Project: Broad Run Expansion
Firm Commitment: 75,000 Dth/d
Project: Broad Run Flexibility
Firm Commitment: 590,000 MMbtu/d
Project: Rover Pipeline LLC
Firm Commitment: 800 Mmcf/d
Project: Mariner East 2
Firm Commitment: 61,500 Bbls/d
COST: 220 $MM
VOLUMES: 75 Mmcf/d
COST: 30 $MM
VOLUMES: 9 Mmcfe/d
ACRES: 4100 Acres
DENVER, Jan. 20, 2021 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its fourth quarter 2020 earnings release on Wednesday, February 17, 2021 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, February 18, 2021 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Thursday, February 25, 2021 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13714534. To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 25, 2021 at 9:00 am MT.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. Antero Resources is one of the most integrated natural gas producers in the U.S. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Jan. 11, 2021 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources") announced today the pricing of its private placement to eligible purchasers of $700 million in aggregate principal amount of 7.625% senior unsecured notes due 2029 at par (the "Notes"). The offering is expected to close on January 26, 2021, subject to customary closing conditions.
Antero Resources estimates that it will receive net proceeds of approximately $692 million, after deducting the initial purchasers' discounts and estimated expenses. Antero Resources intends to use a portion of the net proceeds from the offering to fund the redemption of all $311 million aggregate principal amount of its 5.125% senior notes due 2022 (the "2022 Notes") not previously called for redemption at par plus accrued interest and to use the remaining net proceeds to repay borrowings under its credit facility. The redemption of all 2022 Notes not previously called for redemption is conditioned on the completion of the offering of the Notes. The offering of the Notes is not contingent upon the completion of such redemption.
The Notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes will be offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act and outside the United States pursuant to Regulation S under the Securities Act.
This press release is neither an offer to sell nor a solicitation of an offer to buy the Notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the Notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful. This press release shall not constitute a notice of redemption of the 2022 Notes.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as statements regarding the proposed offering and the intended use of proceeds, including to fund the redemption of all 2022 Notes not previously called for redemption, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequently filed Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Jan. 11, 2021 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources") announced today that, subject to market conditions, it intends to offer $500 million in aggregate principal amount of senior unsecured notes due 2029 (the "Notes") in a private placement to eligible purchasers.
Antero Resources intends to use a portion of the net proceeds from the offering to fund the redemption of all $310.5 million aggregate principal amount of its 5.125% senior notes due 2022 (the "2022 Notes") not previously called for redemption at par plus accrued interest and to use the remaining net proceeds to repay borrowings under its credit facility. The redemption of all 2022 Notes not previously called for redemption is expected to be conditioned on the completion of the offering of the Notes. The offering of the Notes is not contingent upon the completion of such redemption.
The Notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes will be offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act and outside the United States pursuant to Regulation S under the Securities Act.
This press release is neither an offer to sell nor a solicitation of an offer to buy the Notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the Notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful. This press release shall not constitute a notice of redemption of the 2022 Notes.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as statements regarding the proposed offering and the intended use of proceeds, including to fund the redemption of all 2022 Notes not previously called for redemption, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequently filed Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Dec. 17, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources") announced today the pricing of its private placement to eligible purchasers of $500 million in aggregate principal amount of 8.375% senior unsecured notes due 2026 at par (the "Notes"). The offering is expected to close on January 4, 2021, subject to customary closing conditions.
Antero Resources estimates that it will receive net proceeds of approximately $494 million, after deducting the initial purchasers' discounts and estimated expenses. Antero Resources intends to use a portion of the net proceeds from the offering to fund the redemption of $350 million aggregate principal amount of its 5.125% senior notes due 2022 (the "2022 Notes") at par plus accrued interest and to use the remaining net proceeds to repay borrowings under its credit facility. The partial redemption of the 2022 Notes is conditioned on the completion of the offering of the Notes. The offering of the Notes is not contingent upon the completion of such redemption.
The Notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes will be offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act and outside the United States pursuant to Regulation S under the Securities Act.
This press release is neither an offer to sell nor a solicitation of an offer to buy the Notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the Notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful. This press release shall not constitute a notice of redemption of the 2022 Notes.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as statements regarding the proposed offering and the intended use of proceeds, including to fund the partial redemption of the 2022 Notes, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequently filed Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Oct. 14, 2020 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its third quarter 2020 earnings release on Wednesday, October 28, 2020 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, October 29, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Thursday, November 5, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13703919. To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, November 5, 2020 at 9:00 am MT.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Oct. 5, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced the publication of its 2019 Corporate Sustainability Report. The report details Antero's ongoing commitment to environmental excellence, strong governance, safe operations and the communities in which it operates. The full report is available at www.anteroresources.com/sustainability/founders-message.
Report Highlights:
2025 Environmental Goals:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, "Our outstanding ESG performance exemplifies our unwavering and long-standing commitment to make every effort to do the right thing, take accountability for our actions and maintain our position as a world-class sustainable energy producer, partner and employer of choice. We are dedicated to adapting and leading, and operating ethically and responsibly. This commitment is evident in our performance and culture as we proactively care for our employees, contractors, community and the environment."
Glen Warren, CFO and President of Antero Resources said, "Natural gas is key to the energy transition and our ability to address the risks associated with climate change. As the lightest and least greenhouse gas (GHG) intensive hydrocarbon, natural gas is just as important as wind and solar in the energy mix that allows the U.S. and the globe to transition to a lower carbon future. Natural gas is a transition fuel and part of the solution. Investors, creditors, the communities in which we operate, and employees can be stakeholders in a hydrocarbon business that is natural gas focused while at the same time meeting high ESG standards."
Presentation
The Company posted its 2019 Corporate Sustainability Report presentation on its website at www.anteroresources.com/sustainability/founders-message. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Antero Resources is an independent natural gas and natural gas liquids company engaged in the acquisition, development and production of unconventional properties located in the Appalachian Basin in West Virginia and Ohio. In conjunction with its affiliate, Antero Midstream (NYSE: AM), Antero is one of the most integrated natural gas producers in the U.S. The Company's website is located at www.anteroresources.com.
While Antero Resources believes all historical calculations presented in this release and the Corporate Sustainability Report were completed consistent with current industry standards, the numbers provided have not been audited by a third party audit firm.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding our strategy, future operations and forecasts of future events, including our environmental goals, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. These forward-looking statements are management's belief, based on currently available information, as to the outcome and timing of future events. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
In addition, many of the standards and metrics used in preparing this release and the Corporate Sustainability Report continue to evolve and are based on management expectations and assumptions believed to be reasonable at the time of preparation but should not be considered guarantees. The standards and metrics used, and the expectations and assumptions they are based on, have not been verified by any third party.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health event, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity and the other risks described under the heading " Risk Factors" in Antero Resources' filings with the SEC.
This release and the Corporate Sustainability Report contain statements based on hypothetical or severely adverse scenarios and assumptions, and these statements should not necessarily be viewed as being representative of current or actual risk or forecasts of expected risk. While future events discussed in this release or the report may be significant, any significance should not be read as necessarily rising to the level of materiality of certain disclosures included in Antero Resources' SEC filings.
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SOURCE Antero Resources Corporation
DENVER, Aug. 24, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced that as of 5:00 p.m., New York City time, on August 24, 2020 (the "Dutch Auction Early Tender Deadline"), $88,389,000 aggregate principal amount of the Company's 5.125% Senior Notes due 2022 (the "2022 Notes") and $95,661,000 aggregate principal amount of the Company's 5.625% Senior Notes due 2023 (the "2023 Notes" and, together with the 2022 Notes, the "Dutch Auction Notes") had been tendered and not withdrawn prior to the Dutch Auction Early Tender Deadline, in accordance with the previously announced cash tender offers for the Dutch Auction Notes (the "Dutch Auction Offers") on the terms and subject to the conditions set forth in the Offer to Purchase, dated as of August 11, 2020 (as it may be amended and supplemented from time to time, the "Offer to Purchase"). The Company intends to accept for purchase all such notes (the "Accepted Notes") and to make payment for Accepted Notes on August 25, 2020.
Select terms of the early tender results and pricing of the Dutch Auction Offers are described in the table below:
Dutch Auction | CUSIP | Outstanding | Principal Amount | Base Price(3) | Clearing | Dutch Auction |
5.125% Senior Notes | 03674X AC0 / | $ 756,030,000 | $ 88,389,000 | $ 800.00 | $ 60.00 | $ 860.00 |
5.625% Senior Notes | 03674X AF3 / | $ 705,641,000 | $ 95,661,000 | $ 720.00 | $ 60.00 | $ 780.00 |
(1) | No representation is made as to the correctness or accuracy of the CUSIP numbers or ISIN listed in this release or printed on the Dutch Auction Notes. They are provided solely for the convenience of holders. |
(2) | As of the date of this release. |
(3) | Per $1,000 principal amount of Dutch Auction Notes accepted for purchase. Includes the Dutch Auction Early Tender Payment of $30.00. |
(4) | As defined in the Offer to Purchase. |
(5) | Per $1,000 principal amount of Dutch Auction Notes accepted for purchase. Includes the Dutch Auction Early Tender Payment of $30.00. Holders whose Dutch Auction Notes are validly tendered in the Dutch Auction Offers after the Dutch Auction Early Tender Deadline but by the Dutch Auction Expiration Date (and not validly withdrawn) and accepted for purchase in the Dutch Auction Offers will be entitled to receive the Dutch Auction Offer Consideration, which is equal to the Dutch Auction Total Consideration, less the $30.00 Dutch Auction Early Tender Payment. Holders whose Dutch Auction Notes are accepted for purchase will also receive accrued and unpaid interest from the applicable last interest payment date to, but not including, the applicable settlement date with respect to the Dutch Auction Notes accepted for purchase. |
The deadline for holders to validly withdraw tenders of Dutch Auction Notes (unless otherwise required by applicable law) was 5:00 p.m., New York City time, on August 24, 2020, and was not extended. The Dutch Auction Offers will expire at 11:59 p.m., New York City time, on September 8, 2020, unless extended by Antero in its sole discretion (such date and time, as the same may be extended, the "Dutch Auction Expiration Date"). Pursuant to the Offer to Purchase, holders of Dutch Auction Notes may still tender their Dutch Auction Notes by the Dutch Auction Expiration Date, but will be entitled to receive only the Dutch Auction Offer Consideration, which is equal to the Dutch Auction Total Consideration set forth in the table above, less the $30.00 Dutch Auction Early Tender Payment.
As previously announced, $191,566,000 principal amount of the Company's outstanding 5.375% Senior Notes due 2021 (the "2021 Notes") were tendered pursuant to the Company's cash tender offer for any and all of its outstanding 2021 Notes (the "Any and All Offer" and, together with the Dutch Auction Offers, the "Offers" and, the Dutch Auction Notes, collectively with the 2021 Notes, the "Notes"), which amount included $18,480,000 principal amount of 2021 Notes tendered pursuant to guaranteed delivery procedures (the "Guaranteed Delivery Notes"). Because holders owning approximately $9 million aggregate principal amount of Guaranteed Delivery Notes did not perform the delivery requirements under the guaranteed delivery procedures, Antero accepted for purchase $182,725,000 aggregate principal amount of 2021 Notes.
Between the Dutch Auction Notes tendered by the Dutch Auction Early Tender Deadline and 2021 Notes repurchased by the Company in the Any and All Offer, the Company will have repurchased an aggregate $366,775,000 notional amount of senior notes in the Offers at a 10% weighted average discount, reducing total debt by $37 million.
Additional Information
The dealer manager for the Offers is J.P. Morgan Securities LLC and the co-dealer managers for the Offers are BMO Capital Markets Corp. and Citigroup Global Markets Inc. Any questions regarding the terms of the Offers should be directed to J.P. Morgan at (toll-free) (866) 834-2045 or (collect) (866) 834-2045. The depositary and information agent is IPREO LLC. Any questions regarding procedures for tendering Notes or requests for copies of the Offer to Purchase, the Letter of Transmittal or the Notice of Guaranteed Delivery should be directed to the information agent for the Offers, IPREO LLC, at (888) 593-9546 (toll-free), (212) 849-3880 (all others) or ipreo-tenderoffer@ihsmarkit.com. Copies of such documents are also available at the following web address: https://www.debtdomain.com/public/antero/index.html.
This press release is for informational purposes only. This press release is not an offer to purchase or a solicitation of an offer to purchase with respect to any Notes or any other securities. The Offers are being made pursuant to an Offer to Purchase, a related Letter of Transmittal and a related Notice of Guaranteed Delivery, each dated August 11, 2020, which set forth the complete terms and conditions of the Offers. The Offers are not being made to holders of Notes in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction. In any jurisdiction in which the securities laws or blue sky laws require the Offers to be made by a licensed broker or dealer, the Offers will be deemed to be made on behalf of the Company by the Dealer Managers, or one or more registered brokers or dealers that are licensed under the laws of such jurisdiction. None of the Company, the Dealer Managers, the Depositary or the Information Agent makes any recommendation as to whether holders should tender or refrain from tendering their Notes. Holders must make their own decision as to whether to tender or refrain from tendering any or all of such holder's Notes, and how much they should tender.
Antero is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as Antero's ability to successfully consummate the Offers and the terms thereof, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequent Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Aug. 18, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today the pricing of its private placement to eligible purchasers of $250 million in aggregate principal amount of 4.25% convertible senior notes due 2026 (the "Notes"). In connection with the offering of the Notes, the Company granted the initial purchasers of the Notes an option, which is exercisable within 30 days, to purchase up to an additional $50 million aggregate principal amount of the Notes. The offering is expected to close on August 21, 2020, subject to the satisfaction of customary closing conditions.
The Notes will be senior, unsecured obligations of the Company and will accrue interest at a rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, beginning on March 1, 2021. The Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, noteholders will have the right to convert their Notes only upon the occurrence of certain events. From and after May 1, 2026, noteholders may convert their Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. The Company will settle conversions by paying or delivering, as applicable, cash, shares of its common stock or a combination thereof, at the Company's election. The initial conversion rate is 230.2026 shares of common stock per $1,000 principal amount of Notes, which represents an initial conversion price of approximately $4.34 per share of common stock. The initial conversion price represents a premium of approximately 20% over the last reported sale price of the Company's common stock on the New York Stock Exchange of $3.62 per share on August 18, 2020. The conversion rate and conversion price will be subject to adjustment upon the occurrence of certain events.
The Notes will be redeemable, in whole or in part, for cash at the Company's option at any time, and from time to time, on or after March 1, 2024 and before the maturity date, but only if the last reported sale price per share of the Company's common stock exceeds 130% of the conversion price then in effect for at least 20 trading days (whether or not consecutive), including the trading date immediately preceding the date on which the Company provides notice of redemption, during the 30 consecutive trading days ending on, and including, the trading day immediately before the date on which the Company provides the related notice of redemption, at a cash redemption price equal to the principal amount of the Notes to be redeemed, plus accrued and unpaid interest.
The Notes will be fully and unconditionally guaranteed, on a senior, unsecured basis, by the Company's subsidiaries that currently or in the future guarantee the Company's existing senior notes.
If a "fundamental change" (as defined in the indenture for the Notes) occurs, then noteholders may require the Company to repurchase their Notes for cash. The repurchase price will be equal to the principal amount of the Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the applicable repurchase date.
Antero Resources estimates that it will receive net proceeds of approximately $242 million, after deducting the initial purchasers' discounts and estimated expenses (assuming no exercise of the initial purchasers' option to purchase additional Notes). The Company intends to use the net proceeds from the offering (including any additional net proceeds if the initial purchasers exercise their option to purchase additional Notes) to repay indebtedness under the Company's credit facility, which amounts may be reborrowed at any time, including to fund the pending tender offers.
This press release is neither an offer to sell nor a solicitation of an offer to buy any securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, any securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
The Notes to be offered and any shares of the Company's common stock issuable upon conversion of the Notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes will be offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as Antero Resources' ability to successfully consummate the offering of the Notes, the terms and conditions of the Notes and the Company's expected use of proceeds from the offering of the Notes, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and its subsequently filed Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Aug. 18, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today that, subject to market and other conditions, it intends to offer $250 million in aggregate principal amount of convertible senior notes due 2026 (the "Notes") in a private placement to eligible purchasers. The Company also expects to grant the initial purchasers of the Notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the Notes.
The Notes will be senior, unsecured obligations of the Company, accrue interest payable semi-annually in arrears and mature on September 1, 2026, unless earlier repurchased, redeemed or converted. The Notes will be convertible into cash, shares of the Company's common stock or a combination thereof, at the Company's election. The Notes will be fully and unconditionally guaranteed, on a senior, unsecured basis, by the Company's subsidiaries that currently or in the future guarantee the Company's existing senior notes. The interest rate, initial conversion rate and other terms of the Notes are expected to be determined at the time of pricing of the offering.
The Company intends to use the net proceeds from the offering (including any additional net proceeds if the initial purchasers exercise their option to purchase additional Notes) to repay indebtedness under the Company's credit facility, which amounts may be reborrowed at any time, including to fund the pending senior note tender offers.
This press release is neither an offer to sell nor a solicitation of an offer to buy any securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, any securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
The Notes to be offered and any shares of the Company's common stock issuable upon conversion of the Notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes will be offered only to persons reasonably believed to be qualified institutional buyers in reliance on Rule 144A under the Securities Act.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as Antero Resources' ability to successfully consummate the offering of the Notes, the terms and conditions of the Notes and the Company's expected use of proceeds from the offering of the Notes, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and its subsequently filed Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Aug. 17, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") announced today that, as of 5:00 p.m., New York City time, on August 17, 2020, $191,566,000 principal amount of the Company's outstanding 5.375% Senior Notes due 2021 (the "2021 Notes") have been tendered and accepted for purchase (the "Tendered Notes") pursuant to the previously announced cash tender offer (the "Any and All Offer") on the terms and subject to the conditions set forth in the Offer to Purchase, dated as of August 11, 2020 (as it may be amended or supplemented from time to time, the "Offer to Purchase"). This amount includes $18,480,000 principal amount of 2021 Notes tendered pursuant to the guaranteed delivery procedures described in the Offer to Purchase and the related notice of guaranteed delivery provided in connection with the Any and All Offer, which remain subject to the holders' performance of the delivery requirements under such procedures (the "Guaranteed Delivery Notes").
Holders of 2021 Notes that have been accepted for purchase will receive the total consideration of $980.00 for each $1,000 principal amount of 2021 Notes purchased pursuant to the Any and All Offer, plus accrued and unpaid interest thereon from the last interest payment date to, but not including, August 18, 2020. Antero expects to make payment for the Tendered Notes (other than the Guaranteed Delivery Notes) on August 18, 2020 and to make payment for the Guaranteed Delivery Notes delivered pursuant to the guaranteed delivery procedures on August 20, 2020.
Based on the results of the Any and All Offer, the maximum purchase price, excluding accrued interest, available to purchase the Company's outstanding 5.125% Senior Notes due 2022 and 5.625% Senior Notes due 2023 (collectively, the "Dutch Auction Notes" and, with the 2021 Notes, the "Notes") subject to the previously announced cash tender offers (the "Dutch Auction Offers" and, collectively with the Any and All Offer, the "Offers") will be $250,000,000, which was the maximum amount available for the Dutch Auction Offers regardless of the principal amount of Tendered Notes. The "Dutch Auction Cap" will be a principal amount of Dutch Auction Notes that can be purchased with such maximum purchase price.
The Dutch Auction Offers are scheduled to expire at 11:59 p.m., New York City time, on Tuesday, September 8, 2020, unless extended (the "Dutch Auction Expiration Date"). As more fully described in the Offer to Purchase, holders of Dutch Auction Notes who validly tender (and do not validly withdraw) their Dutch Auction Notes at or prior to 5:00 p.m., New York City time, on Monday, August 24, 2020, unless extended (the "Dutch Auction Early Tender Deadline"), will receive the applicable "Dutch Auction Total Consideration" (as defined in the Offer to Purchase), including a "Dutch Auction Early Tender Payment" of $30.00 per $1,000 principal amount of Dutch Auction Notes. Holders who validly tender their Dutch Auction Notes after the Dutch Auction Early Tender Deadline will not be eligible to receive the Dutch Auction Early Tender Payment.
Information relating to the Dutch Auction Notes and Dutch Auction Offers is set forth in the table below:
Dutch Auction Notes | CUSIP | Outstanding | Total | |||
5.125% Senior Notes due 2022......... | 03674X AC0 / | $ 756,030,000 | $ 800.00 – 860.00 | |||
5.625% Senior Notes due 2023......... | 03674X AF3 / | $ 705,641,000 | $ 720.00 – 780.00 |
(1) | No representation is made as to the correctness or accuracy of the CUSIP numbers or ISIN listed in this release or printed on the Dutch Auction Notes. They are provided solely for the convenience of holders. |
(2) | As of the date of this release. |
(3) | Per $1,000 principal amount of Dutch Auction Notes accepted for purchase. Includes the Dutch Auction Early Tender Payment. Holders whose Dutch Auction Notes are validly tendered in the Dutch Auction Offers after the Dutch Auction Early Tender Deadline but by the Dutch Auction Expiration Date (and not validly withdrawn) and accepted for purchase in the Dutch Auction Offers will receive the Dutch Auction Offer Consideration (as defined in the Offer to Purchase), which does not include the Dutch Auction Early Tender Payment. Holders will also receive accrued and unpaid interest from the applicable last interest payment date to, but not including, the applicable settlement date with respect to the Dutch Auction Notes accepted for purchase. |
As previously announced, and as more fully described in the Offer to Purchase, the "Clearing Premium" will be determined pursuant to a modified "Dutch Auction" by consideration of the "bid price" specified by each holder that tenders Dutch Auction Notes prior to the Dutch Auction Early Tender Deadline. The bid premiums of Dutch Auction Notes validly tendered after the Dutch Auction Early Tender Deadline will not be used in determining the Clearing Premium. The Clearing Premium for the Dutch Auction Offers will be the lowest single bid premium (the amount by which bid price exceeds the "Base Price," which is also equal to the minimum "bid price") at which Antero will be able to purchase Dutch Auction Notes in an aggregate principal amount equal to the Dutch Auction Cap. If the aggregate amount of Dutch Auction Notes validly tendered (and not validly withdrawn) at or below the Clearing Premium would cause Antero to purchase more than the Dutch Auction Cap, then holders of Dutch Auction Notes tendered at the Clearing Premium will be subject to proration as described in the Offer to Purchase.
Additional Information
The dealer manager for the Offers is J.P. Morgan Securities LLC and the co-dealer managers for the Offers are BMO Capital Markets Corp. and Citigroup Global Markets Inc. Any questions regarding the terms of the Offers should be directed to J.P. Morgan at (toll-free) (866) 834-2045 or (collect) (866) 834-2045. The depositary and information agent is IPREO LLC. Any questions regarding procedures for tendering Notes or requests for copies of the Offer to Purchase, the Letter of Transmittal or the Notice of Guaranteed Delivery should be directed to the information agent for the Offers, IPREO LLC, at (888) 593-9546 (toll-free), (212) 849-3880 (all others) or ipreo-tenderoffer@ihsmarkit.com. Copies of such documents are also available at the following web address: https://www.debtdomain.com/public/antero/index.html.
This press release is for informational purposes only. This press release is not an offer to purchase or a solicitation of an offer to purchase with respect to any Notes or any other securities. The Offers are being made pursuant to an Offer to Purchase, a related Letter of Transmittal and a related Notice of Guaranteed Delivery, each dated August 11, 2020, which set forth the complete terms and conditions of the Offers. The Offers are not being made to holders of Notes in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction. In any jurisdiction in which the securities laws or blue sky laws require the Offers to be made by a licensed broker or dealer, the Offers will be deemed to be made on behalf of the Company by the Dealer Managers, or one or more registered brokers or dealers that are licensed under the laws of such jurisdiction. None of the Company, the Dealer Managers, the Depositary or the Information Agent makes any recommendation as to whether holders should tender or refrain from tendering their Notes. Holders must make their own decision as to whether to tender or refrain from tendering any or all of such Holder's Dutch Auction Notes, and how much they should tender or at what bid price any Dutch Auction Notes should be tendered.
Antero is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as Antero's ability to successfully consummate the Offers and the terms thereof, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequent Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Aug. 11, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced today that it has commenced cash tender offers (the "Offers") to purchase (i) any and all of the Company's outstanding 5.375% Senior Notes due 2021 (such notes, the "Any and All Notes" and, such offer, the "Any and All Offer") and (ii) up to the Dutch Auction Cap (as defined below) of the Company's outstanding 5.125% Senior Notes due 2022 the ("2022 Notes") and the Company's 5.625% Senior Notes due 2023 (the "2023 Notes" and, together with the 2022 Notes, the "Dutch Auction Notes" and, such offers, the "Dutch Auction Offers" and, the Dutch Auction Notes together with the Any and All Notes, the "Notes"), in each case, on the terms and subject to the conditions set forth in the Offer to Purchase, dated the date hereof (as it may be amended or supplemented from time to time, the "Offer to Purchase").
The Dutch Auction Cap will be a principal amount of 2022 Notes and/or 2023 Notes that could be purchased with a maximum purchase price, excluding accrued interest, equal to $525,000,000 less the aggregate amount paid by the Company to purchase the Any and All Notes (other than accrued interest) in the Any and All Offer, but in no event more than $250,000,000 (such amount, the "Dutch Auction Cap"). The Any and All Offer is scheduled to expire at 5:00 p.m., New York City time, on Monday, August 17, 2020, unless extended (such time and date, as the same may be extended, the "Any and All Expiration Date"). The Dutch Auction Offers are scheduled to expire at 11:59 p.m., New York City time, on Tuesday, September 8, 2020, unless extended (such time and date, as the same may be extended, the "Dutch Auction Expiration Date").
Information relating to the Notes and the Offers is set forth in the table below:
Title of Notes | CUSIP | Outstanding | Total | |||
Any and All Notes: | ||||||
5.375% Senior Notes due 2021 | 03674P AL7 / | $ 500,202,000 | $ 980.00 | |||
Dutch Auction Notes: | ||||||
5.125% Senior Notes due 2022 | 03674X AC0 / | $ 756,030,000 | $ 800.00 – $860.00 | |||
5.625% Senior Notes due 2023 | 03674X AF3 / | $ 705,641,000 | $ 720.00 – $780.00 |
________________ | |
(1) | No representation is made as to the correctness or accuracy of the CUSIP numbers or ISIN listed in this release or printed on the Notes. They are provided solely for the convenience of holders. |
(2) | As of the date of this release. |
(3) | Per $1,000 principal amount of Notes accepted for purchase, including the Dutch Auction Early Tender Payment of $30.00 for the Dutch Auction Notes. Holders whose Dutch Auction Notes are validly tendered in the Dutch Auction Offers after the Dutch Auction Early Tender Deadline (as defined below) but by the Dutch Auction Expiration Date (and not validly withdrawn) and accepted for purchase in the Dutch Auction Offers will receive the Dutch Auction Offer Consideration (as defined below), which does not include the Dutch Auction Early Tender Payment. There is no early tender payment for the Any and All Notes tendered in the Any and All Offer. Holders will also receive accrued and unpaid interest from the applicable last interest payment date to, but not including, the applicable settlement date with respect to the Notes accepted for purchase. |
Holders of Any and All Notes who validly tender (and do not validly withdraw) their Any and All Notes at or prior to 5:00 p.m., New York City time on Monday, August 17, 2020, unless extended, or who comply with the guaranteed delivery procedures in accordance with the instructions described in the Offer to Purchase, will receive total consideration of $980.00 per $1,000 principal amount of Any and All Notes purchased pursuant to the Offers. There will not be an early tender payment for the Any and All Notes.
The total consideration payable for each $1,000 principal amount of Dutch Auction Notes will be determined based on a modified "Dutch Auction" procedure. Holders of Dutch Auction Notes who validly tender (and do not validly withdraw) their Dutch Auction Notes at or prior to 5:00 p.m., New York City time, on Monday, August 24, 2020, unless extended (the "Dutch Auction Early Tender Deadline"), will receive the applicable "Dutch Auction Total Consideration," including a "Dutch Auction Early Tender Payment" of $30.00 per $1,000 principal amount of Dutch Auction Notes. Holders who validly tender their Dutch Auction Notes after the Dutch Auction Early Tender Deadline will not be eligible to receive the Dutch Auction Early Tender Payment.
As more fully described in the Offer to Purchase, the Dutch Auction Total Consideration for each $1,000 principal amount of the Dutch Auction Notes validly tendered (and not validly withdrawn) at or prior to the Dutch Auction Early Tender Deadline and accepted for purchase will be equal to the sum of: (1) the "Base Price" for the Dutch Auction Notes, which is also equal to the minimum "bid price," and (2) the "Clearing Premium," which will be determined pursuant to a modified "Dutch Auction" by consideration of the "bid price" specified by each holder that tenders Dutch Auction Notes prior to the Dutch Auction Early Tender Deadline pursuant to the Offers. The bid premiums of Dutch Auction Notes validly tendered after the Dutch Auction Early Tender Deadline will not be used in determining the Clearing Premium. The bid price for tendered Dutch Auction Notes represents the minimum consideration a holder is willing to receive for those Dutch Auction Notes and must fall within the acceptable bid price range specified in the table above and be in increments of $5.00.
The total consideration for each $1,000 principal amount of the Dutch Auction Notes validly tendered (and not validly withdrawn) after the Dutch Auction Early Tender Deadline and at or prior to the Dutch Auction Expiration Date and accepted for purchase will consist of the Dutch Auction Total Consideration less the Dutch Auction Early Tender Payment (the "Dutch Auction Offer Consideration").
As more fully described in the Offer to Purchase, the Clearing Premium for the Dutch Auction Offers will be the lowest single bid premium (the amount by which bid price exceeds the Base Price) at which the Company will be able to purchase Dutch Auction Notes in an aggregate principal amount equal to the Dutch Auction Cap. If the aggregate amount of Dutch Auction Notes validly tendered (and not validly withdrawn) at or below the Clearing Premium would cause the Company to purchase more than the Dutch Auction Cap for the Dutch Auction Offers, then holders of Dutch Auction Notes tendered at the Clearing Premium will be subject to proration as described in the Offer to Purchase.
In addition, the Company will pay accrued and unpaid interest on all Notes tendered and accepted for payment in the Offers from the last interest payment date to, but not including, the applicable settlement date.
Tendered Any and All Notes may be validly withdrawn at any time by the Any and All Expiration Date, but not thereafter unless otherwise required by applicable law. Tendered Dutch Auction Notes may be validly withdrawn at any time prior to 5:00 p.m., New York City time, on Monday, August 24, 2020, unless extended (the "Dutch Auction Withdrawal Deadline"), but not thereafter unless otherwise required by applicable law.
The Company reserves the right, in its sole discretion, to increase the Dutch Auction Cap for the Dutch Auction Notes. If the Company increases the Dutch Action Cap, it does not currently intend to extend the Dutch Auction Withdrawal Deadline or otherwise reinstate withdrawal rights, subject to applicable law.
Consummation of the Offers is subject to the satisfaction or waiver of certain conditions, which are more fully described in the Offer to Purchase. If any of the conditions are not satisfied, the Company may terminate the Offers and return tendered Notes. The Company has the right to waive any conditions with respect to the Notes and to consummate the Offers. In addition, the Company has the right, in its sole discretion, to terminate the Offers at any time, subject to applicable law. The Company has the right, in its sole discretion, to amend, extend or terminate an Offer without amending, extending or terminating any other Offer.
Additional Information
The dealer manager for the Offers is J.P. Morgan Securities LLC and the co-dealer managers for the Offers are BMO Capital Markets Corp. and Citigroup Global Markets Inc. Any questions regarding the terms of the Offers should be directed to J.P. Morgan at (toll-free) (866) 834-2045 or (collect) (866) 834-2045. The depositary and information agent is IPREO LLC. Any questions regarding procedures for tendering Notes or requests for copies of the Offer to Purchase, the Letter of Transmittal or the Notice of Guaranteed Delivery should be directed to the information agent for the Offers, IPREO LLC, at (888) 593-9546 (toll-free), (212) 849-3880 (all others) or ipreo-tenderoffer@ihsmarkit.com. Copies of such documents are also available at the following web address: https://www.debtdomain.com/public/antero/index.html.
This press release is for informational purposes only. This press release is not an offer to purchase or a solicitation of an offer to purchase with respect to any Notes or any other securities. The Offers are being made pursuant to an Offer to Purchase, a related Letter of Transmittal and a related Notice of Guaranteed Delivery, each dated the date hereof, which set forth the complete terms and conditions of the Offers. The Offers are not being made to holders of Notes in any jurisdiction in which the making or acceptance thereof would not be in compliance with the securities, blue sky or other laws of such jurisdiction. In any jurisdiction in which the securities laws or blue sky laws require the Offers to be made by a licensed broker or dealer, the Offers will be deemed to be made on behalf of the Company by the Dealer Managers, or one or more registered brokers or dealers that are licensed under the laws of such jurisdiction. None of the Company, the Dealer Managers, the Depositary or the Information Agent makes any recommendation as to whether holders should tender or refrain from tendering their Notes. Holders must make their own decision as to whether to tender or refrain from tendering any or all of such Holder's Notes and, how much they should tender or, in the case of the Dutch Auction Offers, at what bid price any Dutch Auction Notes should be tendered.
Antero is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as Antero's ability to successfully consummate the Offers and the terms thereof, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2019 and in its subsequent Quarterly Reports on Form 10-Q.
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SOURCE Antero Resources Corporation
DENVER, Aug. 11, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced a volumetric production payment ("VPP") transaction with an affiliate of J.P. Morgan for cash proceeds of $220 million. The Company also announced today in a separate press release the commencement of cash tender offers for its 2021, 2022 and 2023 senior notes for $525 million. Pro forma for application of the VPP proceeds to repay outstanding revolver borrowings, but prior to the completion of the tender offers, the Company had approximately $715 million drawn on its revolving credit facility and $1.2 billion in liquidity as of June 30, 2020.
Release highlights:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, "The VPP transaction brings asset sales to date to the low end of the asset sale target range announced in December of 2019. The ability to monetize $751 million of assets in such a challenging market is a testament to the quality of Antero's substantial producing properties and acreage."
Glen Warren, CFO and President of Antero Resources said, "Pro forma for the VPP sale and assuming $525 million of bonds are tendered and repurchased, Antero will have reduced near term bond maturities by over $1.4 billion since the fourth quarter of 2019. Future contingent payments expected to be received from our previously announced ORRI counterparty and expected free cash flow during the second half of 2020 will be used to further reduce debt. We will continue to pursue additional asset sale opportunities and plan to use any future proceeds for debt retirement."
Presentation
The Company posted a new strategic update presentation on its website at www.anteroresources.com. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future production targets, future earnings, leverage targets and debt repayment, asset monetization opportunities and pricing, future financial position, , future receipt of contingent consideration and the results of the tender offers are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health event, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.
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SOURCE Antero Resources Corporation
DENVER, July 29, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced its second quarter 2020 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.
Highlights Include:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, "We have made considerable progress towards our $750 to $1 billion asset sale target having closed $531 million of transactions to date. The asset sale proceeds received to date have enabled Antero to reduce total debt by $365 million since the start of the bond repurchase program in the fourth quarter of 2019, capturing a meaningful discount on our outstanding senior notes and significantly addressing our upcoming debt maturities. On the operating front, we continue to see momentum on well cost savings, setting a new quarterly record with an average of 8.7 completion stages per day. We also set a U.S. horizontal well record during the quarter, drilling 11,253 lateral feet in a 24-hour period. These well cost savings helped to deliver our lowest quarterly drilling and completion capital spend since the company's IPO in 2013 and drove well costs to below $700 per lateral foot in May and June. We are incredibly proud of all of our employees who have safely delivered these results despite the ongoing uncertainty and challenges surrounding the COVID-19 pandemic. The combination of a successful asset sale program with repurchasing debt at a discount and significant capital efficiencies have materially improved Antero's credit profile and outlook."
Glen Warren, CFO and President of Antero Resources said, "Over the last nine months we have delivered on our commitment to reduce debt through a combination of asset sales and debt repurchased at a discount. This successful debt repurchase program has resulted in an $888 million reduction in near-term maturities. Further, we have completed 69 of our 105 projected wells for the year and expect drilling and completion capital spend to be substantially lower during the second half of the year. The low capital spend projected for the second half of 2020 is expected to result in over $175 million in Free Cash Flow based on today's strip prices, providing additional liquidity for debt retirement. Longer term, we are committed to maximizing Free Cash Flow and further reducing total debt."
For a discussion of the non-GAAP financial measures including Adjusted EBITDA, Adjusted Net Income, and Free Cash Flow presented on an actual and pro forma basis, please see "Non-GAAP Financial Measures."
Asset Sale Program Update
Since the announcement of the Company's $750 million to $1 billion asset sale target in December 2019, Antero has closed $531 million of transactions. This total includes the sale of $100 million of Antero Midstream common stock in December 2019, the $402 million ORRI transaction announced in June 2020, which includes $102 million of contingent payments that may be earned based on volume thresholds in the third quarter of 2020 and the first quarter of 2021, and the $29 million hedge monetization announced today. Proceeds received to date have been used to repurchase debt at a discount. Pro forma for the hedge monetization and senior note repurchases, Antero had $1.0 billion in liquidity as of June 30, 2020.
Hedge Monetization
As a result of the ORRI transaction and the resulting excess hedges based on expected 2021 net natural gas production, Antero monetized 100,000 MMBtu/d of 2021 natural gas hedges in July for proceeds of $29 million. Pro forma for the hedge monetization, Antero has 2,300,000 MMBtu/d of natural gas hedged in 2021 at $2.77 per MMBtu. Assuming a maintenance level capital plan, approximately 100% of Antero's 2021 expected natural gas production is hedged.
Debt Repurchases
Antero repurchased $279 million notional amount of senior debt from April 1, 2020 through July 24, 2020 at an 18% weighted average discount price. The repurchases were comprised primarily of the 2021 and 2023 senior notes, but also included the 2022 and 2025 senior notes. The repurchases over this time period reduced our total indebtedness by $51 million. Since the commencement of the debt repurchase program in the fourth quarter of 2019, Antero has repurchased $888 million of notional debt at a 19% weighted average discount, reducing our total indebtedness by $171 million and interest expense by $24 million on an annualized basis.
The par value of the 2021 senior notes outstanding have been reduced from $1.0 billion initially to $503 million and the par value of the 2022 senior notes outstanding has been reduced from $1.1 billion to $756 million. The par value of the 2023 and 2025 senior notes outstanding have been reduced from $750 million to $714 million and $600 million to $590 million, respectively. In total, debt repurchases have reduced the total par value of Antero's senior notes outstanding by $888 million as of July 24, 2020.
Second Quarter 2020 Financial Results
For the three months ended June 30, 2020, Antero reported a GAAP net loss of $463 million, or $1.73 per diluted share, compared to a GAAP net income of $42 million, or $0.14 per diluted share, in the prior year period. The decrease compared to the year ago period is attributable to lower commodity pricing. Adjusted Net Loss (non-GAAP measure) was $99 million, or $0.37 per diluted share, compared to Adjusted Net Loss of $76 million during the three months ended June 30, 2019, or $0.25 per diluted share.
Adjusted EBITDAX (non-GAAP measure) was $186 million, a 26% decrease compared to $252 million in the prior year period due to lower commodity pricing. Antero's average realized price after hedges declined 13% from $3.24 per Mcfe in the second quarter of 2019 to $2.81 per Mcfe in the second quarter of 2020.
The following table details the components of average net production and average realized prices for the three months ended June 30, 2020:
Three months ended June 30, 2020 | |||||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane (Bbl/d) | Combined Natural Gas | |||||||||||||
Average Net Production | 2,364 | 11,029 | 131,150 | 50,796 | 3,521 | ||||||||||||
Average Realized Prices | Natural Gas | Oil ($/Bbl) | C3+ NGLs | Ethane ($/Bbl) | Combined Natural Gas | ||||||||||||
Average realized prices before settled derivatives | $ | 1.71 | $ | 8.29 | $ | 15.55 | $ | 5.76 | $ | 1.83 | |||||||
Settled commodity derivatives | 1.08 | 25.18 | 4.68 | (0.10) | 0.98 | ||||||||||||
Average realized prices after settled derivatives | $ | 2.79 | $ | 33.47 | $ | 20.23 | $ | 5.66 | $ | 2.81 | |||||||
NYMEX average price | $ | 1.72 | $ | 27.84 | $ | 1.72 | |||||||||||
Premium / (Differential) to NYMEX | $ | 1.07 | $ | 5.63 | $ | 1.09 |
Net daily natural gas equivalent production in the second quarter averaged 3,521 MMcfe/d, including 192,975 Bbl/d of liquids (67% natural gas by volume). Net production increased 9% from the year ago period and 4% from the prior period.
Antero's average realized C3+ NGL price before hedging was $15.55 per barrel, representing a 46% decrease versus the prior year period. Antero shipped 54% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.04 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 46% of C3+ NGL net production at a $0.12 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 131,150 Bbl/d of net C3+ NGL production was $15.55 per barrel, which was a $0.04 per gallon discount to Mont Belvieu pricing. Based on current strip prices at Mont Belvieu and in the international markets, Antero expects its blended realized C3+ NGL prices in 2020 to average a $0.00 to a $0.05 per gallon premium to Mont Belvieu. Antero expects to sell at least 50% of its C3+ NGL production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.
Three months ended June 30, 2020 | ||||||||
Pricing Point | Net C3+ NGL Production | % by | Premium (Discount) To Mont Belvieu | |||||
Propane / Butane exported on ME2 | Marcus Hook, PA | 70,369 | 54% | $0.04 | ||||
Remaining C3+ NGL volume | Hopedale, OH | 60,781 | 46% | ($0.12) | ||||
Total C3+ NGLs/Blended Premium | 131,150 | 100% | ($0.04) |
All-in cash expense, which includes lease operating, gathering, compression, processing and transportation, production and ad valorem taxes, net marketing, and general and administrative expense (excluding equity-based compensation) was $2.35 per Mcfe in the second quarter, an 8% decrease compared to $2.56 per Mcfe average during the second quarter of 2019. Lease operating expense was $0.08 per Mcfe in the second quarter, a 43% decline from $0.14 per Mcfe in the year ago period driven by a decrease in water handling costs as Antero increased water blending and reuse in completion operations. G&A expense was $0.09 per Mcfe, a 25% decrease from the second quarter of 2019 primarily due to reduced employee headcount and a 9% increase in production. Antero expects all-in cash expense to average $2.25 to $2.35 per Mcfe in 2020 driven by a decrease in net marketing expense during the second half of the year.
Per unit net marketing expense declined to $0.15 per Mcfe in the second quarter compared to $0.25 per Mcfe reported in the prior year period. The decline was driven primarily by higher production volumes during the quarter resulting in less unutilized transportation capacity. Net marketing expense averaged $0.10 per Mcfe in June as production volumes increased significantly during the month. Net marketing expense is expected to average $0.09 to $0.10 per Mcfe during the second half of 2020 as a result of Antero's increase in natural gas production volumes. Full year guidance for net marketing expense remains $0.10 to $0.12 per Mcfe.
Liquids Pricing Update
NGL Prices
C3+ NGL prices during the second quarter were negatively impacted by weak demand for normal butane (nC4), isobutane (iC4), and pentane (C5), all of which are used for gasoline. The demand destruction on gasoline caused by the COVID-19 pandemic forced C5 prices below propane prices for much of April to under $0.40 per gallon. As gasoline demand rebounded in May and June, there has been a notable improvement in C5 pricing and therefore C3+ NGL pricing. The benchmark C5 price in July has been in the range of $0.60 to $0.70 per gallon.
The restart of economic activity in Asia and Europe, coupled with lower LPG production from refineries in the US, Europe, and Asia during the second quarter, provided support for international LPG prices relative to oil. Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane prices through the remainder of 2020 and into 2021.
Condensate Pricing
During the second quarter, condensate differentials to WTI were notably wider as a result of COVID-19 demand destruction at both the Appalachia regional level and national level. To protect against production curtailments and shut-ins due to insufficient storage capacity, Antero expanded its customer base and its condensate storage capacity within the basin. In addition, Antero entered into transactions that required buyers to transport product to more distant markets and storage, which coincided with substantially weakened crack spreads for refined products. To date, Antero has not shut in or curtailed any production from its assets as a result of COVID-19 demand issues and does not expect to shut in any volumes during 2020.
Condensate differentials to WTI expanded to nearly $20/Bbl during the second quarter, but have begun to return to pre-pandemic levels as gasoline demand improved through the summer months. Pre-hedge oil realizations were negatively impacted during the quarter as Antero sold volumes at a material discount to WTI in order to keep from shutting in production volumes. This period of weak condensate demand driven by the pandemic coincided with an active well completion quarter for Antero that brought on large condensate volumes. The negative impact from wider oil differentials was more than offset by the benefit of maintaining full natural gas and NGL volumes. Antero expects its full year 2020 realized oil price differential to be $10.00/Bbl to $12.00/Bbl, as the differential normalizes during the second half of 2020.
COVID-19 Pandemic Developments
As a producer of natural gas, NGLs and oil, Antero Resources is recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic and the communities in which it operates. Antero has continued to operate under these regulations, while taking steps to protect the health and safety of its workers. Antero has implemented protocols to reduce the risk of an outbreak within its field operations, and these protocols have not had an impact on production. A substantial portion of the Company's non-field level employees have transitioned to remote work from home arrangements. Antero has been able to maintain a consistent level of effectiveness, including maintaining day-to-day operations and decision making, and financial reporting systems and internal control over financial reporting. For more information, please see Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.
Second Quarter 2020 Operating Update
Marcellus Shale — Antero placed 44 horizontal Marcellus wells to sales during the second quarter with an average lateral length of 10,757 feet. Nineteen of the 44 new wells have had at least 60 days of reported production data to date and the average 60-day rate per well was 20.2 MMcfe/d, including approximately 922 Bbl/d of liquids, assuming 25% ethane recovery. During the second quarter, Antero achieved a new U.S. horizontal record by drilling 11,253 lateral feet during a 24-hour period. Additionally, Antero's ongoing emphasis on completion efficiencies resulted in a material improvement during the second quarter to 8.7 stages completed per day, a 23% increase from 7.1 stages per day in the prior period, also a company record. During the quarter, Antero set a company record for an entire pad averaging 9.6 stages per day.
These efficiency gains led to average well costs below $700 per lateral foot during the months of May and June, despite only partial vendor cost savings being realized. All-in well costs are expected to average $675 per lateral foot for the second half of 2020 for a 12,000' lateral. Antero currently has one drilling rig and two completion crews running.
Second Quarter 2020 Capital Investment
Antero's drilling and completion capital expenditures for the three months ended June 30, 2020 were $180 million. Through the first half of 2020, Antero has completed 69 of the projected 105 well completions planned for the year. Antero anticipates a decline in capital spending in each subsequent quarter of 2020, reflecting continued efficiencies, service cost deflation and the release of three rigs and two completion crews that occurred during the second quarter of 2020. In addition to capital invested in drilling and completion costs, the Company invested $11 million in land during the second quarter. For a reconciliation of accrued capital expenditures to cash capital expenditures see the table on page 10.
Balance Sheet and Liquidity
As of June 30, 2020, Antero's total debt was $3.5 billion, of which $926 million were borrowings outstanding under the Company's revolving credit facility. Antero has a borrowing base of $2.85 billion with lender commitments that total $2.64 billion. After deducting letters of credit outstanding of $730 million and pro forma for the subsequent hedge monetization and senior note repurchases, the Company had $1.0 billion in available liquidity at June 30, 2020.
Commodity Derivative Positions
Antero has hedged 1.7 Tcf of natural gas at a weighted average index price of $2.71 per MMBtu through 2023 with fixed price swap positions. Antero also has oil and NGL and ethane fixed price swap positions, including oil positions that total 26,000 Bbl/d, NGL positions that total 10,315 Bbl/d and ethane positions that total 24,500 Bbl/d during 2020. As of June 30, 2020, the Company's estimated fair value gain on remaining commodity derivative instruments was $618 million based on strip pricing, a portion of which was realized in the Company's hedge monetization described above.
Please see Antero's Annual Report on Form 10-Q for the quarter ended June 30, 2020, for more information on all commodity derivative positions, including basis swaps and natural gas calls.
The following tables summarize Antero's hedge position as of June 30, 2020:
Fixed price natural gas positions from July 1, 2020 through December 31, 2023 were as follows:
Natural gas | Weighted | |||||
Year ending December 31, 2020: | ||||||
NYMEX ($/MMBtu) | 2,227,500 | $2.87 | ||||
Year ending December 31, 2021: | ||||||
NYMEX ($/MMBtu) (1) | 2,400,000 | $2.80 | ||||
Year ending December 31, 2022: | ||||||
NYMEX ($/MMBtu) | 1,307,500 | $2.44 | ||||
Year ending December 31, 2023: | ||||||
NYMEX ($/MMBtu) | 150,000 | $2.38 |
(1) | Pro forma for the recent hedge monetization, 2021 fixed price natural gas position is 2,300,000 MMBtu/d at $2.77/MMBtu |
C3+ NGL, ethane and oil derivative contract positions from July 1, 2020 through December 31, 2020 were as follows: |
Derivative Contract Type | Liquids | Weighted | Weighted | Weighted | ||
Year ending December 31, 2020: | ||||||
Total Propane (C3) – ARA (Europe) (1) | Fixed swap | 10,315 | $0.55 | $23.10 | ||
Total OPIS Ethane Mt Belvieu | Fixed swap | 24,500 | $0.20 | |||
Total NYMEX Crude Oil (2) | 26,000 | $55.63 | ||||
(1) Net of shipping. Assumes $0.10/gal shipping to ARA. (2) Hedged 20,000 Bbl/d of pentane (C5) at 80% of WTI and hedged the resulting 26,000 Bbl/d of oil- | ||||||
Guidance
All guidance not discussed in this release is unchanged from previously stated guidance.
Consolidation
For the three months and six months ended June 30, 2020, Martica Holdings, LLC ("Martica"), the entity associated with the ORRI transaction, is consolidated in the Company's consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in the Company's unaudited condensed consolidated financial statements. The noncontrolling interest in the Company's unaudited condensed consolidated financial statements for the three and six months ended June 30, 2020 represents the interest in Martica owned by Sixth Street. For more information, please see Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.
Conference Call
A conference call is scheduled on Thursday, July 30, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, August 6, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13703838.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, August 6, 2020 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Basis of Financial Presentation
In connection with the closing of the simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of June 30, 2020, Antero Resources owned 29% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to June 30, 2020, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described herein reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Non-GAAP Financial Measures
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income (Loss), adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (Loss) as an indicator of financial performance. The following tables reconcile net income (loss) to Adjusted Net Income (Loss) (in thousands):
Three months ended June 30, | ||||||||
2019 | 2020 | |||||||
Net income (loss) attributable to Antero Resources Corp | $ | 42,168 | $ | (463,304) | ||||
Commodity derivative fair value (gains) losses | (328,427) | 168,015 | ||||||
Gains on settled commodity derivatives | 44,699 | 313,912 | ||||||
Impairment of oil and gas properties | 130,999 | 37,350 | ||||||
Equity-based compensation | 6,549 | 7,973 | ||||||
Equity in earnings of unconsolidated - AMC | (13,585) | (20,228) | ||||||
Gain on early extinguishment of debt | — | (39,171) | ||||||
(Gain) loss on sale of assets | 951 | — | ||||||
Contract termination and rig stacking | 5,604 | 11,071 | ||||||
Tax effect of reconciling items (1) | 34,914 | (115,047) | ||||||
Adjusted Net Loss | $ | (76,128) | $ | (99,429) | ||||
Fully Diluted Shares Outstanding | 309,062 | 268,386 |
(1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
Per Share Amounts | |||||||
Three months ended June 30, | |||||||
2019 | 2020 | ||||||
Net income (loss) attributable to Antero Resources Corp | $ | 0.14 | (1.73) | ||||
Commodity derivative fair value (gains) losses | (1.06) | 0.63 | |||||
Gains on settled commodity derivatives | 0.14 | 1.17 | |||||
Impairment of oil and gas properties | 0.42 | 0.14 | |||||
Equity-based compensation | 0.02 | 0.03 | |||||
Equity in earnings of unconsolidated - AMC | (0.04) | (0.07) | |||||
Gain on early extinguishment of debt | — | (0.15) | |||||
(Gain) loss on sale of assets | — | — | |||||
Contract termination and rig stacking | 0.02 | 0.04 | |||||
Tax effect of reconciling items (1) | 0.11 | (0.43) | |||||
Adjusted Net Loss | $ | (0.25) | (0.37) |
(1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | June 30, | ||||||
2019 | 2020 | ||||||
AR bank credit facility | $ | 552,000 | 926,000 | ||||
5.375% AR senior notes due 2021 | 952,500 | 516,202 | |||||
5.125% AR senior notes due 2022 | 923,041 | 756,030 | |||||
5.625% AR senior notes due 2023 | 750,000 | 743,690 | |||||
5.000% AR senior notes due 2025 | 600,000 | 590,000 | |||||
Net unamortized premium | 791 | 542 | |||||
Net unamortized debt issuance costs | (19,464) | (14,388) | |||||
Consolidated total debt | $ | 3,758,868 | 3,518,076 | ||||
Less: AR cash and cash equivalents | — | — | |||||
Net Debt | $ | 3,758,868 | 3,518,076 |
Free Cash Flow
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash flow from operating, investing, or financing activities, as an indicator of cash flow, or as a measure of liquidity. The Company defines Free Cash Flow as Cash Flow from Operations, less drilling and completion capital and leasehold capital plus earnout payments.
The Company has not provided projected Cash Flow from Operations or a reconciliation of Free Cash Flow to projected Cash Flow from Operations, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Cash Flow from Operations for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts. Targeted 2020 Free Cash Flow is based on current strip pricing and assumes that dividends from Antero Midstream remain flat for the year for aggregate annual dividends from Antero Midstream of $171 million in 2020. Antero Midstream previously announced that in light of the uncertain conditions impacting the energy industry, Antero Midstream will continue to evaluate its capital budget as well as the appropriate amount of capital that is returned to shareholders through dividends and share repurchases in order to maintain its financial profile.
Free Cash Flow is a useful indicator of the Company's ability to internally fund its activities and to service or incur additional debt. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), adjusted for certain items detailed below.
Through March 12, 2019, the financial results of Antero Midstream Partners were included in our consolidated results. Effective March 13, 2019, we no longer consolidate Antero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting. Adjusted EBITDAX includes distributions received with respect to limited partner interests in Antero Midstream Partners common units through March 12, 2019.
Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.
The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our unaudited condensed consolidated statements of cash flows, in each case, for the three and six months ended June 30, 2019 and 2020. Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.
Three months ended June 30, | |||||||
(in thousands) | 2019 | 2020 | |||||
Reconciliation of net income (loss) to Adjusted EBITDAX: | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 42,168 | (463,304) | ||||
Net loss and comprehensive loss attributable to noncontrolling interests | — | 236 | |||||
Depletion, depreciation, amortization, and accretion | 243,220 | 215,146 | |||||
Impairment of oil and gas properties | 130,999 | 37,350 | |||||
Commodity derivative fair value (gains) losses (1) | (328,427) | 168,015 | |||||
Gains on settled commodity derivatives (1) | 44,699 | 313,912 | |||||
Equity-based compensation expense | 6,549 | 7,973 | |||||
Provision for income tax expense (benefit) | 17,249 | (142,404) | |||||
Gain on early extinguishment of debt | — | (39,171) | |||||
Equity in (earnings) loss of unconsolidated affiliates | (13,585) | (20,228) | |||||
Distributions/dividends from unconsolidated affiliates | 47,922 | 42,755 | |||||
Interest expense, net | 54,164 | 51,811 | |||||
Exploration expense | 314 | 231 | |||||
(Gain) Loss on sale of assets | 951 | — | |||||
Contract termination and rig stacking | 5,604 | 11,071 | |||||
Transaction expense | — | 6,138 | |||||
251,827 | 189,531 | ||||||
Martica related adjustments (2) | — | (3,100) | |||||
Adjusted EBITDAX | $ | 251,827 | 186,431 | ||||
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | |||||||
Adjusted EBITDAX | $ | 251,827 | 186,431 | ||||
Martica related adjustments (2) | — | 3,100 | |||||
Interest expense, net | (54,164) | (51,811) | |||||
Exploration expense | (314) | (231) | |||||
Changes in current assets and liabilities | 31,910 | (6,310) | |||||
Transaction expense | — | (6,138) | |||||
Other items | (11,155) | (9,078) | |||||
Net cash provided by operating activities | $ | 218,104 | 115,963 |
(1) | The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation for Adjusted EBITDAX only reflect derivatives that settled during the period. |
(2) | Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above. |
Drilling and Completion Capital Expenditures
For a reconciliation between cash paid for drilling and completion capital expenditures and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below. (in thousands):
Three months ended June 30, | ||||||||
2019 | 2020 | |||||||
Drilling and completion costs (as reported; cash basis) | $ | 311,401 | 251,744 | |||||
Change in accrued capital costs | (8,624) | (71,793) | ||||||
Adjusted drilling and completion costs (accrual basis) | $ | 302,777 | 179,951 |
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, asset monetization opportunities and pricing, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, the amount and timing of any litigation settlements or awards, and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health event, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020.
ANTERO RESOURCES CORPORATION | |||||||||
(Unaudited) | |||||||||
December 31, | June 30, | ||||||||
2019 | 2020 | ||||||||
Assets | |||||||||
Current assets: | |||||||||
Accounts receivable | $ | 46,419 | 57,013 | ||||||
Accounts receivable, related parties | 125,000 | — | |||||||
Accrued revenue | 317,886 | 254,863 | |||||||
Derivative instruments | 422,849 | 521,459 | |||||||
Other current assets | 10,731 | 8,942 | |||||||
Total current assets | 922,885 | 842,277 | |||||||
Property and equipment: | |||||||||
Oil and gas properties, at cost (successful efforts method): | |||||||||
Unproved properties | 1,368,854 | 1,277,476 | |||||||
Proved properties | 11,859,817 | 11,989,302 | |||||||
Gathering systems and facilities | 5,802 | 5,802 | |||||||
Other property and equipment | 71,895 | 72,649 | |||||||
13,306,368 | 13,345,229 | ||||||||
Less accumulated depletion, depreciation, and amortization | (3,327,629) | (3,408,099) | |||||||
Property and equipment, net | 9,978,739 | 9,937,130 | |||||||
Operating leases right-of-use assets | 2,886,500 | 2,562,945 | |||||||
Derivative instruments | 333,174 | 103,514 | |||||||
Investment in unconsolidated affiliate | 1,055,177 | 279,805 | |||||||
Other assets | 21,094 | 18,319 | |||||||
Total assets | $ | 15,197,569 | 13,743,990 | ||||||
Liabilities and Equity | |||||||||
Current liabilities: | |||||||||
Accounts payable | $ | 14,498 | 36,736 | ||||||
Accounts payable, related parties | 97,883 | 73,375 | |||||||
Accrued liabilities | 400,850 | 339,388 | |||||||
Revenue distributions payable | 207,988 | 173,759 | |||||||
Derivative instruments | 6,721 | 3,652 | |||||||
Short-term lease liabilities | 305,320 | 230,499 | |||||||
Other current liabilities | 6,879 | 6,831 | |||||||
Total current liabilities | 1,040,139 | 864,240 | |||||||
Long-term liabilities: | |||||||||
Long-term debt | 3,758,868 | 3,518,076 | |||||||
Deferred income tax liability | 781,987 | 529,598 | |||||||
Derivative instruments | 3,519 | 2,558 | |||||||
Long-term lease liabilities | 2,583,678 | 2,334,227 | |||||||
Other liabilities | 58,635 | 62,312 | |||||||
Total liabilities | 8,226,826 | 7,311,011 | |||||||
Commitments and contingencies (Notes 14 and 15) | |||||||||
Equity: | |||||||||
Stockholders' equity: | |||||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | |||||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 295,941 shares and 268,390 shares issued | 2,959 | 2,684 | |||||||
Additional paid-in capital | 6,130,365 | 6,098,167 | |||||||
Accumulated earnings | 837,419 | 35,305 | |||||||
Total stockholders' equity | 6,970,743 | 6,136,156 | |||||||
Noncontrolling interests | — | 296,823 | |||||||
Total equity | 6,970,743 | 6,432,979 | |||||||
Total liabilities and equity | $ | 15,197,569 | 13,743,990 |
ANTERO RESOURCES CORPORATION | |||||||
Three Months Ended June 30, | |||||||
2019 | 2020 | ||||||
Revenue and other: | |||||||
Natural gas sales | $ | 553,372 | 367,415 | ||||
Natural gas liquids sales | 303,963 | 212,197 | |||||
Oil sales | 49,062 | 8,322 | |||||
Commodity derivative fair value gains (losses) | 328,427 | (168,015) | |||||
Marketing | 63,080 | 64,285 | |||||
Other income | 1,760 | 707 | |||||
Total revenue | 1,299,664 | 484,911 | |||||
Operating expenses: | |||||||
Lease operating | 40,857 | 24,742 | |||||
Gathering, compression, processing, and transportation | 566,834 | 631,845 | |||||
Production and ad valorem taxes | 30,968 | 19,992 | |||||
Marketing | 137,539 | 113,053 | |||||
Exploration | 314 | 231 | |||||
Impairment of oil and gas properties | 130,999 | 37,350 | |||||
Depletion, depreciation, and amortization | 242,302 | 214,035 | |||||
Loss on sale of assets | 951 | — | |||||
Accretion of asset retirement obligations | 918 | 1,111 | |||||
General and administrative (including equity-based compensation expense of $6,549 and | 42,382 | 38,403 | |||||
Contract termination and rig stacking | 5,604 | 11,071 | |||||
Total operating expenses | 1,199,668 | 1,091,833 | |||||
Operating income (loss) | 99,996 | (606,922) | |||||
Other income (expenses): | |||||||
Equity in earnings of unconsolidated affiliates | 13,585 | 20,228 | |||||
Transaction expense | — | (6,138) | |||||
Interest expense, net | (54,164) | (51,811) | |||||
Gain on early extinguishment of debt | — | 39,171 | |||||
Total other income (expenses) | (40,579) | 1,450 | |||||
Income (loss) before income taxes | 59,417 | (605,472) | |||||
Provision for income tax (expense) benefit | (17,249) | 142,404 | |||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | 42,168 | (463,068) | |||||
Less: Net income and comprehensive income attributable to noncontrolling interests | — | 236 | |||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources | $ | 42,168 | (463,304) | ||||
Income (loss) per share—basic | $ | 0.14 | (1.73) | ||||
Income (loss) per share—diluted | $ | 0.14 | (1.73) | ||||
Weighted average number of shares outstanding: | |||||||
Basic | 309,062 | 268,386 | |||||
Diluted | 309,137 | 268,386 |
ANTERO RESOURCES CORPORATION | |||||||
Six Months Ended June 30, | |||||||
2019 | 2020 | ||||||
Cash flows provided by (used in) operating activities: | |||||||
Net income (loss) including noncontrolling interests | $ | 1,067,924 | (801,878) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||
Depletion, depreciation, amortization, and accretion | 484,397 | 415,927 | |||||
Impairment of oil and gas properties | 212,243 | 126,570 | |||||
Impairment of midstream assets | 6,982 | — | |||||
Commodity derivative fair value gains | (251,059) | (397,818) | |||||
Gains on settled commodity derivatives | 141,791 | 524,838 | |||||
Loss on sale of assets | 951 | — | |||||
Equity-based compensation expense | 15,452 | 11,302 | |||||
Deferred income tax expense (benefit) | 304,963 | (252,389) | |||||
Gain on early extinguishment of debt | — | (119,732) | |||||
Equity in (earnings) loss of unconsolidated affiliates | (27,666) | 107,827 | |||||
Impairment of equity investment | — | 610,632 | |||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | — | |||||
Distributions/dividends of earnings from unconsolidated affiliates | 60,527 | 85,511 | |||||
Other | 5,670 | 4,433 | |||||
Changes in current assets and liabilities: | |||||||
Accounts receivable | 5,848 | (27,329) | |||||
Accrued revenue | 166,066 | 63,023 | |||||
Other current assets | 2,307 | 789 | |||||
Accounts payable including related parties | (2,424) | (21,182) | |||||
Accrued liabilities | (22,146) | 15,722 | |||||
Revenue distributions payable | (9,795) | (29,560) | |||||
Other current liabilities | 1,119 | (46) | |||||
Net cash provided by operating activities | 757,108 | 316,640 | |||||
Cash flows provided by (used in) investing activities: | |||||||
Additions to unproved properties | (56,814) | (21,672) | |||||
Drilling and completion costs | (680,088) | (552,227) | |||||
Additions to water handling and treatment systems | (24,416) | — | |||||
Additions to gathering systems and facilities | (48,239) | — | |||||
Additions to other property and equipment | (4,629) | (1,234) | |||||
Settlement of water earnout | — | 125,000 | |||||
Investments in unconsolidated affiliates | (25,020) | — | |||||
Proceeds from the Antero Midstream Partners LP Transactions | 296,611 | — | |||||
Proceeds from asset sales | 1,983 | — | |||||
Change in other assets | (4,974) | 525 | |||||
Net cash used in investing activities | (545,586) | (449,608) | |||||
Cash flows provided by (used in) financing activities: | |||||||
Repurchases of common stock | — | (43,443) | |||||
Issuance of senior notes | 650,000 | — | |||||
Repayment of senior notes | — | (496,541) | |||||
Borrowings (repayments) on bank credit facilities, net | (145,000) | 374,000 | |||||
Payments of deferred financing costs | (8,259) | — | |||||
Sale of noncontrolling interest | — | 300,000 | |||||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (85,076) | — | |||||
Employee tax withholding for settlement of equity compensation awards | (2,295) | (331) | |||||
Other | (1,360) | (717) | |||||
Net cash provided by financing activities | 408,010 | 132,968 | |||||
Effect of deconsolidation of Antero Midstream Partners LP | (619,532) | — | |||||
Net decrease in cash and cash equivalents | — | — | |||||
Cash and cash equivalents, beginning of period | — | — | |||||
Cash and cash equivalents, end of period | $ | — | — | ||||
Supplemental disclosure of cash flow information: | |||||||
Cash paid during the period for interest | $ | 119,180 | 101,885 | ||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment | $ | 33,240 | 61,305 |
The following table set forth selected operating data for the three months ended June 30, 2019 and 2020:
Amount of | ||||||||||||
Three months ended June 30, | Increase | Percent | ||||||||||
(in thousands) | 2019 | 2020 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 553,372 | $ | 367,415 | $ | (185,957) | (34) | % | ||||
Natural gas liquids sales | 303,963 | 212,197 | (91,766) | (30) | % | |||||||
Oil sales | 49,062 | 8,322 | (40,740) | (83) | % | |||||||
Commodity derivative fair value gains (losses) | 328,427 | (168,015) | (496,442) | (151) | % | |||||||
Marketing | 63,080 | 64,285 | 1,205 | 2 | % | |||||||
Other income | 1,760 | 707 | (1,053) | (60) | % | |||||||
Total revenue | 1,299,664 | 484,911 | (814,753) | (63) | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 40,857 | 24,742 | (16,115) | (39) | % | |||||||
Gathering and compression | 210,149 | 202,773 | (7,376) | (4) | % | |||||||
Processing | 193,018 | 242,592 | 49,574 | 26 | % | |||||||
Transportation | 163,667 | 186,480 | 22,813 | 14 | % | |||||||
Production and ad valorem taxes | 30,968 | 19,992 | (10,976) | (35) | % | |||||||
Marketing | 137,539 | 113,053 | (24,486) | (18) | % | |||||||
Exploration | 314 | 231 | (83) | (26) | % | |||||||
Impairment of oil and gas properties | 130,999 | 37,350 | (93,649) | (71) | % | |||||||
Depletion, depreciation, and amortization | 242,302 | 214,035 | (28,267) | (12) | % | |||||||
Loss on sale of assets | 951 | — | (951) | (100) | % | |||||||
Accretion of asset retirement obligations | 918 | 1,111 | 193 | 21 | % | |||||||
General and administrative (excluding equity-based compensation) | 35,833 | 30,430 | (5,403) | (15) | % | |||||||
Equity-based compensation | 6,549 | 7,973 | 1,424 | 22 | % | |||||||
Contract termination and rig stacking | 5,604 | 11,071 | 5,467 | 98 | % | |||||||
Total operating expenses | 1,199,668 | 1,091,833 | (107,835) | (9) | % | |||||||
Operating income (loss) | 99,996 | (606,922) | (706,918) | (707) | % | |||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliates | 13,585 | 20,228 | 6,643 | 49 | % | |||||||
Transaction expense | — | (6,138) | (6,138) | * | ||||||||
Interest expense, net | (54,164) | (51,811) | 2,353 | (4) | % | |||||||
Gain on early extinguishment of debt | — | 39,171 | 39,171 | * | ||||||||
Total other income (expenses) | (40,579) | 1,450 | 42,029 | (104) | % | |||||||
Income (loss) before income taxes | 59,417 | (605,472) | (664,889) | (1,119) | % | |||||||
Provision for income tax (expense) benefit | (17,249) | 142,404 | 159,653 | (926) | % | |||||||
Net income (loss) and comprehensive income (loss) including | 42,168 | (463,068) | (505,236) | (1,198) | % | |||||||
Less: Net income and comprehensive income attributable to | — | 236 | 236 | * | ||||||||
Net income (loss) and comprehensive income (loss) | 42,168 | (463,304) | (505,472) | (1,199) | % | |||||||
Adjusted EBITDAX | $ | 251,827 | $ | 186,431 | $ | (65,396) | (26) | % | ||||
* Not meaningful |
Three months ended June 30, | Amount of | Percent | ||||||||||
2019 | 2020 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 208 | 215 | 7 | 3 | % | |||||||
C2 Ethane (MBbl) | 3,720 | 4,622 | 902 | 24 | % | |||||||
C3+ NGLs (MBbl) | 9,576 | 11,935 | 2,359 | 25 | % | |||||||
Oil (MBbl) | 940 | 1,004 | 64 | 7 | % | |||||||
Combined (Bcfe) | 294 | 320 | 26 | 9 | % | |||||||
Daily combined production (MMcfe/d) | 3,226 | 3,521 | 295 | 9 | % | |||||||
Average prices before effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) | $ | 2.66 | $ | 1.71 | $ | (0.95) | (36) | % | ||||
C2 Ethane (per Bbl) | $ | 8.16 | $ | 5.76 | $ | (2.40) | (29) | % | ||||
C3+ NGLs (per Bbl) | $ | 28.57 | $ | 15.55 | $ | (13.02) | (46) | % | ||||
Oil (per Bbl) | $ | 52.19 | $ | 8.29 | $ | (43.90) | (84) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.09 | $ | 1.83 | $ | (1.26) | (41) | % | ||||
Average realized prices after effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) | $ | 2.86 | $ | 2.79 | $ | (0.07) | (2) | % | ||||
C2 Ethane (per Bbl) | $ | 8.16 | $ | 5.66 | $ | (2.50) | (31) | % | ||||
C3+ NGLs (per Bbl) | $ | 28.67 | $ | 20.23 | $ | (8.44) | (29) | % | ||||
Oil (per Bbl) | $ | 53.49 | $ | 33.47 | $ | (20.02) | (37) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.24 | $ | 2.81 | $ | (0.43) | (13) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.14 | $ | 0.08 | $ | (0.06) | (43) | % | ||||
Gathering and compression | $ | 0.72 | $ | 0.63 | $ | (0.09) | (13) | % | ||||
Processing | $ | 0.66 | $ | 0.76 | $ | 0.10 | 15 | % | ||||
Transportation | $ | 0.56 | $ | 0.58 | $ | 0.02 | 4 | % | ||||
Production taxes | $ | 0.11 | $ | 0.06 | $ | (0.05) | (45) | % | ||||
Marketing, net | $ | 0.25 | $ | 0.15 | $ | (0.10) | (40) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.12 | $ | 0.09 | $ | (0.03) | (25) | % | ||||
All-in cash expense | $ | 2.56 | $ | 2.35 | $ | (0.21) | (8) | % | ||||
Depletion, depreciation, amortization and accretion | $ | 0.83 | $ | 0.67 | $ | (0.16) | (19) | % | ||||
(1) | Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. |
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SOURCE Antero Resources Corporation
DENVER, July 15, 2020 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its second quarter 2020 earnings release on Wednesday, July 29, 2020 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, July 30, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Thursday, August 6, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13703838. To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, August 6, 2020 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, June 15, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced the closing of an overriding royalty interest ("ORRI") transaction with Sixth Street Partners, LLC ("Sixth Street"), a leading global investment firm, that will result in proceeds to the Company of up to $402 million. Proceeds will be used to repay revolver borrowings and the effective date of the transaction is April 1, 2020. Further, the Company announced that it is has repurchased additional 2021 senior notes during the second quarter and that $540 million of that issue remain outstanding. Pro forma for the initial proceeds from the ORRI transaction and the repurchase of senior notes during the quarter, the Company has approximately $745 million drawn on its revolving credit facility and $1.2 billion in liquidity under its credit facility as of March 31, 2020.
Release Highlights:
Paul Rady, Chairman and Chief Executive Officer of Antero, commented, "The ORRI transaction addresses over half of our $650 to $900 million asset sale goal for 2020 and allows us to pay down debt, while importantly retaining the long-term upside of our core acreage position. Additional asset sales and projected free cash flow during 2020 will be used to further reduce debt."
Commenting on the transaction, Glen Warren, President, and Chief Financial Officer of Antero said, "We continued to repurchase bonds during the second quarter, reducing the outstanding principal amount of our 2021 bonds to $540 million. The ORRI transaction increases our liquidity, reduces debt, and positions us to address our upcoming bond maturities. Importantly, our borrowing base remains unchanged following this transaction, which further supports our liquidity profile."
Matt Dillard, Partner at Sixth Street, commented, "Antero has built an extensive core acreage position in one of the lowest cost shale basins in the U.S. Our investment further strengthens Antero's balance sheet and provides a clear path for the company to develop its attractive acreage position for many years to come. We are excited to participate in this shale development alongside a proven team with a long-term track record of industry success."
Credit Suisse Securities (USA) LLC was sole financial advisor to Antero on the ORRI transaction and Vinson & Elkins LLP was the legal advisor. White & Case LLP was the legal advisor to Sixth Street.
Presentation
The Company posted an updated investor presentation on its website at www.anteroresources.com. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
Sixth Street is a global investment firm with over $34 billion in assets under management and committed capital. Through its dedicated energy team based in Houston, Sixth Street invests in and partners with energy companies to finance, acquire, develop, and operate energy-related assets. Sixth Street operates eight diversified, collaborative investment platforms across its growth investing, adjacencies, direct lending, fundamental public strategies, infrastructure, special situations, agriculture and par liquid credit businesses. Its long-term oriented, highly flexible capital base and "One Team" cultural philosophy allows Sixth Street to invest thematically across sectors, geographies and asset classes. Founded in 2009, Sixth Street has more than 275 team members including over 140 investment professionals operating from nine locations around the world. For more information, visit www.sixthstreetpartners.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, future earnings, leverage targets and debt repayment, asset monetization opportunities and pricing, and the amount and timing of any contingent payments, expected drilling and development plans, future financial position, and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2019.
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SOURCE Antero Resources Corporation
DENVER, June 4, 2020 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced a change in the format of its Annual Meeting of Shareholders ("Annual Meeting") from in-person to virtual only, via a live audio webcast at www.virtualshareholdermeeting.com/AR2020. The change is due to the continuing impact of the coronavirus pandemic (COVID-19) and to support the health and well-being of Antero's stockholders, employees and their families. As previously announced, the Annual Meeting will be held on Wednesday, June 17, 2020 at 8:30 A.M., Mountain Time.
For additional information regarding how stockholders may access, vote and participate in the virtual Annual Meeting, please refer to the Company's supplemental proxy materials filed today with the Securities and Exchange Commission.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, April 29, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced its first quarter 2020 financial and operational results. In addition, Antero announced its revised 2020 capital budget and guidance. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.
Highlights Include:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources, commented, "Our reduced 2020 drilling and completion capital budget highlights the continued momentum in our capital cost savings initiative that was launched in early 2019. The new $750 million budget is 41% lower than our 2019 capital spend, with no change to our growth target of 9% for 2020. The lower capital spending plan is partly driven by lower well costs of $715 per lateral foot, a 26% decrease from our first quarter 2019 well costs. Further, due to the near term liquids pricing environment, we have deferred 20 well completions into 2021. This reduced capital budget is expected to result in positive Free Cash Flow of $175 million for 2020 assuming current commodity strip prices. Based on the current commodity price environment, we anticipate a maintenance capital spend level in 2021 of $600 million to hold 3.5 Bcfe/d production flat. This low maintenance capital level, combined with the substantial natural gas and liquids production base, enables Antero to succeed under various pricing environments."
For a discussion of the non-GAAP financial measures including Adjusted EBITDA, Adjusted Net Income, and Free Cash Flow presented on an actual and pro forma basis, please see "Non-GAAP Financial Measures."
COVID-19 Pandemic Developments
As a producer of natural gas, NGLs and oil, Antero Resources is recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic and the communities in which it operates. Antero has continued to operate under these regulations, while taking steps to protect the health and safety of its workers. Antero has implemented protocols to reduce the risk of an outbreak within its field operations, and these protocols have not had an impact on production. A substantial portion of the Company's non-field level employees have transitioned to remote work from home arrangements, and have been able to maintain a consistent level of effectiveness, including maintaining day-to-day operations and decision making, and financial reporting systems and internal control over financial reporting. To date, the Company has had no confirmed cases of COVID-19 within its employee base at any of its locations.
Borrowing Base Redetermination Completed
As a result of the recent spring borrowing base redetermination, the borrowing base under Antero Resources' credit facility was approved at $2.85 billion. This borrowing base is the first redetermination based on stand-alone financials following the midstream simplification and deconsolidation of Antero Midstream in 2019. Lender commitments under the credit facility remained at $2.64 billion and is comprised of 25 banks. The spring redetermination confirms Antero's $1.0 billion in available liquidity under its credit facility as of March 31, 2020.
Lower 2020 Capital Budget
Antero reduced its 2020 drilling and completion capital budget to $750 million from $1.0 billion previously and the $1.15 billion initial budget announced in February 2020. The reduction is driven by continued drilling and completion efficiency improvements, service cost deflation and a deferral of 20 well completions into 2021. Due to these efficiency gains and the reduced activity level, Antero has dropped its rig count to one rig for the remainder of 2020. Antero's completion crew count will be reduced in May from three crews to one crew for the remainder of 2020. Despite the lower capital spend, 2020 production guidance is unchanged at 3.5 Bcfe/d, delivering 9% growth as compared to 2019. Antero projects this reduced capital spend to generate $175 million of positive free cash flow in 2020 based on strip prices as of April 24, 2020.
Antero's drilling and completion capital budget reflects an updated average total well cost of $715 per lateral foot, which compares to the initial 2020 target range of $795 to $825 per foot. Well costs averaged $720 per lateral foot in March of 2020. The continued decline in well costs is attributed to increased stages completed per day in well completions, improved lateral footage drilled per day, lower service costs and numerous other improvements.
The following is a summary of Antero Resources' 33% reduction in the 2020 capital budget.
Capital Budget ($ in millions) | ||||||||||
Initial | Revised | Variance | ||||||||
Drilling & Completion | $1,150 | $750 | 35% | |||||||
Land | 50 | 45 | 10% | |||||||
Total E&P Capital | $1,200 | $795 | 33% |
All guidance not discussed in this release is unchanged from previously stated guidance.
Maintenance Capital Outlook
If low commodity prices persist in 2021, Antero expects to invest approximately $600 million in drilling and completion capital in 2021 to hold the expected 2020 exit rate production flat at 3.5 Bcfe/d in 2021. Additionally, assuming maintenance capital spending in 2021, net marketing expense is estimated to be $150 million, consistent with 2020 guidance, but $50 million above the previous target. Relative to Free Cash Flow, this expense increase would be more than offset by the reduction in capital of over $500 million from the previous plan.
Antero has 1,200 undrilled dry gas locations located in the Ohio Utica and Marcellus Shale in its 2,700 location total drilling inventory. If the current relative strip pricing holds for oil, C3+ NGLs and natural gas, the Company has four pads in the dry gas Ohio Utica that it could drill during 2021.
Unsecured Debt and Common Stock Repurchases
Antero repurchased $383 million notional amount of senior unsecured debt during the first quarter of 2020 at a 21% weighted average discount price. The repurchases were comprised of both the 2021 and 2022 bond maturities and reduced debt by $81 million. In total, during the fourth quarter of 2019 and the first quarter of 2020, Antero repurchased $608 million of notional debt at a 20% weighted average discount, reducing debt by $120 million and net interest expense by $16 million on an annualized basis. The par value of 2021 maturities outstanding has been reduced from $1.0 billion initially to $730 million and the 2022 maturities outstanding has been reduced from $1.1 billion to $761 million, as of March 31, 2020.
Antero also repurchased 27 million shares of its common stock during the first quarter of 2020 at a weighted average cost of $1.57 per share, leaving 269 million shares outstanding at the end of the first quarter.
Appalachian Condensate Outlook
Prior to the COVID-19 pandemic, Antero had developed a diverse set of buyers and destinations as well as in-field and off-site storage capacity for its condensate volumes. Since the outbreak of the pandemic, Antero has further expanded its customer base and doubled its condensate storage capacity within the basin. To date, Antero has not shut-in or curtailed any production from its assets. Although there is uncertainty around how long government stay-at-home mandates will remain in place and hence reduce oil and refined products demand, Antero believes that there will be minimal impact to its 2020 production guidance due to curtailments from condensate production. Oil differentials are expected to widen during the second quarter of 2020. Antero expects full year 2020 realized oil price differential to be $9.00/Bbl to $11.00/Bbl, an increase from $7.00/Bbl to $9.00/Bbl previously.
Based on the above, Antero does not expect material curtailments to residue gas or dry gas production as a result of basin-wide condensate storage constraints or any other unforeseen events arising from the global COVID-19 pandemic. Antero Resources and Antero Midstream continue to work together to find solutions to mitigate the potential impacts of the decline in demand for oil and NGLs including additional storage capacity in the Northeast if needed. In light of the uncertain market conditions impacting the energy industry, Antero Resources will continue to evaluate its capital budget in order to maintain its financial profile.
NGL Prices
The COVID-19 pandemic has not impacted global demand for NGL products nearly as much as it has impacted demand for transportation fuels derived from oil. The restart of economic activity in Asia, coupled with lower LPG production from refineries in the US, Europe, and Asia, has led to strengthening prices for international LPG relative to oil.
Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane export prices through the remainder of 2020 and into 2021. In addition, Antero is 100% hedged on its 2020 condensate and C5+ production, at an oil price equivalent of $55.63/Bbl.
First Quarter 2020 Financial Results
For the three months ended March 31, 2020, Antero reported a GAAP net loss of $339 million, or $1.19 per diluted share, compared to a GAAP net income of $979 million, or $3.17 per diluted share, in the prior year period. Adjusted Net Loss (non-GAAP measure) was $38 million, or $0.13 per diluted share, compared to Adjusted Net Income of $97 million during the three months ended March 31, 2019, or $0.31 per diluted share.
Adjusted EBITDAX (non-GAAP measure) was $244 million, a 45% decrease compared to $443 million in the prior year period due to lower commodity pricing. Antero's average realized price after hedges declined 26% from $4.00 per Mcfe in the first quarter of 2019 to $2.99 per Mcfe in the first quarter of 2020.
The following table details the components of average net production and average realized prices for the three months ended March 31, 2020:
Three months ended March 31, 2020 | ||||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane | Combined | ||||||||||||
Average Net Production | 2,286 | 10,302 | 119,040 | 50,595 | 3,366 | |||||||||||
Average Realized Prices | Natural Gas | Oil ($/Bbl) | C3+ NGLs | Ethane | Combined | |||||||||||
Average realized prices before settled derivatives | $ | 1.98 | $ | 38.02 | $ | 21.31 | $ | 5.82 | $ | 2.30 | ||||||
Settled commodity derivatives | 0.91 | 9.27 | 1.25 | — | 0.69 | |||||||||||
Average realized prices after settled derivatives | $ | 2.88 | $ | 47.29 | $ | 22.56 | $ | 5.82 | $ | 2.99 | ||||||
NYMEX average price | $ | 1.95 | $ | 45.81 | $ | 1.95 | ||||||||||
Premium / to NYMEX | $ | 0.93 | $ | 1.48 | $ | 1.04 |
Net daily natural gas equivalent production in the first quarter averaged 3,366 MMcfe/d, including 179,937 Bbl/d of liquids (68% natural gas by volume). Production increased 9% from the year ago period and 6% from the prior period.
Antero's average realized C3+ NGL price before hedging was $21.31 per barrel, representing a 33% decrease versus the prior year period. Antero shipped 44% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.11 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 56% of C3+ NGL net production at a $0.06 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 119,040 Bbl/d of net C3+ NGL production was $21.31 per barrel, which was a $0.01 per gallon premium to Mont Belvieu pricing. Based on current strip prices at Mont Belvieu and in the international markets, Antero expects its blended realized C3+ NGL prices in 2020 to average a $0.00 to a $0.05 per gallon premium to Mont Belvieu. Antero expects to sell at least 50% of its C3+ NGL production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.
Three months ended March 31, 2020 | |||||||||
Pricing Point | Net C3+ NGL Production | % by | Premium (Discount) To Mont Belvieu | ||||||
Propane / Butane exported on ME2 | Marcus Hook, PA | 52,730 | 44% | $0.11 | |||||
Remaining C3+ NGL volume | Hopedale, OH | 66,310 | 56% | ($0.06) | |||||
Total C3+ NGLs/Blended Premium | 119,040 | 100% | $0.01 |
Cash Expense and Net Marketing Expense
All-in cash expense, which includes lease operating, GP&T, production and ad valorem taxes, net marketing and general and administrative expense (excluding equity-based compensation) was $2.34 per Mcfe in the first quarter, a 9% decrease compared to $2.58 per Mcfe average during the first quarter of 2019. Antero expects all-in cash expense to average $2.25 to $2.35 per Mcfe in 2020.
Per unit net marketing expense declined to $0.15 per Mcfe in the first quarter compared to $0.26 per Mcfe reported in the prior year period. The decline was driven by higher production volumes and the mitigation of some of our excess firm transportation expense during the quarter. Net marketing expense is expected to decline further in 2020, to $0.10 to $0.12 per Mcfe, as a result of both an increase in natural gas production filling excess firm transportation capacity and renegotiated agreements with midstream providers that allow for higher utilization of our transportation capacity to the more attractive pricing in the Gulf Coast markets.
First Quarter 2020 Operating Update
Marcellus Shale — Antero placed 25 horizontal Marcellus wells to sales during the first quarter with an average lateral length of 10,900 feet. Of the 25 wells, 13 new wells had at least 60 days of reported production data during the quarter and the average 60-day rate per well was 22.6 MMcfe/d. Antero drilled an average of 6,395 lateral feet per day in the quarter, which represented a 20% increase compared to the prior year period and was a record for the company. Additionally, Antero's ongoing emphasis on completion efficiencies resulted in an improvement during the first quarter to 7.1 stages completed per day, a 13% increase from 6.3 stages per day in the prior period, also a company record. Last week, Antero's three completion crews averaged 9.7 stages per day and recently set a record for most stages in a day at 13 stages per day. Antero spud 30 wells during the first quarter with an average lateral length of 11,693 feet.
First Quarter 2020 Capital Investment
Antero's cash drilling and completion capital expenditures for the three months ended March 31, 2020 were $300 million. Antero anticipates a decline in capital spending in each subsequent quarter of 2020, reflecting continued efficiencies, service cost deflation and the release of three rigs and two completion crews during the second quarter of 2020. In addition to capital invested in drilling and completion costs, the Company invested $7 million in land during the first quarter.
Balance Sheet and Liquidity
As of March 31, 2020, Antero's total debt was $3.7 billion, of which $882 million were borrowings outstanding under the Company's revolving credit facility. Antero has a borrowing base of $2.85 billion with lender commitments that total $2.64 billion. After deducting letters of credit outstanding of $730 million, the Company had $1.0 billion in available liquidity as of March 31, 2020 and net debt to trailing twelve months Adjusted EBITDAX ratio was 3.5x.
Glen Warren, CFO and President of Antero Resources said, "The borrowing base approval of $2.85 billion provides us with available liquidity of over $1 billion and the flexibility to execute certain asset sales without impacting liquidity under the credit facility. We remain focused on executing on our asset sale program, targeting proceeds of $650 to $900 million during 2020. While the transaction environment has been very challenging over the past few months, we are in substantive discussions with several counterparties and expect the outlook to improve given positive expectations for natural gas and NGL prices going forward. Further, our reduced drilling and completion capital budget is expected to result in $175 million in Free Cash Flow in 2020 based on today's strip prices, providing additional strength to our liquidity profile. Longer term, we are committed to maximizing Free Cash Flow and reducing absolute debt."
Commodity Derivative Positions
Antero has hedged 1.8 Tcf of natural gas at a weighted average index price of $2.75 per MMBtu through 2023 with fixed price swap positions. Antero also has oil and NGL fixed price swap positions, including NGL positions that total 10,352 Bbl/day and oil and C5 positions that total 26,000 Bbl/d during 2020. As of March 31, 2020, the Company's estimated fair value of commodity derivative instruments was $1.1 billion based on strip pricing.
Please see Antero's Annual Report on Form 10-Q for the quarter ended March 31, 2020, for more information on all commodity derivative positions, including basis swaps and natural gas calls.
The following tables summarize Antero's hedge position as of March 31, 2020:
Fixed price natural gas positions from April 1, 2020 through December 31, 2023 were as follows:
Natural gas | Weighted | ||||
Year ending December 31, 2020: | |||||
NYMEX ($/MMBtu) | 2,227,500 | $2.87 | |||
Year ending December 31, 2021: | |||||
NYMEX ($/MMBtu) | 2,400,000 | $2.80 | |||
Year ending December 31, 2022: | |||||
NYMEX ($/MMBtu) | 687,500 | $2.48 | |||
Year ending December 31, 2023: | |||||
NYMEX ($/MMBtu) | 50,000 | $2.39 |
C3+ NGL and Oil derivative contract positions from April 1, 2020 through December 31, 2020 were as follows:
Derivative | Liquids | Weighted | Weighted | Weighted | ||
Year ending December 31, 2020: | ||||||
Total Propane (C3) – ARA (Europe) (1) | Fixed swap | 10,352 | $0.55 | $23.10 | ||
Total NYMEX Crude Oil (2) | 26,000 | $55.63 |
(1) | Net of shipping. Assumes $0.10/gal shipping to ARA. | |||||
(2) | Hedged 20,000 Bbl/d of pentane (C5) at 80% of WTI and hedged the resulting 16,000 Bbl/d of oil-equivalent volumes at $55.63/Bbl WTI on average (80% x $55.63 = $44.52/Bbl pentane). |
Conference Call
A conference call is scheduled on Thursday, April 30, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, May 7, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13701248.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, May 7, 2020 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Basis of Financial Presentation
In connection with the closing of the simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of March 31, 2020, Antero Resources owned 29% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to March 31, 2020, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described herein reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Non-GAAP Financial Measures
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income (Loss), adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (Loss) as an indicator of financial performance. The following tables reconcile net income (loss) to Adjusted Net Income (Loss) (in thousands):
Three months ended | ||||||
March 31, | ||||||
2019 | 2020 | |||||
Net income (loss) attributable to Antero Resources Corp | $ | 978,763 | $ | (338,810) | ||
Commodity derivative fair value (gains) losses | 77,368 | (565,833) | ||||
Gains on settled commodity derivatives | 97,092 | 210,926 | ||||
Impairment of oil and gas properties | 81,244 | 89,220 | ||||
Impairment of equity investment | — | 610,632 | ||||
Equity-based compensation | 6,426 | 3,329 | ||||
Equity in loss of unconsolidated - AMC | (14,081) | 128,055 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | — | ||||
Gain on early extinguishment of debt | — | (80,561) | ||||
Gain on sale of assets | — | (31) | ||||
Contract termination and rig stacking | 8,360 | — | ||||
Simplification transaction fees | 6,297 | — | ||||
Tax effect of reconciling items (1) | 268,111 | (95,071) | ||||
Other tax items (2) | (6,513) | — | ||||
Adjusted Net Income (Loss) | $ | 97,025 | $ | (38,144) | ||
Fully Diluted Shares Outstanding | 308,788 | 284,227 |
(1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
(2) | Tax impact in changes in statutory tax rate and items effecting the deconsolidated financial statements. |
Per Share Amounts
Three months ended | ||||||
March 31, 2020 | ||||||
2019 | 2020 | |||||
Net income (loss) attributable to Antero Resources Corp | $ | 3.17 | (1.19) | |||
Commodity derivative fair value (gains) losses | 0.25 | (1.99) | ||||
Gains on settled commodity derivatives | 0.31 | 0.74 | ||||
Impairment of oil and gas properties | 0.26 | 0.31 | ||||
Impairment of equity investment | — | 2.15 | ||||
Equity-based compensation | 0.02 | 0.01 | ||||
Equity in loss of unconsolidated - AMC | (0.05) | 0.45 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (4.55) | — | ||||
Gain on early extinguishment of debt | — | (0.28) | ||||
Gain on sale of assets | — | — | ||||
Contract termination and rig stacking | 0.03 | — | ||||
Simplification transaction fees | 0.02 | — | ||||
Tax effect of reconciling items (1) | 0.87 | (0.33) | ||||
Other tax items (2) | (0.02) | — | ||||
Adjusted Net Income (Loss) | $ | 0.31 | (0.13) |
(1) | Deferred taxes were approximately 23% for 2019 and 24% for 2020. |
(2) | Tax impact in changes in statutory tax rate and items effecting the deconsolidated financial statements. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | March 31, | |||||
2019 | 2020 | |||||
AR bank credit facility | $ | 552,000 | $ | 882,000 | ||
5.375% AR senior notes due 2021 | 952,500 | 730,283 | ||||
5.125% AR senior notes due 2022 | 923,041 | 761,337 | ||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | ||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | ||||
Net unamortized premium | 791 | 600 | ||||
Net unamortized debt issuance costs | (19,464) | (16,433) | ||||
Total debt | $ | 3,758,868 | 3,707,787 | |||
Less: AR cash and cash equivalents | — | — | ||||
Net debt | $ | 3,758,868 | 3,707,787 | |||
Free Cash Flow
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash flow from operating, investing, or financing activities, as an indicator of cash flow, or as a measure of liquidity. The Company defines Free Cash Flow as Cash Flow from Operations, less drilling and completion capital and leasehold capital plus earnout payments.
The Company has not provided projected Cash Flow from Operations or reconciliations of Free Cash Flow to projected Cash Flow from Operations, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Cash Flow from Operations for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts. However, the Company is able to forecast 2020 drilling and completion capital of $750 million and leasehold capital of $45 million. Targeted 2020 Free Cash Flow also includes the $125 million earnout payment received from Antero Midstream in January 2020 associated with the water drop down transaction that occurred in 2015. Targeted 2020 Free Cash Flow is based on current strip pricing and assumes that dividends from Antero Midstream remain flat for the year for aggregate annual dividends from Antero Midstream of $171 million in 2020. Today, Antero Midstream announced that in light of the uncertain market conditions impacting the energy industry, Antero Midstream will continue to evaluate its capital budget as well as the appropriate amount of capital that is returned to shareholders through dividends and share repurchases in order to maintain its financial profile.
Free Cash Flow is a useful indicator of the Company's ability to internally fund its activities and to service or incur additional debt. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), adjusted for certain items detailed below.
Through March 12, 2019, the financial results of Antero Midstream Partners were included in our consolidated results. Effective March 13, 2019, we no longer consolidate Antero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting. Adjusted EBITDAX includes distributions received with respect to limited partner interests in Antero Midstream Partners common units through March 12, 2019.
Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.
The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our unaudited condensed consolidated statements of cash flows, in each case, for the three months ended March 31, 2019 and 2020. Adjusted EBITDAX also excludes the results of Antero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effective March 13, 2019, we no longer consolidate Antero Midstream Partners results. These adjustments are disclosed in the table below as Antero Midstream Partners related adjustments.
Three months ended March 31, | ||||||
(in thousands) | 2019 | 2020 | ||||
Reconciliation of net income (loss) to Adjusted EBITDAX: | ||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 978,763 | (338,810) | |||
Net income and comprehensive income attributable to noncontrolling interests | 46,993 | — | ||||
Depletion, depreciation, amortization, and accretion | 241,177 | 200,781 | ||||
Impairment of oil and gas properties | 81,244 | 89,220 | ||||
Impairment of midstream assets | 6,982 | — | ||||
Commodity derivative fair value (gains) losses (1) | 77,368 | (565,833) | ||||
Gains on settled commodity derivatives (1) | 97,092 | 210,926 | ||||
Equity-based compensation expense | 8,903 | 3,329 | ||||
Provision for income tax expense (benefit) | 288,710 | (109,985) | ||||
Gain on early extinguishment of debt | — | (80,561) | ||||
Equity in (earnings) loss of unconsolidated affiliates | (14,081) | 128,055 | ||||
Impairment of equity investment | — | 610,632 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | — | ||||
Distributions/dividends from unconsolidated affiliates | 12,605 | 42,756 | ||||
Interest expense, net | 71,950 | 53,102 | ||||
Exploration expense | 126 | 210 | ||||
Gain on sale of assets | — | (31) | ||||
Contract termination and rig stacking | 8,360 | — | ||||
Simplification transaction fees | 15,482 | — | ||||
515,632 | 243,791 | |||||
Net income and comprehensive income attributable to noncontrolling interests | (46,993) | — | ||||
Antero Midstream Partners interest expense, net (2) | (16,815) | — | ||||
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2) | (21,770) | — | ||||
Antero Midstream Partners impairment | (6,982) | — | ||||
Antero Midstream Partners equity-based compensation expense (2) | (2,477) | — | ||||
Antero Midstream Partners equity in earnings of unconsolidated affiliates (2) | 12,264 | — | ||||
Antero Midstream Partners distributions from unconsolidated affiliates (2) | (12,605) | — | ||||
Equity in earnings of Antero Midstream Partners (2) | (15,021) | — | ||||
Distributions from Antero Midstream Partners (2) | 46,469 | — | ||||
Antero Midstream Partners Simplification transaction fees | (9,185) | — | ||||
Antero Midstream Partners related adjustments | (73,115) | — | ||||
Adjusted EBITDAX | $ | 442,517 | 243,791 | |||
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||
Adjusted EBITDAX | $ | 442,517 | 243,791 | |||
Antero Midstream Partners related adjustments | 73,115 | — | ||||
Interest expense, net | (71,950) | (53,102) | ||||
Exploration expense | (126) | (210) | ||||
Gain on asset sale | — | 31 | ||||
Changes in current assets and liabilities | 109,065 | 7,727 | ||||
Simplification transaction fees | (15,482) | — | ||||
Other non-cash items | 1,865 | 2,440 | ||||
Net cash provided by operating activities | $ | 539,004 | 200,677 |
(1) | The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. |
(2) | Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of the Closing). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream Corporation using the equity method of accounting. |
The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended March 31, 2020, as used in this release (in thousands):
Twelve months | |||
(in thousands) | March 31, 2020 | ||
Reconciliation of net loss to Adjusted EBITDAX: | |||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (1,657,702) | |
Depletion, depreciation, amortization, and accretion | 878,233 | ||
Impairment of oil and gas properties | 1,308,420 | ||
Impairment of midstream assets | 7,800 | ||
Commodity derivative fair gains (1) | (1,107,173) | ||
Gains on settled commodity derivatives (1) | 438,924 | ||
Equity-based compensation expense | 17,985 | ||
Provision for income tax benefit | (472,805) | ||
Gain on early extinguishment of debt | (116,980) | ||
Equity in loss of unconsolidated affiliates | 285,352 | ||
Impairment of equity investment | 1,078,222 | ||
Distributions/dividends from unconsolidated affiliates | 188,107 | ||
Loss on sale of equity investments | 108,745 | ||
Water earnout | (125,000) | ||
Gain on sale of assets | 920 | ||
Interest expense, net | 209,263 | ||
Exploration expense | 968 | ||
Contract termination and rig stacking | 5,666 | ||
Adjusted EBITDAX | $ | 1,048,945 |
(1) | The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization. |
Drilling and Completion Capital Expenditures
For a reconciliation between cash paid for drilling and completion capital expenditures and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below. (in thousands):
Three months ended March 31, | |||||||
2019 | 2020 | ||||||
Drilling and completion costs (as reported; cash basis) | $ | 368,687 | 300,483 | ||||
Drilling and completion costs paid to Antero Midstream Partners (cash basis) (1) | 20,565 | — | |||||
Adjusted drilling and completion costs (cash basis) | 389,252 | 300,483 | |||||
Change in accrued capital costs | (9,601) | 8,816 | |||||
Adjusted drilling and completion costs (accrual basis) | $ | 379,651 | 309,299 |
(1) | Represents drilling and completion costs paid to Antero Midstream that were consolidated in Antero Resources' financial results in 2019. |
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, asset monetization opportunities and pricing, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, the amount and timing of any litigation settlements or awards, and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of world health event, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019 and in its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.
ANTERO RESOURCES CORPORATION | ||||||
Consolidated Balance Sheets | ||||||
December 31, 2019 and March 31, 2020 | ||||||
(In thousands, except per share amounts) | ||||||
(Unaudited) | ||||||
December 31, | March 31, | |||||
2019 | 2020 | |||||
Assets | ||||||
Current assets: | ||||||
Accounts receivable | $ | 46,419 | 91,944 | |||
Accounts receivable, related parties | 125,000 | — | ||||
Accrued revenue | 317,886 | 201,320 | ||||
Derivative instruments | 422,849 | 816,444 | ||||
Other current assets | 10,731 | 10,313 | ||||
Total current assets | 922,885 | 1,120,021 | ||||
Property and equipment: | ||||||
Oil and gas properties, at cost (successful efforts method): | ||||||
Unproved properties | 1,368,854 | 1,289,770 | ||||
Proved properties | 11,859,817 | 12,154,162 | ||||
Gathering systems and facilities | 5,802 | 5,802 | ||||
Other property and equipment | 71,895 | 72,312 | ||||
13,306,368 | 13,522,046 | |||||
Less accumulated depletion, depreciation, and amortization | (3,327,629) | (3,527,306) | ||||
Property and equipment, net | 9,978,739 | 9,994,740 | ||||
Operating leases right-of-use assets | 2,886,500 | 2,814,539 | ||||
Derivative instruments | 333,174 | 284,461 | ||||
Investment in unconsolidated affiliate | 1,055,177 | 291,989 | ||||
Other assets | 21,094 | 20,039 | ||||
Total assets | $ | 15,197,569 | 14,525,789 | |||
Liabilities and Equity | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 14,498 | 37,909 | |||
Accounts payable, related parties | 97,883 | 88,894 | ||||
Accrued liabilities | 400,850 | 367,444 | ||||
Revenue distributions payable | 207,988 | 174,654 | ||||
Derivative instruments | 6,721 | — | ||||
Short-term lease liabilities | 305,320 | 295,658 | ||||
Other current liabilities | 6,879 | 7,315 | ||||
Total current liabilities | 1,040,139 | 971,874 | ||||
Long-term liabilities: | ||||||
Long-term debt | 3,758,868 | 3,707,787 | ||||
Deferred income tax liability | 781,987 | 672,002 | ||||
Derivative instruments | 3,519 | 215 | ||||
Long-term lease liabilities | 2,583,678 | 2,520,939 | ||||
Other liabilities | 58,635 | 60,432 | ||||
Total liabilities | 8,226,826 | 7,933,249 | ||||
Commitments and contingencies (Notes 13 and 14) | ||||||
Equity: | ||||||
Stockholders' equity: | ||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 295,941 shares and 268,926 shares issued and outstanding at December 31, 2019 and March 31, 2020, respectively | 2,959 | 2,689 | ||||
Additional paid-in capital | 6,130,365 | 6,091,242 | ||||
Accumulated earnings | 837,419 | 498,609 | ||||
Total equity | 6,970,743 | 6,592,540 | ||||
Total liabilities and equity | $ | 15,197,569 | 14,525,789 |
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||||
Three Months Ended March 31, 2019 and 2020 | |||||||
(Unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
Three Months Ended March 31, | |||||||
2019 | 2020 | ||||||
Revenue and other: | |||||||
Natural gas sales | $ | 657,266 | 411,082 | ||||
Natural gas liquids sales | 313,685 | 257,673 | |||||
Oil sales | 48,052 | 35,646 | |||||
Commodity derivative fair value gains (losses) | (77,368) | 565,833 | |||||
Gathering, compression, water handling and treatment | 4,479 | — | |||||
Marketing | 91,186 | 46,073 | |||||
Other income | 107 | 798 | |||||
Total revenue and other | 1,037,407 | 1,317,105 | |||||
Operating expenses: | |||||||
Lease operating | 41,732 | 25,644 | |||||
Gathering, compression, processing, and transportation | 424,529 | 588,624 | |||||
Production and ad valorem taxes | 35,678 | 25,699 | |||||
Marketing | 163,084 | 93,273 | |||||
Exploration | 126 | 210 | |||||
Impairment of oil and gas properties | 81,244 | 89,220 | |||||
Impairment of midstream assets | 6,982 | — | |||||
Depletion, depreciation, and amortization | 240,201 | 199,677 | |||||
Accretion of asset retirement obligations | 976 | 1,104 | |||||
General and administrative (including equity-based compensation expense of $8,903 and $3,329 in 2019 and 2020, respectively) | 68,202 | 31,221 | |||||
Contract termination and rig stacking | 8,360 | — | |||||
Total operating expenses | 1,071,114 | 1,054,672 | |||||
Operating income (loss) | (33,707) | 262,433 | |||||
Other income (expenses): | |||||||
Equity in earnings (loss) of unconsolidated affiliates | 14,081 | (128,055) | |||||
Impairment of equity investment | — | (610,632) | |||||
Gain on deconsolidation of Antero Midstream Partners LP | 1,406,042 | — | |||||
Interest expense, net | (71,950) | (53,102) | |||||
Gain on early extinguishment of debt | — | 80,561 | |||||
Total other income (expenses) | 1,348,173 | (711,228) | |||||
Income (loss) before income taxes | 1,314,466 | (448,795) | |||||
Provision for income tax (expense) benefit | (288,710) | 109,985 | |||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | 1,025,756 | (338,810) | |||||
Net income and comprehensive income attributable to noncontrolling interests | 46,993 | — | |||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 978,763 | (338,810) | ||||
Income (loss) per share—basic | $ | 3.17 | (1.19) | ||||
Income (loss) per share—diluted | $ | 3.17 | (1.19) | ||||
Weighted average number of shares outstanding: | |||||||
Basic | 308,694 | 284,227 | |||||
Diluted | 308,788 | 284,227 | |||||
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Cash Flows | ||||||
Three Months Ended March 31, 2019 and 2020 | ||||||
(Unaudited) | ||||||
(In thousands) | ||||||
Three Months Ended March 31, | ||||||
2019 | 2020 | |||||
Cash flows provided by (used in) operating activities: | ||||||
Net income (loss) including noncontrolling interests | $ | 1,025,756 | (338,810) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||
Depletion, depreciation, amortization, and accretion | 241,177 | 200,781 | ||||
Impairment of oil and gas properties | 81,244 | 89,220 | ||||
Impairment of midstream assets | 6,982 | — | ||||
Commodity derivative fair value (gains) losses | 77,368 | (565,833) | ||||
Gains on settled commodity derivatives | 97,092 | 210,926 | ||||
Equity-based compensation expense | 8,903 | 3,329 | ||||
Deferred income tax expense (benefit) | 287,854 | (109,985) | ||||
Gain on early extinguishment of debt | — | (80,561) | ||||
Equity in (earnings) loss of unconsolidated affiliates | (14,081) | 128,055 | ||||
Impairment of equity investment | — | 610,632 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | — | ||||
Distributions/dividends of earnings from unconsolidated affiliates | 12,605 | 42,756 | ||||
Other | 11,081 | 2,440 | ||||
Changes in current assets and liabilities: | ||||||
Accounts receivable | 42,168 | (54,514) | ||||
Accrued revenue | 109,677 | 116,566 | ||||
Other current assets | 1,364 | (583) | ||||
Accounts payable including related parties | (21,370) | (1,251) | ||||
Accrued liabilities | (14,965) | (19,593) | ||||
Revenue distributions payable | (9,761) | (33,333) | ||||
Other current liabilities | 1,952 | 435 | ||||
Net cash provided by operating activities | 539,004 | 200,677 | ||||
Cash flows provided by (used in) investing activities: | ||||||
Additions to unproved properties | (27,463) | (10,357) | ||||
Drilling and completion costs | (368,687) | (300,483) | ||||
Additions to water handling and treatment systems | (24,416) | — | ||||
Additions to gathering systems and facilities | (48,239) | — | ||||
Additions to other property and equipment | (3,128) | (771) | ||||
Settlement of water earnout | — | 125,000 | ||||
Investments in unconsolidated affiliates | (25,020) | — | ||||
Proceeds from the Antero Midstream Partners LP Transactions | 296,611 | — | ||||
Change in other assets | (4,475) | (70) | ||||
Net cash used in investing activities | (204,817) | (186,681) | ||||
Cash flows provided by (used in) financing activities: | ||||||
Repurchases of common stock | — | (42,690) | ||||
Issuance of senior notes | 650,000 | — | ||||
Repayment of senior notes | — | (300,835) | ||||
Borrowings (repayments) on bank credit facilities, net | (270,000) | 330,000 | ||||
Payments of deferred financing costs | (8,259) | — | ||||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (85,076) | — | ||||
Employee tax withholding for settlement of equity compensation awards | (479) | (32) | ||||
Other | (841) | (439) | ||||
Net cash provided by (used in) financing activities | 285,345 | (13,996) | ||||
Effect of deconsolidation of Antero Midstream Partners LP | (619,532) | — | ||||
Net decrease in cash and cash equivalents | — | — | ||||
Cash and cash equivalents, beginning of period | — | — | ||||
Cash and cash equivalents, end of period | $ | — | — | |||
Supplemental disclosure of cash flow information: | ||||||
Cash paid during the period for interest | $ | 37,081 | 30,089 | |||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | $ | (22,825) | 10,767 |
The following table set forth selected operating data for the three months ended March 31, 2019 and 2020:
Three months ended March 31, | Amount of | Percent | ||||||||||
(in thousands) | 2019 | 2020 | (Decrease) | Change | ||||||||
Operating revenues and other: | ||||||||||||
Natural gas sales | $ | 657,266 | $ | 411,082 | $ | (246,184) | (37) | % | ||||
NGLs sales | 313,685 | 257,673 | (56,012) | (18) | % | |||||||
Oil sales | 48,052 | 35,646 | (12,406) | (26) | % | |||||||
Commodity derivative fair value gains (losses) | (77,368) | 565,833 | 643,201 | 831 | % | |||||||
Gathering, compression, water handling and treatment | 4,479 | — | (4,479) | (100) | % | |||||||
Marketing | 91,186 | 46,073 | (45,113) | (49) | % | |||||||
Other income | 107 | 798 | 691 | 646 | % | |||||||
Total operating revenues and other | 1,037,407 | 1,317,105 | 279,698 | 27 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 41,732 | 25,644 | (16,088) | (39) | % | |||||||
Gathering and compression | 102,347 | 193,008 | 90,661 | 89 | % | |||||||
Processing | 169,999 | 210,236 | 40,237 | 24 | % | |||||||
Transportation | 152,183 | 185,380 | 33,197 | 22 | % | |||||||
Production and ad valorem taxes | 35,678 | 25,699 | (9,979) | (28) | % | |||||||
Marketing | 163,084 | 93,273 | (69,811) | (43) | % | |||||||
Exploration | 126 | 210 | 84 | 67 | % | |||||||
Impairment of oil and gas properties | 81,244 | 89,220 | 7,976 | 10 | % | |||||||
Impairment of midstream assets | 6,982 | — | (6,982) | (100) | % | |||||||
Depletion, depreciation, and amortization | 240,201 | 199,677 | (40,524) | (17) | % | |||||||
Accretion of asset retirement obligations | 976 | 1,104 | 128 | 13 | % | |||||||
General and administrative (excluding equity-based compensation) | 59,299 | 27,892 | (31,407) | (53) | % | |||||||
Equity-based compensation | 8,903 | 3,329 | (5,574) | (63) | % | |||||||
Contract termination and rig stacking | 8,360 | — | (8,360) | (100) | % | |||||||
Total operating expenses | 1,071,114 | 1,054,672 | (16,442) | (2) | % | |||||||
Operating income (loss) | (33,707) | 262,433 | 296,140 | 879 | % | |||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliates | 14,081 | (128,055) | (142,136) | (1,009) | % | |||||||
Impairment of equity investments | — | (610,632) | (610,632) | * | ||||||||
Interest expense | (71,950) | (53,102) | 18,848 | (26) | % | |||||||
Gain on deconsolidation of Antero Midstream Partners LP | 1,406,042 | — | (1,406,042) | (100) | % | |||||||
Gain on early extinguishment of debt | — | 80,561 | 80,561 | * | ||||||||
Total other earnings (expenses) | 1,348,173 | (711,228) | (2,059,401) | (153) | % | |||||||
Income (loss) before income taxes | 1,314,466 | (448,795) | (1,763,261) | (134) | % | |||||||
Income tax (expense) benefit | (288,710) | 109,985 | 398,695 | 138 | % | |||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | 1,025,756 | (338,810) | (1,364,566) | (133) | % | |||||||
Net income and comprehensive income attributable to noncontrolling interest | 46,993 | — | (46,993) | (100) | % | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 978,763 | $ | (338,810) | $ | (1,317,573) | (135) | % | ||||
Adjusted EBITDAX | $ | 442,517 | $ | 243,791 | $ | (198,726) | (45) | % |
* Not meaningful |
Three months ended March 31, | Amount of | Percent | ||||||||||
2019 | 2020 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 199 | 208 | 9 | 5 | % | |||||||
C2 Ethane (MBbl) | 3,509 | 4,604 | 1,095 | 31 | % | |||||||
C3+ NGLs (MBbl) | 8,794 | 10,833 | 2,039 | 23 | % | |||||||
Oil (MBbl) | 1,017 | 938 | (79) | (8) | % | |||||||
Combined (Bcfe) | 279 | 306 | 27 | 10 | % | |||||||
Daily combined production (MMcfe/d) | 3,099 | 3,366 | 267 | 9 | % | |||||||
Average prices before effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) (2) | $ | 3.30 | $ | 1.98 | $ | (1.32) | (40) | % | ||||
C2 Ethane (per Bbl) | $ | 10.12 | $ | 5.82 | $ | (4.30) | (42) | % | ||||
C3+ NGLs (per Bbl) | $ | 31.63 | $ | 21.31 | $ | (10.32) | (33) | % | ||||
Oil (per Bbl) | $ | 47.23 | $ | 38.02 | $ | (9.21) | (20) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.65 | $ | 2.30 | $ | (1.35) | (37) | % | ||||
Average realized prices after effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) | $ | 3.79 | $ | 2.88 | $ | (0.91) | (24) | % | ||||
C2 Ethane (per Bbl) | $ | 10.12 | $ | 5.82 | $ | (4.30) | (42) | % | ||||
C3+ NGLs (per Bbl) | $ | 31.59 | $ | 22.56 | $ | (9.03) | (29) | % | ||||
Oil (per Bbl) | $ | 47.23 | $ | 47.29 | $ | 0.06 | 0 | % | ||||
Weighted Average Combined (per Mcfe) | $ | 4.00 | $ | 2.99 | $ | (1.01) | (25) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.15 | $ | 0.08 | $ | (0.07) | (47) | % | ||||
Gathering and compression | $ | 0.76 | $ | 0.63 | $ | (0.13) | (17) | % | ||||
Processing | $ | 0.61 | $ | 0.69 | $ | 0.08 | 13 | % | ||||
Transportation | $ | 0.55 | $ | 0.61 | $ | 0.06 | 11 | % | ||||
Production and ad valorem taxes | $ | 0.12 | $ | 0.08 | $ | (0.04) | (33) | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.78 | $ | 0.66 | $ | (0.12) | (15) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.16 | $ | 0.09 | $ | (0.07) | (44) | % |
(1) | Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value. |
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SOURCE Antero Resources Corporation
DENVER, April 15, 2020 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its first quarter 2020 earnings release on Wednesday, April 29, 2020 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, April 30, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Thursday, May 7, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13701248. To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, May 7, 2020 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, April 2, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced that Jacqueline C. Mutschler has been appointed to its board of directors (the "Board"), as a Class II director, effective as of March 31, 2020. Ms. Mutschler is an independent director under the director independence standards set forth in the rules and regulations of the Securities and Exchange Commission and the applicable listing standards of the New York Stock Exchange. Ms. Mutschler's appointment increases the size of the Board to nine directors, seven of whom are independent for service on the Board.
Ms. Mutschler has an extensive background in the oil and gas industry, previously serving as Senior Vice President and Head of Exploration and Production Technology at BP, PLC from 2006 to 2014. Prior to that, Ms. Mutschler served in a number of leadership positons at BP from 1986 to 2006 across various business segments that included U.S. Unconventional Gas, E&P Change Management Strategy and Appraisal & Developments. Her areas of focus at BP included strategy development, organizational and leadership practices to deliver new technology, digital optimization and analysis of conventional and unconventional production opportunities across the world. Ms. Mutschler currently consults as an independent executive consultant, providing advice and training for the oil and gas, technology and automotive sectors. Ms. Mutschler also currently serves on the Board of Weatherford International. Ms. Mutschler received a Bachelor of Science in Geology/Geophysics from Wright State University.
Paul M. Rady, Chairman and CEO of Antero Resources commented, "We are delighted to welcome Jackie to our Board of Directors. Her broad functional and management experience at BP combined with a significant focus on technology innovation in the oil and gas industry will serve as a valuable asset to Antero and its stakeholders."
Ms. Mutschler stated, "I am excited to join the Antero Resources Board of Directors. With a low cost, integrated asset base in one of the largest natural gas and liquids plays in the world combined with compelling ESG metrics, there is a lot of opportunity to maximize value for Antero shareholders."
Antero Resources is an independent oil and natural gas company engaged in the exploration, development and production of natural gas, NGLs, and oil properties located in the Appalachian Basin.
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SOURCE Antero Resources Corporation
DENVER, Feb. 12, 2020 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced its fourth quarter and full year 2019 financial and operational results as well as its 2020 capital budget, guidance and proved reserves as of December 31, 2019. The relevant consolidated financial statements are included in Antero Resource's Annual Report on Form 10-K for the year ended December 31, 2019.
Fourth Quarter and Full Year 2019 Highlights Include:
2020 Guidance Highlights:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, "Our 2020 capital budget highlights the direct benefit from our well cost savings initiatives that we launched in 2019. In simple terms, we have reduced our total well cost per foot from $970 in the initial 2019 budget to a target of $795 to $825 per for 2020. The result is a 10% reduction in drilling and completion capital and a 28% reduction in lease operating expense as compared to 2019, while delivering production growth of 9%. This level of production in turn should trigger $75 million in previously announced gathering, processing and transportation expense savings in 2020 and paves the way for up to $350 million in total savings between 2020 and 2023. Additionally, by growing into our unutilized firm transportation commitments we reduce our cost structure by another $200 million by 2022."
Mr. Rady continued, "We believe that our industry-leading hedge portfolio and diversified production mix, combined with our ability to export more than 50% of our C3+ NGL production to premium international markets, provides Antero with a competitive advantage throughout commodity price cycles. Our cost savings initiatives and liquids exposure result in a projected cash flow neutral profile for 2020 at current strip pricing including the $125 million water earnout payment received in January from Antero Midstream."
2020 Capital Budget and Guidance
The following is a summary of Antero Resources' 2020 capital budget. The capital budget is based on commodity strip pricing as of February 7, 2020 that was $52 per barrel WTI oil, $25 per barrel C3+ NGL and $2.08 per MMBtu NYMEX natural gas for 2020.
Capital Budget ($ in Billions) | ||||
Drilling & Completion | $1.15 | |||
Land | $0.05 | |||
Total E&P Capital | $1.2 |
The following is a summary of Antero Resources' 2020 production, pricing and cash expense guidance.
Production Guidance | ||||||
Net Daily Natural Gas Equivalent Production (MMcfe/d) | 3,500 | |||||
Net Daily Natural Gas Production (MMcf/d) | 2,375 | |||||
Total Net Daily Liquids Production (Bbl/d): | 187,500 | |||||
Realized Pricing Guidance | ||||||
Natural Gas Realized Price vs. NYMEX Henry Hub ($/Mcf) | $0.00 – $0.10 | |||||
Oil Realized Price vs. WTI Oil ($/Bbl) | ($7.00) – ($9.00) | |||||
C3+ NGL Realized Price vs. Mont Belvieu ($/Gal) | $0.00 – $0.05 | |||||
Cash Expense Guidance | Low | High | ||||
Cash Production Expense ($/Mcfe)(1) | $2.07 | $2.13 | ||||
Marketing Expense, Net of Marketing Revenue ($/Mcfe) | $0.10 | $0.12 | ||||
G&A Expense ($/Mcfe)(2) | $0.08 | $0.10 | ||||
All-In Cash Expense | $2.25 | $2.35 |
(1) | Includes lease operating expenses, gathering, compression, processing and transportation expenses ("GP&T") and production and ad valorem taxes. |
(2) | Excludes equity-based compensation. |
Well Cost Savings
Antero's drilling and completion capital budget is based on average total well cost of $825 per foot, which is at the high end of the 2020 target range of $795 to $825 per foot. Well costs averaged $860 per foot in the fourth quarter of 2019 with only a portion of the wells being completed with reduced water. The reduction in 2020 well costs is expected to be driven by both drier completions (36 Bbl of water per foot of lateral) on all wells and expanded produced water services provided by Antero Midstream.
Fourth Quarter 2019 Financial Results
For the three months ended December 31, 2019, Antero reported a GAAP net loss of $482 million, or $1.61 per diluted share, compared to a GAAP net loss of $122 million, or $0.39 per diluted share, in the prior year period. Adjusted Net Loss (non-GAAP measure) was $6 million, or $0.02 per diluted share, compared to Adjusted Net Income of $175 million during the three months ended December 31, 2018, or $0.56 per diluted share. The Adjusted Net Loss reflects a $468 million impairment based on the fair value of our equity interest in Antero Midstream at year end 2019.
Adjusted EBITDAX (non-GAAP measure) was $295 million, a 38% decrease compared to $475 million in the prior year period due to lower commodity pricing. Antero's average realized price after hedges declined 20% from $3.97 per Mcfe in the fourth quarter of 2018 to $3.18 per Mcfe in the fourth quarter of 2019.
The following table details the components of average net production and average realized prices for the three months ended December 31, 2019:
Three months ended December 31, 2019 | |||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane | Combined | |||||||||||
Average Net Production | 2,223 | 8,793 | 104,376 | 47,014 | 3,185 | ||||||||||
Average Realized Prices | Natural Gas | Oil ($/Bbl) | C3+ NGLs | Ethane | Combined | ||||||||||
Average realized prices before settled derivatives | $ | 2.50 | $ | 49.29 | $ | 29.61 | $ | 7.44 | $ | 2.96 | |||||
Settled commodity derivatives | 0.37 | 4.28 | (1.66) | — | 0.22 | ||||||||||
Average realized prices after settled derivatives | $ | 2.87 | $ | 53.57 | $ | 27.95 | $ | 7.44 | $ | 3.18 | |||||
NYMEX average price | $ | 2.50 | $ | 56.96 | $ | 2.50 | |||||||||
Premium / (Differential) to NYMEX | $ | 0.37 | $ | (3.39) | $ | 0.68 |
Net daily natural gas equivalent production in the fourth quarter averaged 3,185 MMcfe/d, including 160,183 Bbl/d of liquids (30% liquids by volume). Liquids revenue represented approximately 41% of total product revenue before hedges. Production declined 1% from the prior year period due to the timing of well completions in 2019 as two pads, totaling 13 wells, were turned to sales in late December of 2019.
Antero's average realized C3+ NGL price before hedging was $29.61 per barrel, representing a 4% decrease versus the prior year period and a 31% increase from the third quarter of 2019. Antero shipped 41% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.21 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. Antero sold the remaining 59% of C3+ NGL net production at a $0.09 per gallon discount to Mont Belvieu pricing at Hopedale, OH. The resulting blended price on 104,376 Bbl/d of net C3+ NGL production was $29.61 per barrel, which was a $0.03 per gallon premium to Mont Belvieu pricing. Based on current strip prices at Mont Belvieu and in the international markets, Antero expects its realized C3+ NGL prices in 2020 to be $0.00 to a $0.05 per gallon premium to Mont Belvieu. Antero expects to sell at least 50% of its C3+ NGL production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.
Three months ended December 31, 2019 | ||||||||
Pricing Point | Net C3+ NGL Production | % by | Premium (Discount) To Mont Belvieu | |||||
Propane / Butane shipped on ME2 | Marcus Hook | 42,794 | 41% | $0.21 | ||||
Remaining C3+ NGL volume | Hopedale | 61,582 | 59% | ($0.09) | ||||
Total C3+ NGLs | 104,376 | 100% | $0.03 |
Cash Expense and Net Marketing Expense
All-in per unit cash expense, which includes lease operating, GP&T, production and ad valorem taxes, net marketing and general and administrative expense (excluding equity-based compensation) was $2.34 per Mcfe in the fourth quarter, an 8% decrease compared to $2.56 per Mcfe average during the first half of 2019. Antero expects all-in cash expense of $2.25 to $2.35 per Mcfe as a result of the recently announced midstream fee reductions, filling unutilized firm transportation, and ongoing progress on the water savings initiatives that reduces lease operating expense.
Per unit net marketing expense declined to $0.17 per Mcfe in the fourth quarter compared to $0.22 per Mcfe reported in the prior year period. The decline was driven by the mitigation of some of our excess firm transportation expense. Net marketing expense is expected to decline further in 2020, to $0.10 to $0.12 per Mcfe, as a result of both an increase in natural gas production filling excess firm transportation capacity and renegotiated agreements with midstream providers that allow for higher utilization of our transportation capacity to the more attractive pricing in the Gulf Coast markets.
Adjusted EBITDAX margin (non-GAAP measure) was $1.01 per Mcfe, a 37% decrease from the prior year period, due to lower realized prices relative to the prior year period. The following table presents a calculation of Adjusted EBITDAX margin on a per Mcfe basis and a reconciliation to the realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, and is a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations on a per unit basis from period to period by removing the effect of its capital structure from its operating structure.
Three months ended December 31, | |||||||
2018 | 2019 | ||||||
Adjusted EBITDAX margin ($ per Mcfe): | |||||||
Realized price before cash receipts for settled derivatives | $ | 4.05 | $ | 2.96 | |||
Distributions/dividends from Antero Midstream | 0.16 | 0.17 | |||||
Marketing, net | (0.22) | (0.17) | |||||
Gathering, compression, processing and transportation costs | (1.88) | (1.88) | |||||
Lease operating expense | (0.15) | (0.09) | |||||
Production and ad valorem taxes | (0.15) | (0.10) | |||||
General and administrative (excluding equity-based compensation) | (0.11) | (0.10) | |||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.70 | 0.79 | |||||
Cash receipts for settled commodity derivatives | (0.09) | 0.22 | |||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 1.61 | $ | 1.01 |
Fourth Quarter 2019 Operating Update
Marcellus Shale — Antero placed 21 horizontal Marcellus wells to sales during the fourth quarter of 2019 with an average lateral length of 11,600 feet. For new wells that had 60 days of reported production data during the quarter, the average 60-day rate per well was 18.2 MMcfe/d on choke. The 60-day average rate per well included 742 Bbl/d of liquids, comprised of oil, C3+ NGLs and assumes 25% ethane recovery.
Additionally, Antero drilled an average of 7,000 lateral feet per day in the quarter, achieving its highest quarterly rate in the Company's history. This drilling record represents a 17% sequential increase and a 38% increase compared to the 2018 average in lateral footage performance. Antero also drilled a company one-well record of 10,453 lateral feet in a 24-hour period. During 2019, Antero drilled 97 wells that averaged over one mile per day drilling in the lateral and was the only known operator in the Marcellus to drill over 10,000 lateral feet in a 24-hour period, which Antero accomplished twice. Antero's ongoing emphasis on completion efficiencies resulted in an improvement during the fourth quarter, as the Company averaged 6.3 stages completed per day, representing a 7% increase from 5.9 stages per day in the prior period.
Fourth Quarter and Full Year 2019 Capital Investment
Antero's accrued drilling and completion capital expenditures for the three months ended December 31, 2019 were $300 million. For the full year 2019, drilling and completion capital expenditures were $1.27 billion, a decrease of 16% from 2018 and 7% below Antero's original 2019 guidance.
Balance Sheet and Liquidity
As of December 31, 2019, Antero's total debt was $3.76 billion, of which $552 million were borrowings outstanding under the Company's revolving credit facility. Antero has a borrowing base of $4.5 billion with lender commitments that total $2.64 billion. After deducting letters of credit outstanding of $623 million, the Company had $1.5 billion in available liquidity. The decrease in Antero's outstanding letters of credit from the prior period reflect new surety bonds that were secured during the fourth quarter. As of December 31, 2019, Antero's net debt to trailing twelve months Adjusted EBITDAX ratio was 3.0x.
Antero repurchased $225 million principal amount of senior unsecured notes during the fourth quarter at a 17% weighted average discount price, including both its 2021 and 2022 senior notes. The repurchases reduced Antero's total debt by $37 million and net interest expense was reduced by $6 million on an annualized basis. Antero also repurchased 8.3 million shares of common stock during the fourth quarter at a weighted average price of $2.50 per share.
President and CFO, Glen Warren, commented, "Our ability to materially reduce operating costs and lower capital spending allows us to protect our balance sheet while executing a moderate near-term growth strategy to fill our remaining unfilled premium firm transportation and realize the midstream fee reductions announced in December. Pro forma for the recently announced asset sale program, we are targeting a mid 2-times leverage ratio with robust liquidity of $2.3 billion at year-end 2020 excluding further senior note repurchases or redemptions. Longer term, we are committed to reducing absolute debt and maximizing free cash flow as we expect to fill our premium firm transportation commitments by the end of 2021."
Year End Proved Reserves
At December 31, 2019, Antero's estimated proved reserves were 18.9 Tcfe, a 5% increase over the prior year. Estimated proved reserves were comprised of 61% natural gas, 38% NGLs and 1% oil. The Marcellus Shale accounted for 92% of estimated proved reserves and the Ohio Utica Shale accounted for 8%. For 2019, Antero added 3.7 Tcfe of estimated proved reserves. Approximately 2.3 Tcfe was removed from Antero's proved reserves due to the SEC 5-year rule, primarily related to changes in drilling locations in our 5-year development plan.
Estimated proved developed reserves were 11.7 Tcfe, a 13% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 62% at year-end 2019, compared to 58% at year-end 2018. Antero's 328 proved undeveloped locations average an estimated 1258 BTU, with an average lateral length of approximately 12,500 feet.
Antero's 7.2 Tcfe of estimated proved undeveloped reserves will require an estimated $2.6 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.
The following table presents a summary of changes in estimated proved reserves (in Tcfe).
Proved reserves, December 31, 2018 | 18.0 | ||
Extensions, discoveries, and other additions | 3.7 | ||
Revisions to prior estimates | (1.6) | ||
Estimated Production | (1.2) | ||
Proved reserves, December 31, 2019 | 18.9 |
The following table summarizes pre-tax estimated proved reserves PV-10 (non-GAAP measure) and the associated Standardized Measure. The decrease in pre-tax estimated proved reserves PV-10 value as compared to 2018, was due primarily to lower SEC pricing and the deconsolidation of Antero Resources' and Antero Midstream's financial statements. Lower pricing resulted in approximately 65% of the decline and the deconsolidation resulted in approximately 35% of the reduction. The deconsolidation resulted in Antero Resources recording the full fees paid to Antero Midstream for services rendered and no longer recording the future capital expenditures associated with Antero Midstream assets in future development costs. Prior to deconsolidation, as required by SEC guidance, Antero Resources' consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream and the inclusion of the operating costs and capital incurred by Antero Midstream. Detailed SEC pricing can be found in Antero's Form 10-K for the year ended December 31, 2019.
SEC Pricing | |||||||
Proved Reserve Value ($B): | 2019 Year-End | 2018 Year-End | % | ||||
(Deconsolidated) | (Consolidated) | Variance | Variance | ||||
Standardized Measure | $5.5 | $10.5 | $5.0 | -52% | |||
Pre-tax estimated proved reserves PV-10 | $6.1 | $12.6 | $6.5 | -52% | |||
Pre-tax estimated proved developed reserves PV-10 | $4.7 | $8.4 | $3.7 | -45% |
Commodity Derivative Positions
Antero has hedged 1.8 Tcf of natural gas at a weighted average index price of $2.84 per MMBtu through 2023 with fixed price swap positions. Antero also has oil and NGL fixed price swap positions, including NGL positions that totaled 35,800 Bbl/day and oil positions that totaled 10,000 Bbl/d during 2020. As of December 31, 2019, the Company's estimated fair value of commodity derivative instruments was $1.1 billion based on strip pricing.
Please see Antero's Annual Report on Form 10-K for the year ended December 31, 2019, for more information on all commodity derivative positions.
The following tables summarize Antero's hedge position as of December 31, 2019:
Fixed price natural gas positions from January 1, 2020 through December 31, 2023 were as follows:
Natural gas MMBtu/day | Weighted average index price | ||||
Year ending December 31, 2020: | |||||
NYMEX ($/MMBtu) | 2,227,500 | $ | 2.87 | ||
Year ending December 31, 2021: | |||||
NYMEX ($/MMBtu) | 2,400,000 | $ | 2.80 | ||
Year ending December 31, 2022: | |||||
NYMEX ($/MMBtu) | 0 | $ | N/A | ||
Year ending December 31, 2023: | |||||
NYMEX ($/MMBtu) | 90,000 | $ | 2.91 |
C3+ NGL and Oil derivative contract positions from January 1, 2020 through December 31, 2020 were as follows:
Derivative | Liquids Hedges | Weighted | Weighted differential | Weighted | |||
Year ending December 31, 2020: | |||||||
Propane (C3) – Mont Belvieu (Domestic) | Fixed swap | 373 | $0.50 | $21.00 | |||
Propane (C3) – ARA (Europe) (1) | Fixed swap | 10,371 | $0.55 | $23.10 | |||
Propane (C3) – FEI (Asia) (1) | Fixed swap | 2,457 | $0.61 | $25.62 | |||
Normal Butane (C4) – ARA to Mont Belvieu Basis | Basis | 1,072 | — | $0.23 | — | ||
Normal Butane (C4) – Mont Belvieu (Domestic) | Fixed swap | 1,492 | $0.57 | $24.12 | |||
Pentane (C5) – Mont Belvieu (Domestic) (2) | Fixed swap | 20,000 | $1.06 | $44.52 | |||
Total C3+ NGLs | 35,765 | ||||||
Total NYMEX Crude Oil | 10,000 | $55.63 |
(1) | Net of shipping. Assumes $0.10/gal shipping to ARA and $0.20/gal shipping to FEI. | ||||
(2) | Hedged 20,000 Bbl/d of pentane (C5) at 80% of WTI and hedged the resulting 16,000 Bbl/d of oil-equivalent volumes at $55.63/Bbl WTI or average (80% x $55.63 = $44.52/Bbl pentane). |
Conference Call
A conference call is scheduled on Thursday, February 13, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, February 20, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13693463.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 20, 2020 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Basis of Financial Presentation
In connection with the closing of the simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of December 31, 2019, Antero Resources owned 29% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to December 31, 2019, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described herein reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Non-GAAP Financial Measures
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income (Loss), adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (Loss) as an indicator of financial performance. The following tables reconcile net income (loss) before income taxes to Adjusted Net Income (Loss) (in thousands):
Three months ended | Twelve months ended | |||||||||
December 31, | December 31, | |||||||||
2018 | 2019 | 2018 | 2019 | |||||||
Net loss attributable to Antero Resources Corp | $ | (121,546) | $ | (482,196) | $ | (397,517) | (340,129) | |||
Commodity derivative fair value losses (gains) | 222,387 | 7,875 | 87,594 | (463,972) | ||||||
Gains (losses) on settled commodity derivatives | (25,257) | 63,296 | 243,112 | 325,090 | ||||||
Marketing derivative fair value losses (gains) | — | — | (94,081) | — | ||||||
(Gains) losses on settled marketing derivatives | (5,411) | — | 72,687 | — | ||||||
Impairment of oil and gas properties | 143,369 | 46,732 | 553,907 | 1,300,444 | ||||||
Impairment of midstream assets | — | — | — | 7,800 | ||||||
Impairment of equity investments | — | 467,590 | — | 467,590 | ||||||
Equity-based compensation | 9,518 | 4,232 | 49,341 | 21,082 | ||||||
Income from water earnout | — | (125,000) | — | (125,000) | ||||||
Gain on deconsolidation of Antero Midstream LP | — | — | — | (1,406,042) | ||||||
Loss on change of fair value of contingent acquisition consideration | 104,860 | — | 93,019 | — | ||||||
Gain on early extinguishment of debt | — | (36,419) | — | (36,419) | ||||||
Loss on sale of assets | — | — | — | 951 | ||||||
Loss on sale of investment | 108,745 | 108,745 | ||||||||
Equity in loss of unconsolidated - AMC | 53,024 | 155,481 | ||||||||
Contract termination and rig stacking | — | — | — | 14,026 | ||||||
Simplification transaction fees | — | — | — | 15,482 | ||||||
Tax effect of reconciling items (1) | (105,508) | (138,097) | (237,170) | (90,163) | ||||||
Other tax items (2) | (47,550) | 24,041 | (2,987) | 17,528 | ||||||
Adjusted Net Income (Loss) | $ | 174,566 | $ | (6,177) | $ | 366,422 | (27,506) | |||
Fully Diluted Shares Outstanding | 317,889 | 300,142 | 316,036 | 306,400 |
Per Share Amounts
Three months ended | Year ended | ||||||||||||
December 31, | December 31, | ||||||||||||
2018 | 2019 | 2018 | 2019 | ||||||||||
Net loss attributable to Antero Resources Corp | $ | (0.39) | $ | (1.61) | $ | (1.26) | (1.13) | ||||||
Commodity derivative fair value losses (gains) | 0.71 | 0.03 | 0.28 | (1.55) | |||||||||
Gains (losses) on settled commodity derivatives | (0.08) | 0.21 | 0.77 | 1.08 | |||||||||
Marketing derivative fair value losses (gains) | — | — | (0.30) | — | |||||||||
(Gains) losses on settled marketing derivatives | (0.02) | — | 0.23 | — | |||||||||
Impairment of oil and gas properties | 0.46 | 0.16 | 1.74 | 4.33 | |||||||||
Impairment of midstream assets | — | — | — | 0.03 | |||||||||
Impairment of equity investments | — | 1.56 | — | 1.56 | |||||||||
Equity-based compensation | 0.03 | 0.01 | 0.16 | 0.07 | |||||||||
Income from water earnout | (0.42) | (0.42) | |||||||||||
Gain on deconsolidation of Antero Midstream | — | — | — | (4.68) | |||||||||
Loss on change in fair value of contingent acquisition consideration | — | — | 0.29 | — | |||||||||
Gain on early extinguishment of debt | 0.34 | (0.12) | — | (0.12) | |||||||||
Loss on sale of assets | — | — | — | — | |||||||||
Loss on sale of investment | — | 0.36 | 0.36 | ||||||||||
Equity in loss of unconsolidated - AMC | — | 0.18 | — | 0.52 | |||||||||
Contract termination and rig stacking | — | — | — | 0.05 | |||||||||
Simplification transaction fees | — | — | — | 0.05 | |||||||||
Tax effect of reconciling items (1) | (0.34) | (0.46) | (0.75) | (0.30) | |||||||||
Other tax items (2) | (0.15) | 0.08 | (0.01) | 0.06 | |||||||||
Adjusted Net Income (Loss) | $ | 0.56 | $ | (0.02) | $ | 1.15 | (0.09) | ||||||
Fully Diluted Shares Outstanding | 317,889 | 300,142 | 316,036 | 306,400 |
(1) | Deferred taxes were approximately 24% for 2018 and 23% for 2019. |
(2) | Tax impact in 2018 of valuation allowance on Colorado net operating losses, changes in statutory tax rate and items effecting the deconsolidated financial statements. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | December 31, | |||||
2018 | 2019 | |||||
AR bank credit facility | $ | 405,000 | $ | 552,000 | ||
AM bank credit facility (1) | 990,000 | — | ||||
5.375% AR senior notes due 2021 | 1,000,000 | 952,500 | ||||
5.125% AR senior notes due 2022 | 1,100,000 | 923,041 | ||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | ||||
5.375% AM senior notes due 2024 (1) | 650,000 | — | ||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | ||||
Net unamortized premium | 1,241 | 791 | ||||
Net unamortized debt issuance costs (1) | (34,553) | (19,464) | ||||
Consolidated total debt | $ | 5,461,688 | 3,758,868 | |||
Less: AR cash and cash equivalents | — | — | ||||
Less: AM cash and cash equivalents (1) | — | — | ||||
Consolidated net debt | $ | 5,461,688 | 3,758,868 | |||
Less: Antero Midstream debt net of cash and unamortized premium and debt issuance costs (1) | $ | 1,632,147 | — | |||
Net Debt | $ | 3,829,541 | $ | 3,758,868 |
(1) Effective March 13, 2019, Antero Midstream is no longer consolidated in Antero's results |
Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, distributions from unconsolidated affiliates and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company's financial performance because it:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
The following table represents a reconciliation of Adjusted EBITDAX to net income (loss), including noncontrolling interest to Adjusted EBITDAX for the periods presented. Adjusted EBITDAX also excludes the results of Antero Midstream in order to provide comparability with the current structure of Antero Resources as Antero Resources no longer consolidates Antero Midstream's results, effective March 13, 2019. These Adjustments are disclosed in the table below as Antero Midstream related adjustments.
Three months ended December 31, | ||||||
(in thousands) | 2018 | 2019 | ||||
Reconciliation of net loss to Adjusted EBITDAX: | ||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ (121,546) | $ | (482,196) | |||
Net income and comprehensive income attributable to noncontrolling interests | 140,282 | — | ||||
Commodity derivative fair value gains (1) | 222,387 | 7,875 | ||||
Gains (losses) on settled commodity derivatives (1) | (25,257) | 63,296 | ||||
Gains on settled marketing derivatives (1) | (5,411) | — | ||||
Interest expense, net | 78,440 | 54,243 | ||||
(Gain) loss on early extinguishment of debt | — | (36,419) | ||||
Provision for income tax expense (benefit) | (131,357) | (107,442) | ||||
Depletion, depreciation, amortization, and accretion | 263,703 | 191,802 | ||||
Impairment of oil and gas properties | 143,369 | 46,732 | ||||
Impairment of equity investments | — | 467,590 | ||||
Exploration expense | 936 | 236 | ||||
Equity-based compensation expense | 13,984 | 4,232 | ||||
Equity in (earnings) loss of unconsolidated affiliate | (12,448) | 53,023 | ||||
Distributions from unconsolidated affiliates | 16,755 | 48,715 | ||||
Loss on sale of equity investment shares | — | 108,745 | ||||
Water earnout | — | (125,000) | ||||
583,837 | 295,432 | |||||
Antero Midstream Related Adjustments (2) | ||||||
Net income and comprehensive income attributable to noncontrolling interests | (140,282) | — | ||||
Antero Midstream interest expense, net (2) | (18,982) | — | ||||
Antero Midstream depreciation, accretion of ARO and accretion of contingent consideration (2) | 82,134 | — | ||||
Antero Midstream equity-based compensation expense (2) | (4,467) | — | ||||
Antero Midstream equity in earnings of unconsolidated affiliates (2) | 12,448 | — | ||||
Antero Midstream distributions from unconsolidated affiliates (2) | (16,755) | — | ||||
Equity in earnings of Antero Midstream (2) | (66,753) | — | ||||
Distributions from Antero Midstream (2) | 43,503 | — | ||||
Adjusted EBITDAX | $ | 474,683 | $ | 295,432 | ||
(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization. |
(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the condensed consolidated financial statements in Antero's Annual Report on Form 10-K for the year ended December 31, 2019 for further discussion on equity method investments. |
The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended December 31, 2019, as used in this release (in thousands):
Twelve months ended | |||||
(in thousands) | December 31, 2019 | ||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (340,129) | |||
Net income and comprehensive income attributable to noncontrolling interests | 46,993 | ||||
Commodity derivative fair value gains (1) | (463,972) | ||||
Losses on settled commodity derivatives (1) | 325,090 | ||||
Loss on sale of assets | 951 | ||||
Gain on deconsolidation of Antero Midstream | (1,406,042) | ||||
Interest expense, net | 228,111 | ||||
Gain on early extinguishment of debt | (36,419) | ||||
Provision for income tax benefit | (74,110) | ||||
Depletion, depreciation, amortization, and accretion | 918,629 | ||||
Impairment of oil and gas properties | 1,300,444 | ||||
Impairment of midstream assets | 14,782 | ||||
Impairment of equity investments | 467,590 | ||||
Exploration expense | 884 | ||||
Equity-based compensation expense | 23,559 | ||||
Equity in loss of unconsolidated affiliate - AMC | 143,216 | ||||
Distributions from unconsolidated affiliates | 157,956 | ||||
Contract termination and rig stacking | 14,026 | ||||
Loss on sale of equity investment shares | 108,745 | ||||
Water earnout | (125,000) | ||||
Simplification transaction fees | 15,482 | ||||
Antero Midstream Related Adjustments (2) | |||||
Net income and comprehensive income attributable to noncontrolling interests | (46,993) | ||||
Antero Midstream interest expense, net (2) | (16,815) | ||||
Antero Midstream loss on extinguishment of debt | (21,770) | ||||
Antero Midstream depreciation, accretion of ARO and accretion of contingent consideration (2) | (6,982) | ||||
Antero Midstream impairment | (2,477) | ||||
Antero Midstream equity-based compensation expense (2) | 12,264 | ||||
Antero Midstream gain on sale (2) | (61,319) | ||||
Antero Midstream equity in earnings of unconsolidated affiliates (2) | (15,021) | ||||
Antero Midstream distributions from unconsolidated affiliates (2) | 95,183 | ||||
Equity in earnings of Antero Midstream (2) | — | ||||
Distributions from Antero Midstream (2) | — | ||||
Antero Midstream simplification transaction fees | (9,185) | ||||
Adjusted EBITDAX | $ | 1,247,671 |
(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization. |
(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the condensed consolidated financial statements in Antero's Annual Report on Form 10-K for the year ended December 31, 2019 for further discussion on equity method investments. |
Drilling and Completion Capital Expenditures
For a reconciliation between cash paid for drilling and completion capital expenditures and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below. (in thousands):
Three months ended December 31, | ||||||
2018 | 2019 | |||||
Drilling and completion costs (as reported; cash basis) | $ | 362,913 | $ | 296,187 | ||
Drilling and completion costs paid to Antero Midstream (cash basis) (1) | 52,385 | — | ||||
Adjusted drilling and completion costs (cash basis) | 415,298 | 296,187 | ||||
Change in accrued capital costs | (36,633) | 3,441 | ||||
Adjusted drilling and completion costs (accrual basis) | $ | 378,665 | $ | 299,628 |
(1) Represents drilling and completion costs paid to Antero Midstream that were consolidated in Antero Resources' financial results in 2018. |
F&D Cost & Pre-Tax PV-10 Value
The pre-tax PV-10 value is a non-GAAP financial measure. Antero believes that the presentation of pre-tax PV-10 is useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). To reconcile to Standardized Measure to pre-tax PV-10, the Company reduces Standardized Measure by the discounted future income taxes associated with the Company's proved reserves. The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2019.
(In millions, except per Mcf data) | ||
At December 31, 2019 | ||
Future net cash flows | $ | 14,932 |
Present value of future net cash flows: | ||
Before income tax (PV-10) | $ | 6,067 |
Income taxes | $ | (598) |
After income tax (Standardized measure) | $ | 5,469 |
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, asset monetization opportunities and pricing, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, the amount and timing of any litigation settlements, and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2019.
ANTERO RESOURCES CORPORATION | ||||||
Consolidated Balance Sheets | ||||||
December 31, 2018 and 2019 | ||||||
(In thousands, except per share amounts) | ||||||
2018 | 2019 | |||||
Assets | ||||||
Current assets: | ||||||
Accounts receivable | $ | 51,073 | 46,419 | |||
Accounts receivable, related parties | — | 125,000 | ||||
Accrued revenue | 474,827 | 317,886 | ||||
Derivative instruments | 245,263 | 422,849 | ||||
Other current assets | 35,450 | 10,731 | ||||
Total current assets | 806,613 | 922,885 | ||||
Property and equipment: | ||||||
Oil and gas properties, at cost (successful efforts method): | ||||||
Unproved properties | 1,767,600 | 1,368,854 | ||||
Proved properties | 12,705,672 | 11,859,817 | ||||
Water handling and treatment systems | 1,013,818 | — | ||||
Gathering systems and facilities | 2,470,708 | 5,802 | ||||
Other property and equipment | 65,842 | 71,895 | ||||
18,023,640 | 13,306,368 | |||||
Less accumulated depletion, depreciation, and amortization | (4,153,725) | (3,327,629) | ||||
Property and equipment, net | 13,869,915 | 9,978,739 | ||||
Operating leases right-of-use assets | — | 2,886,500 | ||||
Derivative instruments | 362,169 | 333,174 | ||||
Investments in unconsolidated affiliates | 433,642 | 1,055,177 | ||||
Other assets | 47,125 | 21,094 | ||||
Total assets | $ | 15,519,464 | 15,197,569 | |||
Liabilities and Equity | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 66,289 | 14,498 | |||
Accounts payable, related parties | — | 97,883 | ||||
Accrued liabilities | 465,070 | 400,850 | ||||
Revenue distributions payable | 310,827 | 207,988 | ||||
Derivative instruments | 532 | 6,721 | ||||
Short-term lease liabilities | 2,459 | 305,320 | ||||
Other current liabilities | 8,363 | 6,879 | ||||
Total current liabilities | 853,540 | 1,040,139 | ||||
Long-term liabilities: | ||||||
Long-term debt | 5,461,688 | 3,758,868 | ||||
Deferred income tax liability | 650,788 | 781,987 | ||||
Derivative instruments | — | 3,519 | ||||
Long-term lease liabilities | 2,873 | 2,583,678 | ||||
Other liabilities | 63,098 | 58,635 | ||||
Total liabilities | 7,031,987 | 8,226,826 | ||||
Commitments and contingencies (Notes 14 and 15) | ||||||
Equity: | ||||||
Stockholders' equity: | ||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 308,594 shares and 295,941 shares issued and outstanding at December 31, 2018 and 2019, respectively | 3,086 | 2,959 | ||||
Additional paid-in capital | 6,485,174 | 6,130,365 | ||||
Accumulated earnings | 1,177,548 | 837,419 | ||||
Total stockholders' equity | 7,665,808 | 6,970,743 | ||||
Noncontrolling interests in consolidated subsidiary | 821,669 | — | ||||
Total equity | 8,487,477 | 6,970,743 | ||||
Total liabilities and equity | $ | 15,519,464 | 15,197,569 |
ANTERO RESOURCES CORPORATION | ||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | ||||||||||||
Three Months and Years Ended December 31, 2018 and 2019 | ||||||||||||
(In thousands, except per share amounts) | ||||||||||||
Three Months Ended December 31, | Year Ended December 31, | |||||||||||
2018 | 2019 | 2018 | 2019 | |||||||||
Revenue and other: | ||||||||||||
Natural gas sales | $ | 789,614 | 512,076 | $ | 2,287,939 | 2,247,162 | ||||||
Natural gas liquids sales | 349,353 | 316,556 | 1,177,777 | 1,219,162 | ||||||||
Oil sales | 58,310 | 39,874 | 187,178 | 177,549 | ||||||||
Commodity derivative fair value gains (losses) | (222,386) | (7,875) | (87,594) | 463,972 | ||||||||
Gathering, compression, water handling and treatment | 6,047 | — | 21,344 | 4,478 | ||||||||
Marketing | 64,712 | 91,296 | 458,901 | 292,207 | ||||||||
Marketing derivative fair value gains (losses) | (1) | — | 94,081 | — | ||||||||
Other income | — | 811 | — | 4,160 | ||||||||
Total revenue and other | 1,045,649 | 952,738 | 4,139,626 | 4,408,690 | ||||||||
Operating expenses: | — | |||||||||||
Lease operating | 42,998 | 27,203 | 136,153 | 145,720 | ||||||||
Gathering, compression, processing, and transportation | 413,130 | 551,424 | 1,339,358 | 2,146,647 | ||||||||
Production and ad valorem taxes | 44,242 | 29,633 | 126,474 | 125,142 | ||||||||
Marketing | 125,132 | 140,975 | 686,055 | 549,814 | ||||||||
Exploration | 936 | 236 | 4,958 | 884 | ||||||||
Impairment of oil and gas properties | 143,370 | 46,732 | 549,437 | 1,300,444 | ||||||||
Impairment of midstream assets | — | 14,782 | 9,658 | 14,782 | ||||||||
Depletion, depreciation, and amortization | 262,985 | 190,861 | 972,465 | 914,867 | ||||||||
Loss on sale of assets | — | — | — | 951 | ||||||||
Accretion of asset retirement obligations | 719 | 941 | 2,819 | 3,762 | ||||||||
General and administrative (including equity-based compensation expense ) | 58,767 | 32,189 | 240,344 | 178,696 | ||||||||
Contract termination and rig stacking | — | — | — | 14,026 | ||||||||
Total operating expenses | 1,092,279 | 1,034,976 | 4,067,721 | 5,395,735 | ||||||||
Operating income (loss) | (46,630) | (82,238) | 71,905 | (987,045) | ||||||||
Other income (expenses): | — | |||||||||||
Water earnout | — | 125,000 | — | 125,000 | ||||||||
Equity in earnings (loss) of unconsolidated affiliates | 12,449 | (53,023) | 40,280 | (143,216) | ||||||||
Loss on the sale of equity investment shares | — | (108,745) | — | (108,745) | ||||||||
Impairment of equity investments | — | (467,590) | — | (467,590) | ||||||||
Gain on deconsolidation of Antero Midstream Partners LP | — | — | — | 1,406,042 | ||||||||
Interest expense, net | (78,440) | (54,243) | (286,743) | (228,111) | ||||||||
Gain (loss) on early extinguishment of debt | — | 36,419 | — | 36,419 | ||||||||
Total other income (expenses) | (65,991) | (522,182) | (246,463) | 619,799 | ||||||||
Loss before income taxes | (112,621) | (589,638) | (174,558) | (367,246) | ||||||||
Provision for income tax benefit | 131,357 | 107,442 | 128,857 | 74,110 | ||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | 18,736 | (482,196) | (45,701) | (293,136) | ||||||||
Net income and comprehensive income attributable to noncontrolling interests | 140,282 | — | 351,816 | 46,993 | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (121,546) | (482,196) | $ | (397,517) | (340,129) | ||||||
Income (loss) per common share—basic | $ | (0.39) | (1.61) | $ | (1.26) | (1.11) | ||||||
Income (loss) per common share—assuming dilution | $ | (0.39) | (1.61) | $ | (1.26) | (1.11) | ||||||
Weighted average number of shares outstanding: | ||||||||||||
Basic | 313,618 | 300,142 | 316,036 | 306,400 | ||||||||
Diluted | 313,618 | 300,142 | 316,036 | 306,400 |
ANTERO RESOURCES CORPORATION | |||||||||
Condensed Consolidated Statements of Cash Flows | |||||||||
Years Ended December 31, 2017, 2018 and 2019 | |||||||||
(Unaudited) | |||||||||
(In thousands) | |||||||||
Year Ended December 31, | |||||||||
2017 | 2018 | 2019 | |||||||
Cash flows provided by (used in) operating activities: | |||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | $ | 785,137 | (45,701) | (293,136) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||
Depletion, depreciation, amortization, and accretion | 827,220 | 975,284 | 918,629 | ||||||
Impairments | 183,029 | 559,095 | 1,782,816 | ||||||
Commodity derivative fair value (gains) losses | (658,283) | 87,594 | (463,972) | ||||||
Gains on settled commodity derivatives | 213,940 | 243,112 | 325,090 | ||||||
Premium paid on derivative contracts | — | (13,318) | — | ||||||
Proceeds from derivative monetizations | 749,906 | 370,365 | — | ||||||
Marketing derivative fair value gains | 21,394 | (94,081) | — | ||||||
Gains on settled marketing derivatives | — | 72,687 | — | ||||||
Deferred income tax benefit | (295,126) | (128,857) | (79,158) | ||||||
Loss on sale of assets | — | — | 951 | ||||||
Equity-based compensation expense | 103,445 | 70,414 | 23,559 | ||||||
Loss (gain) on early extinguishment of debt | 1,500 | — | (36,419) | ||||||
Loss on sale of Antero Midstream Corporation shares | — | — | 108,745 | ||||||
Equity in earnings (loss) of unconsolidated affiliates | (20,194) | (40,280) | 143,216 | ||||||
Water earnout | — | — | (125,000) | ||||||
Distributions/dividends of earnings from unconsolidated affiliates | 20,195 | 46,415 | 157,956 | ||||||
Gain on deconsolidation of Antero Midstream Partners LP | — | — | (1,406,042) | ||||||
Other | (1,907) | 4,681 | 10,681 | ||||||
Changes in current assets and liabilities: | |||||||||
Accounts receivable | (5,214) | (15,156) | 31,631 | ||||||
Accrued revenue | (38,162) | (174,706) | 156,941 | ||||||
Other current assets | (2,755) | (5,817) | (1,025) | ||||||
Accounts payable including related parties | 9,462 | 9,307 | (27,996) | ||||||
Accrued liabilities | 64,862 | 63,562 | (25,762) | ||||||
Revenue distributions payable | 45,628 | 101,210 | (102,839) | ||||||
Other current liabilities | 2,214 | (3,823) | 4,592 | ||||||
Net cash provided by operating activities | 2,006,291 | 2,081,987 | 1,103,458 | ||||||
Cash flows provided by (used in) investing activities: | |||||||||
Additions to proved properties | (175,650) | — | — | ||||||
Additions to unproved properties | (204,272) | (172,387) | (88,682) | ||||||
Drilling and completion costs | (1,281,985) | (1,488,573) | (1,254,118) | ||||||
Additions to water handling and treatment systems | (194,502) | (97,699) | (24,416) | ||||||
Additions to gathering systems and facilities | (346,217) | (444,413) | (48,239) | ||||||
Additions to other property and equipment | (14,127) | (7,514) | (6,700) | ||||||
Investments in unconsolidated affiliates | (235,004) | (136,475) | (25,020) | ||||||
Proceeds from sale of common stock of Antero Midstream Corporation | — | — | 100,000 | ||||||
Proceeds from the Antero Midstream Partners LP Transactions | — | — | 296,611 | ||||||
Change in other assets | (12,029) | (3,663) | 7,091 | ||||||
Proceeds from asset sales | 2,156 | — | 1,983 | ||||||
Net cash used in investing activities | (2,461,630) | (2,350,724) | (1,041,490) | ||||||
Cash flows provided by (used in) financing activities: | |||||||||
Issuance of common units by Antero Midstream Partners LP | 248,956 | — | — | ||||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation | 311,100 | — | — | ||||||
Repurchases of common stock | — | (129,084) | (38,772) | ||||||
Issuance of senior notes by Antero Midstream Partners LP | — | — | 650,000 | ||||||
Repayment of senior notes | — | — | (191,092) | ||||||
Borrowings on bank credit facilities, net | 90,000 | 660,379 | 232,000 | ||||||
Payments of deferred financing costs | (16,377) | (2,169) | (4,547) | ||||||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (152,352) | (267,271) | (85,076) | ||||||
Employee tax withholding for settlement of equity compensation awards | (24,174) | (17,020) | (2,389) | ||||||
Other | (4,983) | (4,539) | (2,560) | ||||||
Net cash provided by financing activities | 452,170 | 240,296 | 557,564 | ||||||
Antero Midstream Partners LP cash at deconsolidation | — | — | (619,532) | ||||||
Net decrease in cash and cash equivalents | (3,169) | (28,441) | — | ||||||
Cash and cash equivalents, beginning of period | 31,610 | 28,441 | — | ||||||
Cash and cash equivalents, end of period | $ | 28,441 | — | — | |||||
Year Ended December 31, | |||||||||
2017 | 2018 | 2019 | |||||||
Supplemental disclosure of cash flow information: | |||||||||
Cash paid during the period for interest | $ | 263,919 | 275,769 | 224,331 | |||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment | $ | (547) | (47,717) | (15,897) |
The following table set forth selected operating data for the three months ended December 31, 2018 and 2019: | ||||||||||||
Three months ended December 31, | Amount of Increase | Percent | ||||||||||
(in thousands) | 2018 | 2019 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 789,614 | $ | 512,076 | $ | (277,538) | (35) | % | ||||
NGLs sales | 349,353 | 316,556 | (32,797) | (9) | % | |||||||
Oil sales | 58,310 | 39,874 | (18,436) | (32) | % | |||||||
Commodity derivative fair value gains (losses) | (22,386) | (7,875) | 14,511 | (65) | % | |||||||
Gathering, compression, water handling and treatment | 6,047 | — | (6,047) | (100) | % | |||||||
Marketing | 64,712 | 91,296 | 26,584 | 41 | % | |||||||
Other income | (1) | 811 | 812 | * | ||||||||
Total operating revenues and other | 1,045,649 | 952,738 | (92,911) | (9) | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 42,998 | 27,203 | (15,795) | (37) | % | |||||||
Gathering, compression, processing, and transportation | 413,130 | 551,424 | 138,294 | 33 | % | |||||||
Production and ad valorem taxes | 44,242 | 29,633 | (14,609) | (33) | % | |||||||
Marketing | 125,132 | 140,975 | 15,843 | 13 | % | |||||||
Exploration | 936 | 236 | (700) | (75) | % | |||||||
Impairment of oil and gas properties | 143,370 | 46,732 | (96,638) | (67) | % | |||||||
Impairment of midstream assets | — | 14,782 | 14,782 | * | ||||||||
Depletion, depreciation, and amortization | 262,985 | 190,861 | (72,124) | (27) | % | |||||||
Accretion of asset retirement obligations | 719 | 941 | 222 | 31 | % | |||||||
General and administrative (excluding equity-based compensation) | 44,782 | 27,957 | (16,825) | (38) | % | |||||||
Equity-based compensation | 13,985 | 4,232 | (9,753) | (70) | % | |||||||
Total operating expenses | 1,092,279 | 1,034,976 | (57,303) | (5) | % | |||||||
Operating income (loss) | (46,630) | (82,238) | (35,608) | 76 | % | |||||||
Other earnings (expenses): | ||||||||||||
Water earnout | — | 125,000 | (125,000) | * | ||||||||
Equity in earnings of unconsolidated affiliates | 12,449 | (53,023) | (65,472) | (526) | % | |||||||
Loss on the sale of equity investment shares | — | (108,745) | (108,745) | * | ||||||||
Impairment of equity investments | — | (467,590) | 467,590 | * | ||||||||
Interest expense | (78,440) | (54,243) | 24,197 | (31) | % | |||||||
Gain on early extinguishment of debt | — | 36,419 | 36,419 | * | ||||||||
Total other expenses | (65,991) | (522,182) | (456,191) | 691 | % | |||||||
Loss before income taxes | (112,621) | (604,420) | (491,799) | 437 | % | |||||||
Income tax benefit | 131,357 | 107,442 | (23,915) | * | ||||||||
Net loss and comprehensive loss including noncontrolling interest | 18,736 | (496,978) | (515,714) | * | ||||||||
Net income and comprehensive income attributable to noncontrolling interest | 140,282 | — | (140,282) | (100) | % | |||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (121,546) | $ | (496,978) | (375,432) | 309 | % | |||||
— | ||||||||||||
Adjusted EBITDAX | $ | 456,722 | $ | 295,728 | $ | (160,994) | (35) | % |
The following table set forth selected operating data for the three months ended December 31, 2018 and 2019: | ||||||||||||
Three months ended December 31, | Amount of Increase | Percent | ||||||||||
2018 | 2019 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 206 | 205 | (1) | (0) | % | |||||||
C2 Ethane (MBbl) | 4,323 | 4,325 | 2 | 0 | % | |||||||
C3+ NGLs (MBbl) | 9,463 | 9,603 | 140 | 1 | % | |||||||
Oil (MBbl) | 1,125 | 809 | (316) | (28) | % | |||||||
Combined (Bcfe) | 296 | 293 | (3) | (1) | % | |||||||
Daily combined production (MMcfe/d) | 3,213 | 3,185 | (28) | (1) | % | |||||||
Average prices before effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) (2) | $ | 3.83 | $ | 2.50 | $ | (1.33) | (35) | % | ||||
C2 Ethane (per Bbl) | $ | 13.12 | $ | 7.44 | $ | (5.68) | (43) | % | ||||
C3+ NGLs (per Bbl) | $ | 30.92 | $ | 29.61 | $ | (1.31) | (4) | % | ||||
Oil (per Bbl) | $ | 51.83 | $ | 49.29 | $ | (2.54) | (5) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 4.05 | $ | 2.96 | $ | (1.09) | (27) | % | ||||
Average realized prices after effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) | $ | 3.73 | $ | 2.87 | $ | (0.86) | (23) | % | ||||
C2 Ethane (per Bbl) | $ | 13.12 | $ | 7.44 | $ | (5.68) | (43) | % | ||||
C3+ NGLs (per Bbl) | $ | 30.60 | $ | 27.95 | $ | (2.65) | (9) | % | ||||
Oil (per Bbl) | $ | 50.92 | $ | 53.57 | $ | 2.65 | 5 | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.97 | $ | 3.18 | $ | (0.79) | (20) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.15 | $ | 0.09 | $ | (0.06) | (40) | % | ||||
Gathering, compression, processing, and transportation | $ | 1.88 | $ | 1.88 | $ | — | — | % | ||||
Production and ad valorem taxes | $ | 0.15 | $ | 0.10 | $ | (0.05) | (33) | % | ||||
Marketing expense, net | $ | 0.20 | $ | 0.17 | $ | (0.03) | (15) | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.82 | $ | 0.65 | $ | (0.17) | (21) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.11 | $ | 0.10 | $ | (0.01) | (9) | % | ||||
Year ended December 31, | Amount of Increase | Percent | ||||||||||
(in thousands) | 2018 | 2019 | (Decrease) | Change | ||||||||
Operating revenues and other: | ||||||||||||
Natural gas sales | $ | 2,287,939 | $ | 2,247,162 | $ | (40,777) | (2) | % | ||||
NGLs sales | 1,177,777 | 1,219,162 | 41,385 | 4 | % | |||||||
Oil sales | 187,178 | 177,549 | (9,629) | (5) | % | |||||||
Commodity derivative fair value gains (losses) | (87,594) | 463,972 | 551,566 | (630) | % | |||||||
Gathering, compression, water handling and treatment | 21,344 | 4,478 | (16,866) | (79) | % | |||||||
Marketing | 458,901 | 292,207 | (166,694) | (36) | % | |||||||
Marketing derivative fair value gains | 94,081 | — | (94,081) | (100) | % | |||||||
Other income | — | 4,160 | 4,160 | * | ||||||||
Total operating revenues and other | 4,139,626 | 4,408,690 | 269,064 | 6 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 136,153 | 145,720 | 9,567 | 7 | % | |||||||
Gathering, compression, processing, and transportation | 1,339,358 | 2,146,647 | 807,289 | 60 | % | |||||||
Water earnout | — | (125,000) | (125,000) | * | ||||||||
Production and ad valorem taxes | 126,474 | 125,142 | (1,332) | (1) | % | |||||||
Marketing | 686,055 | 549,814 | (136,241) | (20) | % | |||||||
Exploration | 4,958 | 884 | (4,074) | (82) | % | |||||||
Impairment of oil and gas properties | 549,437 | 1,300,444 | 751,007 | 137 | % | |||||||
Impairment of midstream assets | 9,658 | 14,782 | 5,124 | 53 | % | |||||||
Depletion, depreciation, and amortization | 972,465 | 914,867 | (57,598) | (6) | % | |||||||
Loss on sale of assets | — | 951 | 951 | * | ||||||||
Accretion of asset retirement obligations | 2,819 | 3,762 | 943 | 33 | % | |||||||
General and administrative (excluding equity-based compensation) | 169,930 | 155,137 | (14,793) | (9) | % | |||||||
Equity-based compensation | 70,414 | 23,559 | (46,855) | (67) | % | |||||||
Contract termination and rig stacking | — | 14,026 | 14,026 | * | ||||||||
Total operating expenses | 4,067,721 | 5,270,735 | 1,203,014 | 30 | % | |||||||
Operating income (loss) | 71,905 | (862,045) | (933,950) | (1,299) | % | |||||||
Other earnings (expenses): | ||||||||||||
Water earnout | — | 125,000 | 125,000 | * | ||||||||
Equity in earnings of unconsolidated affiliates | 40,280 | (143,216) | (183,496) | (456) | ||||||||
Loss on the sale of equity investment shares | — | (108,745) | (108,745) | * | ||||||||
Gain on deconsolidation of Antero Midstream Partners LP | — | 1,406,042 | 1,406,042 | * | ||||||||
Impairment of equity investments | — | (467,590) | (467,590) | * | ||||||||
Interest expense | (286,743) | (228,111) | 58,632 | (20) | ||||||||
Gain on early extinguishment of debt | — | 36,419 | 36,419 | * | ||||||||
Total other expenses | (246,463) | 494,799 | 741,262 | (301) | % | |||||||
Loss before income taxes | (174,558) | (367,246) | (192,688) | 110 | % | |||||||
Income tax benefit | 128,857 | 74,110 | (54,747) | (42) | % | |||||||
Net loss and comprehensive loss including noncontrolling interest | (45,701) | (293,136) | (247,435) | 541 | % | |||||||
Net income and comprehensive income attributable to noncontrolling interest | 351,816 | 46,993 | (304,823) | (87) | % | |||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (397,517) | $ | (340,129) | $ | 57,388 | (14) | % | ||||
Adjusted EBITDAX | $ | 1,717,120 | $ | 1,247,967 | $ | (469,153) | (27) | % | ||||
Year ended December 31, | Amount of Increase | Percent | ||||||||||
2018 | 2019 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 710 | 822 | 112 | 16 | % | |||||||
C2 Ethane (MBbl) | 14,221 | 15,861 | 1,640 | 12 | % | |||||||
C3+ NGLs (MBbl) | 28,913 | 39,445 | 10,532 | 36 | % | |||||||
Oil (MBbl) | 3,265 | 3,632 | 367 | 11 | % | |||||||
Combined (Bcfe) | 989 | 1,175 | 186 | 19 | % | |||||||
Daily combined production (MMcfe/d) | 2,709 | 3,220 | 511 | 19 | % | |||||||
Average prices before effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) (2) | $ | 3.22 | $ | 2.74 | $ | (0.48) | (15) | % | ||||
C2 Ethane (per Bbl) | $ | 12.14 | $ | 7.85 | $ | (4.29) | (35) | % | ||||
C3+ NGLs (per Bbl) | $ | 34.76 | $ | 27.75 | $ | (7.01) | (20) | % | ||||
Oil (per Bbl) | $ | 57.34 | $ | 48.88 | $ | (8.46) | (15) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.69 | $ | 3.10 | $ | (0.59) | (16) | % | ||||
Average realized prices after effects of derivative settlements (1): | ||||||||||||
Natural gas (per Mcf) | $ | 3.65 | $ | 3.14 | $ | (0.51) | (14) | % | ||||
C2 Ethane (per Bbl) | $ | 12.14 | $ | 7.85 | $ | (4.29) | (35) | % | ||||
C3+ NGLs (per Bbl) | $ | 33.25 | $ | 27.41 | $ | (5.84) | (18) | % | ||||
Oil (per Bbl) | $ | 52.11 | $ | 50.92 | $ | (1.19) | (2) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.94 | $ | 3.38 | $ | (0.56) | (14) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.14 | $ | 0.13 | $ | (0.01) | (7) | % | ||||
Gathering, compression, processing, and transportation | $ | 1.81 | $ | 1.92 | $ | 0.11 | 6 | % | ||||
Production and ad valorem taxes | $ | 0.12 | $ | 0.11 | $ | (0.01) | (8) | % | ||||
Marketing expense (gain), net | $ | 0.23 | $ | 0.22 | $ | (0.01) | (4) | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.85 | $ | 0.76 | $ | (0.09) | (11) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.13 | $ | 0.12 | $ | (0.01) | (8) | % |
View original content to download multimedia:http://www.prnewswire.com/news-releases/antero-resources-reports-fourth-quarter-and-full-year-2019-results-and-announces-2020-guidance-and-proved-reserves-301004031.html
SOURCE Antero Resources Corporation
DENVER, Jan. 15, 2020 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its fourth quarter and full year 2019 earnings release on Wednesday, February 12, 2020 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, February 13, 2020 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Thursday, February 20, 2020 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13693463. To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 20, 2020 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
View original content to download multimedia:http://www.prnewswire.com/news-releases/antero-resources-announces-fourth-quarter-and-full-year-2019-earnings-release-date-and-conference-call-300987829.html
SOURCE Antero Resources Corporation
DENVER, Dec. 9, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced that it has entered into agreements expected to reduce its gathering, processing and transportation costs by approximately $350 million over the next four years. The agreements include a growth incentive fee program with Antero Midstream Corporation ("Antero Midstream" or "AM") that aligns with the Company's current 8% to 10% compound annual production growth plan through 2021 and additional agreements with other third party midstream providers. Antero Resources also announced commencement of an asset sale program targeting $750 million to $1 billion in proceeds to be completed in 2020. The asset sale program was initiated with a $100 million sale of AM shares to Antero Midstream. The amendment to the gathering agreement and the share repurchase with Antero Midstream were negotiated and recommended by the Conflicts Committees of Antero Midstream and Antero Resources and approved by both Boards of Directors.
Highlights Include:
Commenting on the announcements, Paul Rady, Chairman and CEO said, "The midstream fee reductions further demonstrate our ongoing commitment to reducing Antero's cost structure. In aggregate with the previously disclosed $300 million well cost and operating cost savings, we are now targeting a $375 million overall reduction in Antero's capital and operating costs in 2020 as compared to previous expectations. These cost savings further support our moderate growth strategy as we fill the majority of our premium firm transportation commitments by 2022. With these cost savings we now project being free cash flow neutral in 2020 and 2021 combined, and sustained positive free cash flow in 2022 and thereafter, assuming current strip pricing."
Commenting on the asset sale program, Glen Warren, President and CFO said "Antero is in the advantageous position of having a variety of options available for asset monetizations. These options include undeveloped leasehold, minerals, producing properties, an extensive hedge book and midstream ownership. The proceeds of asset sales will be used for debt reduction. Meeting the asset sale target is expected to result in a low 2-times leverage and robust liquidity of approximately $2.3 billion by year-end 2020, assuming no further senior note repurchases."
Gathering, Processing and Transportation Costs
Through negotiations with Antero Midstream and other third party midstream providers, Antero Resources has entered into agreements expected to reduce its gathering, processing and transportation costs "GP&T" and net marketing expense by a combined $350 million in aggregate in the 2020 through 2023 period. As a result of these reductions and production growth into a portion of its unutilized firm transportation, Antero expects its GP&T and net marketing expense to be reduced by a combined $0.10 per Mcfe in 2020.
Under the new amendment to the gathering agreement with Antero Midstream, low pressure gathering fees from January 1, 2020 through December 31, 2023 will be reduced based on Antero Resources achieving increasing volumetric targets on low pressure volumes gathered by Antero Midstream. The growth incentive thresholds were structured in a manner that aligns with Antero Resources' plan to grow 8% to 10% through 2021 in order to fill its premium firm transportation portfolio and invest at maintenance capital levels thereafter. The amendment also extended the term of the agreement by an additional four years to 2038. There are no incremental minimum volume commitments associated with this agreement.
Asset Sale Summary
Antero Resources is targeting $750 million to $1 billion of asset sales to be completed in 2020. Assets under consideration include lease acreage, minerals, producing properties, hedge portfolio restructuring and Antero Midstream shares. Antero Resources has 584,000 net acres of leasehold in the Appalachian Basin with an 84% average net revenue interest. The Company also holds 5,000 net mineral acres with an average royalty of 16%. The company had net production of 3.4 Bcfe/d in the third quarter of 2019 and had 10.4 Tcfe of proved developed producing reserves as of December 31, 2018. The Company's mark-to-market hedge value was $780 million as of December 6, 2019.
The company initiated the asset sale program through the agreed sale of $100 million of Antero Midstream common stock to Antero Midstream. The number of shares sold will be based on a formulaic pricing mechanism taking into account both historical and future market pricing of Antero Midstream shares. Prior to the $100 million sale, the market value of Antero Resources' ownership of Antero Midstream was $715 million, based on the December 6, 2019 closing price. Proceeds from the sale of the Antero Midstream shares will be used to reduce borrowings under the Company's revolver that were incurred in recent senior note repurchases. Antero Midstream also announced that it has $175 million of capacity remaining under its share repurchase program that could be used to repurchase additional Antero Midstream shares held by the Company.
Debt Repurchase
Antero repurchased $215 million notional amount of debt during the fourth quarter at a 17% weighted average discount price. The debt repurchase program occurred under a 10b5-1 plan and included the 2021 senior notes, but focused primarily on the 2022 senior notes. Following the repurchases, Antero's pro forma debt was reduced by $37 million and net interest expense was reduced by over $5 million on an annualized basis.
Glen Warren, CFO and President of Antero Resources said, "The midstream fee reductions announced today combined with the improvement in NGL prices and outlook during the quarter has resulted in a free cash flow neutral profile through 2021 and positions Antero to generate positive free cash flow on a sustained basis beginning in 2022. The asset sale program is expected to meaningfully reduce debt and result in low 2-times leverage by the end of 2020. Today's announcement significantly enhances our credit profile which remains strong with $1.6 billion of liquidity following the bond repurchases and a $1.9 billion borrowing base cushion above the $2.6 billion of lender commitments."
Financial and Legal Advisors
Goldman Sachs and Co. LLC and Richards, Layton, and Finger acted as financial and legal advisors, respectively, to the Conflicts Committee of Antero Midstream. Baird and Potter, Anderson, and Corroon acted as financial and legal advisors, respectively, to the Conflicts Committee of Antero Resources.
Non-GAAP Financial Measures
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company's financial performance because it:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
The Company has not provided projected net income or a reconciliation of projected Adjusted EBITDAX to projected net income, the most comparable financial measure calculated in accordance with GAAP, because the Company does not provide guidance with respect to income tax expense, depletion and depreciation expense or the revenue impact of changes in the projected fair value of derivative instruments prior to settlement. Therefore, projected net income and a reconciliation of projected adjusted EBITDA to projected net income, are not available without unreasonable effort.
Free Cash Flow
Free Cash Flow as presented in this release and defined by the Company represents Cash Flow from Operations, less drilling and completion capital and leasehold capital. Free Cash Flow includes the $125 million earnout payment expected from Antero Midstream in 2020 associated with the water drop down transaction that occurred in 2015.
Free Cash Flow is a useful indicator of the Company's ability to internally fund its activities and to service or incur additional debt. There are significant limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
The Company has not provided projected Cash Flow from Operations or reconciliations of Free Cash Flow to projected Cash Flow from Operations, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Cash Flow from Operations for any future period because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to project these timing differences with any reasonable degree of accuracy without unreasonable efforts.
However, Antero is able to forecast Drilling and Completion capital and leasehold capital, each of which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. Antero is targeting Drilling and Completion Capital of $1.15 Billion to $1.2 Billion in each of 2020 and 2021. For leasehold capital, Antero is targeting $50 million in 2020.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, realizing potential future fee rebates or reductions, including those related to certain levels of production, future earnings, leverage targets and debt repayment, future capital spending plans, asset monetization opportunities and pricing, improved and/or increasing capital efficiency, estimated realized natural gas, NGL and oil prices, expected drilling and development plans, projected well costs and cost savings initiatives, future financial position, future marketing opportunities, and expectations regarding the amount and timing of jury awards, the receipt of which are subject to final orders and the resolutions of appeals processes, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero Resources expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero Resources' control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2018.
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SOURCE Antero Resources Corporation
DENVER, Oct. 29, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero," "Antero Resources," or the "Company") today released its third quarter 2019 financial and operational results. The relevant condensed consolidated and condensed consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, which has been filed with the Securities and Exchange Commission ("SEC").
Third Quarter 2019 Highlights Include:
2019 Outlook Update:
(1) South Jersey Gas Company and South Jersey Resources Group, LLC collectively, "South Jersey".
Paul Rady, Chairman and CEO said, "Antero made substantial progress during the quarter towards lowering its overall cost structure. Driven by our well cost reduction initiatives, we recorded our lowest drilling and completion capital in a given quarter since our IPO in 2013. Importantly, these savings led to a 4% reduction in our 2019 capital budget and a $100 million reduction since our initial 2019 budget announcement. Despite this reduced capital budget we have increased our 2019 production guidance, a testament to the capital efficiency of our operations. As a result of our water savings initiatives, particularly the blending of our flowback and produced water, third quarter lease operating expenses per Mcfe declined 21% from the first half of this year as well. We expect these costs to decline an additional 15% by 2020.
Mr. Rady continued "During the quarter, we also released a meaningful portion of our unutilized firm transportation capacity to third parties, which contributed to a 22% reduction in net marketing expenses compared to the first half of the year. These capacity releases are expected to result in lower net marketing expenses than expected in 2020. General and administrative costs per Mcfe have also declined by 25% since the first half of this year and we are targeting a further 10% reduction by mid-2020. In the aggregate, these capital and expense reductions will create meaningful shareholder value over the long-term and are especially important in this low commodity price environment."
Recent Developments
Well Cost Savings Update
Antero's drilling and completion capital expenditures declined to $290 million during third quarter of 2019. The reduced capital spending during the quarter showcased capital efficiency gains previously outlined that are trending ahead of schedule. Some of the key contributions were (i) localized water blending operations that reduced flowback water costs by reducing trucking costs and (ii) the use of lower volumes of fresh water per foot in approximately 20% of stages completed during the quarter. Additionally, Antero continued to see operational efficiency gains during the third quarter. Completion stages per day exceeded 6 stages per day in August and September, an increase from 5.7 stages per day during the second quarter as lower water volume completions accelerated cycle times. The Company expects further well cost savings moving forward as it transitions to using less water on all completions by 2020 and moves towards blending nearly all flowback and produced water from the Company's Marcellus wells.
Well costs are currently averaging $895 per foot, with a similar level projected for the fourth quarter of 2019. This is 4% below Antero's previously stated second half 2019 target of $930 per foot. First quarter 2020 well costs are now expected to average $880 per foot, and the full year 2020 target range is $830 to $870 per foot.
Net Marketing Expense Mitigation
Antero recently entered into release capacity agreements to mitigate some of its excess firm transportation expenses. For the September 2019 through March 2020 period, the Company has released 250 MMcf/d of excess firm transportation capacity to third parties. Antero estimates that the release will result in a $15 million reduction in net marketing expenses during the seven month period than otherwise expected. Antero continues to see opportunities to monetize some of its excess firm transportation capacity, driven by the recent widening of local basis and attractive spreads to the Midwest and Gulf Coast. Antero's gross production is expected to fill essentially all of its premium transportation capacity by 2022.
Lease Operating Expense Reduction Update
Antero's lease operating expenses during the third quarter of 2019 were $36 million, or $0.12 per Mcfe. This represents a $0.03 per Mcfe or 21% reduction from the first half of 2019. Produced water costs represent approximately 80% of Antero's lease operating expenses. Antero was able to achieve these significant cost savings primarily due to a combination of localized blending, which began in August, and the shifting of wastewater away from the Antero Clearwater Facility in September to a combination of blending and injection. Recently, Antero has begun recycling up to 100% of its produced and flowback water by blending with fresh water for reuse in completions. Given these initiatives were only implemented during a portion of the third quarter, Antero expects to see further lease operating expense savings moving in the fourth quarter and into 2020.
For the fourth quarter of 2019, Antero expects to blend approximately 40 MBbl/d of flowback and produced water for completions, an increase from 10 MBbl/d in the third quarter. This increase in blending operations combined with reduced trucking distances and lower negotiated trucking rates is projected to result in a $4.00 per Bbl decrease in water handling expense related to lease operating expenses as compared to the beginning of 2019. Following the idling of the Antero Clearwater Facility, water fees including trucking costs averaged $6.00 per Bbl, as compared to $10.13 per Bbl during the second quarter of 2019. Antero is forecasting lease operating expenses to be further reduced to $0.10 per Mcfe in the fourth quarter of 2019, a 31% reduction from the first half of 2019 and a 16% reduction from the third quarter.
General & Administrative Cost Savings Update
Antero recently launched a cost savings initiative targeting a 10% reduction to general and administrative expenses by mid-2020. The Company plans to reduce general and administrative costs through a combination of headcount reductions completed earlier this year, natural employee attrition and a reduction across the board in general and administrative expenses.
2019 Guidance Update
2019 – Prior | 2019 – New | |||||||||
Low | High | Low | High | |||||||
Net Production (Bcfe/d) | 3.15 – 3.25 | 3.25 | ||||||||
Natural Gas Realized Price Differential to NYMEX ($/Mcf) | $0.10 – $0.15 Premium | $0.05 – $0.10 Premium | ||||||||
Net Marketing Expense ($/Mcfe) | $0.225 – $0.25 | $0.21 – $0.23 | ||||||||
D&C Capital Expenditures ($MM) | $1,300 – $1,375 | $1,275 – $1,300 |
Drilling and Completion Capital
Based on well cost savings achieved to date, Antero has reduced its 2019 drilling and completion capital to a range of $1.275 to $1.3 billion, a 4% reduction at the midpoint from the previous range of $1.3 to $1.375 billion.
Production Guidance
Driven by continued strong well performance throughout 2019, Antero is increasing its full year production guidance to the high end of the range or approximately 3.25 Bcfe/d, a 2% increase from the midpoint of the prior range of 3.15 to 3.25 Bcfe/d.
Net Marketing Expense
As a result of the successful mitigation efforts, Antero is decreasing its net marketing expense guidance for 2019 to a range of $0.21 to $0.23 per Mcfe, as compared to previous guidance of $0.225 to $0.25 per Mcfe. Antero expects fourth quarter 2019 net marketing expense to be in the range of $0.15 to $0.17 per Mcfe, an approximate 20% reduction from the third quarter of 2019.
Natural Gas Price Realization
Due to sustained lower natural gas prices resulting in a lower BTU upgrade during the third quarter of 2019, Antero now expects a natural gas price differential of $0.05 to $0.10 per Mcf premium to NYMEX, as compared to the prior guidance range of $0.10 to $0.15 premium to NYMEX
All guidance not discussed in this release is unchanged from previously stated guidance.
Preliminary 2020 Outlook
Antero Resources is targeting 110 to 120 completions in 2020, with an average lateral length of 12,100 feet as compared to 115 to 125 completions in 2019 with an average lateral of 10,200 feet. This represents a 14% increase in total lateral feet to be completed. As a result of the well cost reductions achieved to date and expectations for 2020, Antero's preliminary drilling and completion capital target for 2020 has been reduced to $1.15 to $1.20 billion. In addition to drilling and completion capital, Antero is targeting land capital spending of approximately $50 million in 2020, resulting in a preliminary total capital target of $1.20 to $1.25 billion. This capital spending target is expected to deliver annual production growth of 8% to 10%.
Based on current strip prices and accounting for the reduced capital target, lease operating expense savings achieved to date and expected in 2020, the reduction in unutilized firm transport costs and the targeted general and administrative cost savings, Antero is expecting an outspend of $100 to $150 million during 2020. This includes the $125 million water earn-out proceeds expected to be received from Antero Midstream in January of 2020 and the expected $75 million of net proceeds related to the WGL natural gas pricing dispute that has been ruled in favor of Antero, but is subject to appeal. The 2020 capital budget is subject to Board approval and is expected to be finalized by the first quarter of 2020 based on the commodity price outlook and various other considerations at that time.
Hedging Activity Update
Antero has shifted 850 BBtu/d NYMEX of natural gas fixed price swaps from 2022 to 2021 to support the Company's expected production growth to fill its firm transportation portfolio. The company also added another 100 BBtu/d of natural gas fixed price swaps in 2021. As a result, as of October 29, 2019 Antero's expected natural gas production is now 91% hedged in 2020 at an average NYMEX price of $2.87 per MMBtu and approximately 89% hedged in 2021 at an average NYMEX price of $2.80 per MMBtu, assuming 9% growth in 2020, using the midpoint of the 8 to 10% target and 10% production growth 2021.
Antero also commenced a natural gas liquids hedging program during the quarter that has continued through October. The Company added propane hedges at Mont Belvieu, ARA (Europe) and FEI (Asia) indices as well as butane and pentane hedges tied to domestic prices. As of October 29, 2019 Antero has hedged 54,000 Bbl/d, or 54% of its C3+ NGL production for the fourth quarter of 2019. Antero has also hedged approximately 34,000 Bbl/d or 31% of its expected C3+ NGL production in 2020.
Please see Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, for more information on its commodity derivative positions. Please also see Commodity Derivative Positions which appears later in this press release, as well as Antero's Hedge Portfolio presentation that can be found on the Company's website.
Share Repurchase Activity Update
During the third quarter of 2019, Antero returned $17 million of cash to shareholders by repurchasing 5.1 million shares. The Company has reduced shares outstanding by 5% since the commencement of the share repurchase program in the fourth quarter of 2018. Antero's remaining share repurchase authorization is $454 million.
Increased Bank Lender Agreements
In October 2019, Antero added Royal Bank of Canada ("RBC") to its lending group with $140 million of incremental commitments. Pro forma for the addition of RBC, Antero lender commitments increased to $2.64 billion and the Company's available liquidity increased to approximately $1.7 billion.
South Jersey Payment
Antero received a net payment to the Company of $59 million from South Jersey. The benefit consisted of $51 million in Adjusted EBITDAX ($54 million of net revenue offset by $3 million of production taxes) and $8 million in interest. The payment related to a favorable ruling on previously disclosed contractual disputes with South Jersey. In previous quarters South Jersey had paid the Company based on price indices unilaterally selected by South Jersey and not the index price specified in the contract. A favorable judgment was affirmed in August 2019 and resolved in full with this payment. For further information on this dispute, please see note 14 to Antero's condensed consolidated financial statements included in Antero's Form 10-Q for the period ending September 30, 2019.
Impairment of Oil and Gas Properties
Antero recorded an impairment charge of $1 billion related to proved properties in the Utica Shale in the third quarter of 2019 due to lower future commodity prices. The carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future commodity prices at September 30, 2019.
Third Quarter 2019 Financial Results
For the three months ended September 30, 2019, Antero reported a GAAP net loss of $879 million, or $2.86 per diluted share, compared to a GAAP net loss of $154 million, or $0.49 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," Adjusted Net Loss was $150 million, or $0.49 per diluted share, compared to Adjusted Net Income of $22 million during the three months ended September 30, 2018, or $0.07 per diluted share.
Adjusted EBITDAX was $258 million, a 39% decrease compared to $419 million in the prior year period primarily due to lower commodity pricing. Net loss and Adjusted EBITDAX include $51 million related to the South Jersey payment. The South Jersey underpayments had negatively impacted realizations and EBITDAX in prior periods.
The following table details the components of average net production and average realized prices for the three months ended September 30, 2019:
Three months ended September 30, 2019 | |||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane (Bbl/d) | Combined | |||||||||||
Average Net Production | 2,281 | 9,408 | 124,701 | 46,814 | 3,367 | ||||||||||
Average Realized Prices | Natural Gas | Oil ($/Bbl) | C3+ NGLs | Ethane ($/Bbl) | Combined | ||||||||||
Average realized prices before settled derivatives | $ | 2.50 | $ | 46.86 | $ | 22.53 | $ | 6.15 | $ | 2.74 | |||||
Settled commodity derivatives | 0.55 | 3.13 | 0.14 | — | 0.39 | ||||||||||
Average realized prices after settled derivatives | $ | 3.05 | $ | 50.00 | $ | 22.67 | $ | 6.15 | $ | 3.13 | |||||
NYMEX average price | $ | 2.23 | $ | 56.10 | $ | 2.23 | |||||||||
Premium / (Differential) to NYMEX | $ | 0.82 | $ | (6.10) | $ | 0.90 |
Net daily natural gas equivalent production in the third quarter averaged 3,367 MMcfe/d, including 180,922 Bbl/d of liquids (32% of production), an increase of 24% compared to the prior year period. Total liquids production increased 40% compared to the prior year period. Liquids revenue represented approximately 38% of total product revenue before hedges. Oil production averaged 9,408 Bbl/d, a decrease of 12% over the prior year period. C3+ NGL production averaged 124,701 Bbl/d, an increase of 56% over the prior year period. Recovered ethane production averaged 46,814 Bbl/d, an increase of 20% over the prior year period.
Antero's average realized natural gas price before hedging was $2.50 per Mcf, representing a 15% decrease versus the prior year period and a $0.27 per Mcf premium to the average NYMEX Henry Hub price. Excluding revenue proceeds related to the South Jersey payment of $54 million, or $0.26 per Mcf, Antero's average realized natural gas price before hedging was $2.24 per Mcf. Including hedges, Antero's average realized natural gas price was $3.05 per Mcf, an $0.82 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $116 million, or $0.55 per Mcf.
Antero's average realized C3+ NGL price before hedging was $22.53 per barrel, representing a 41% decrease versus the prior year period. Antero shipped 54% of its total C3+ NGL net production on Mariner East 2 for export and realized a $0.12 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook. Antero sold the remaining 46% of C3+ NGL net production at a $0.13 per gallon discount to Mont Belvieu pricing at Hopedale. The resulting blended price on 124,701 Bbl/d of net C3+ NGL production was $22.53 per barrel, which was a $0.01 per gallon premium to Mont Belvieu pricing. Based on current strip prices at Mont Belvieu, Antero expects a $4 to $5 per barrel improvement in blended realized C3+ prices in the fourth quarter of 2019 relative to the third quarter of 2019.
Pricing Point | Net C3+ NGL Production | % by | Premium (Discount) To Mont Belvieu | |||||
Propane / Butane shipped on ME2 | Marcus Hook | 67,367 | 54% | $0.12 | ||||
Remaining C3+ NGL volume (1) | Hopedale | 57,334 | 46% | ($0.13) | ||||
Total C3+ NGLs | 124,701 | 100% | $0.01 |
(1) Represents Antero C3+ volume sold by third-party midstream providers (domestically or internationally). |
Antero's average realized oil price before hedging was $46.86 per barrel, a $9.24 differential to the average NYMEX WTI price and a 23% decrease versus the prior year period. Including hedges, Antero's average realized oil price was $50.00 per barrel, a $6.10 differential to the average NYMEX WTI price, reflecting the realization of a cash settled oil hedge gain of $3 million. The average realized ethane price was $0.15 per gallon, or $6.15 per barrel, a 61% decrease compared to $0.37 per gallon, or $15.70 per barrel, in the prior year period.
Total revenue in the third quarter was $1.119 billion, a 4% increase compared to $1.077 billion in the prior year quarter. Revenue included a $101 million non-cash gain on unsettled commodity derivatives, while the prior year included a $2 million non-cash gain on unsettled derivatives. Revenue excluding unrealized derivative gains (losses) (non-GAAP) was $1.0 billion, a 5% decrease versus the prior year period due to the decline in commodity prices.
The following table presents a calculation of Adjusted EBITDAX margin (non-GAAP measure) on a per Mcfe basis and a reconciliation to the realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, and is a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations on a per unit basis from period to period by removing the effect of its capital structure from its operating structure.
Three months ended September 30, | ||||||
2018 | 2019 | |||||
Adjusted EBITDAX margin ($ per Mcfe): | ||||||
Realized price before cash receipts for settled derivatives | $ | 3.70 | 2.74 | |||
Distributions/dividends from Antero Midstream | 0.18 | 0.16 | ||||
Marketing, net | (0.31) | (0.20) | ||||
Gathering, compression, processing and transportation costs | (1.77) | (1.95) | ||||
Lease operating expense | (0.14) | (0.12) | ||||
Production and ad valorem taxes | (0.12) | (0.09) | ||||
General and administrative (excluding equity-based compensation) | (0.14) | (0.10) | ||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.40 | 0.44 | ||||
Cash receipts for settled commodity derivatives | 0.28 | 0.39 | ||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 1.68 | 0.83 |
Per unit cash production expense, which equals the sum of lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes was $2.16 per Mcfe, a 6% increase compared to $2.03 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.95 per Mcfe for gathering, compression, processing and transportation costs, $0.12 per Mcfe for lease operating costs, and $0.09 per Mcfe for production and ad valorem taxes. Per unit gathering, compression, processing and transportation costs reflect higher expenses related to the commencement of Mariner East 2 earlier this year that enabled Antero to generate improved C3+ NGL prices on volumes sold at the Marcus Hook terminal.
Per unit net marketing expense was $0.20 per Mcfe compared to $0.31 per Mcfe reported in the prior year period. Net marketing expense declined $0.11 per Mcfe, driven by higher production volumes and firm transportation mitigation efforts that began in September 2019.
Per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.10 per Mcfe, a 29% decrease compared to the prior year period. General and administrative expense on a per Mcfe basis decreased due to increased production levels, lower employee headcount and cost savings initiatives that were implemented during the second quarter of 2019.
Adjusted EBITDAX margin after commodity derivatives was $0.83 per Mcfe, a 50% decrease from the prior year period, primarily due lower realized prices relative to the prior year period. Excluding the EBITDAX impact related to South Jersey of $51 million, or $0.16 per Mcfe, Adjusted EBITDAX margin after commodity derivatives was $0.67 per Mcfe.
Operating Update
Third Quarter 2019
Marcellus Shale — 33 horizontal Marcellus wells were placed to sales during the third quarter of 2019 with an average lateral length of 10,075 feet. For wells that had 60-days of reported data during the quarter, the average rate per well was 21.4 MMcfe/d on choke. The 60-day average rate per well included 1,033 Bbl/d of liquids, comprised of oil, C3+ NGLs and approximately 30% ethane recovery.
During the period, Antero drilled 23 wells with an average lateral length of 11,500 feet in an average of 11 total days from spud to final rig release. Additionally, Antero drilled an average of 6,000 lateral feet per day in the quarter, achieving its highest quarterly rate in the Company's history. This drilling record represents a 10% sequential increase and a 31% increase compared to the 2018 average in lateral footage performance. Antero also drilled a company one-well record of 10,067 lateral feet in a 24-hour period. Drilling costs per foot were notably lower during the quarter, equating to a 6% reduction from the previous quarter and a 19% reduction from the prior year.
Antero's ongoing emphasis on completion efficiencies resulted in an improvement during the third quarter, as the Company averaged 5.9 stages completed per day, representing a 4% increase from 5.7 stages per day in the prior period.
Antero plans to operate an average of four drilling rigs and an average of three to four completion crews for the remainder of the year. For the full year, the Company expects to drill 120 to 130 wells and place 115 to 125 wells online, consistent with prior guidance.
Third Quarter 2019 Capital Investment
Antero's accrued drilling and completion capital expenditures for the three months ended September 30, 2019 were $290 million. For a reconciliation of accrued drilling and completion capital expenditures to cash drilling and completion capital expenditures for the three months ended September 30, 2019, see the supplemental table at the end of this press release. In addition to capital invested in drilling and completion costs, the Company invested $13 million for land, resulting in a total of $303 million in capital spending for the quarter.
Balance Sheet and Liquidity
As of September 30, 2019, Antero's total debt was $3.7 billion, of which $275 million were borrowings outstanding under the Company's revolving credit facility. Pro forma for RBC being added to bank group, lender commitments under this facility total $2.64 billion, and the borrowing base is $4.5 billion. After deducting letters of credit outstanding, the Company had $1.7 billion in available liquidity. As of September 30, 2019, Antero's net debt to trailing twelve months Adjusted EBITDAX ratio was 2.6x.
President and CFO, Glen Warren, commented, "The third quarter was a turning point for Antero on the cost front, as cost saving and efficiency initiatives began to make a meaningful impact on financial results. Further, Antero continued to take steps towards improving our financial strength through the expansion of our commodity hedge position, mitigation of net marketing expenses and the increase in our lender commitments, which allows us to be deliberate in the execution of our business strategy with a fundamentally sound balance sheet in a low commodity price environment."
Commodity Derivative Positions
Antero has hedged 1.8 Tcf of natural gas at a weighted average index price of $2.90 per MMBtu through 2023 with a combination of fixed price swap positions in 2019 through 2023 and collar agreements in 2019. Antero also has oil and NGL fixed price swap positions, including oil positions that totaled 6.5 MMbls/day at a weighted average price of $59.05 per barrel from October 2019 through December 2019. As of October 28, 2019, the Company's estimated fair value of commodity derivative instruments was $807 million based on strip pricing.
Antero's estimated natural gas production for the remainder of 2019 is fully hedged with a combination of fixed price swap positions and collars. As of October 29, 2019, the Company had fixed price swaps on the NYMEX index totaling 996,766 MMBtu/day of natural gas for October 2019 through December 2019 fixed at a weighted average price of $3.23 per MMBtu. Collar agreements for October 2019 through December 2019 total 1,575,000 MMBtu/day of natural gas at a weighted average floor of $2.50 per MMBtu and ceiling of $3.52 per MMBtu. Natural gas liquids derivative contract positions include a combination of fixed price swaps and basis swaps.
Please see Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, for more information on all commodity derivative positions.
The following tables summarize Antero's hedge position as of October 29, 2019:
Fixed price natural gas positions from October 1, 2019 through December 31, 2023 were as follows:
Natural gas MMBtu/day | Weighted average index price | ||||
Three months ending December 31, 2019: | |||||
NYMEX ($/MMBtu) | 996,766 | $ | 3.23 | ||
Year ending December 31, 2020: | |||||
NYMEX ($/MMBtu) | 2,227,500 | $ | 2.87 | ||
Year ending December 31, 2021: | |||||
NYMEX ($/MMBtu) | 2,400,000 | $ | 2.80 | ||
Year ending December 31, 2022: | |||||
NYMEX ($/MMBtu) | 0 | $ | N/A | ||
Year ending December 31, 2023: | |||||
NYMEX ($/MMBtu) | 90,000 | $ | 2.91 |
Natural gas collar positions from October 1, 2019 through December 31, 2019 were as follows:
Natural gas (MMBtu/day) | Weighted average index price | ||||||||||
Ceiling | Floor | Ceiling price | Floor price | ||||||||
Three months ending December 31, 2019: | |||||||||||
NYMEX ($/MMBtu) | 1,575,000 | 1,333,234 | $ | 3.52 | $ | 2.50 |
C3+ NGL and Oil derivative contract positions from October 1, 2019 through December 31, 2021 were as follows:
Derivative | Liquids | Weighted | Weighted differential | Weighted | ||||
Propane – Mont Belvieu (Domestic) | Fixed swap | 8,500 | $0.51 | — | $21.50 | |||
Propane – ARA (Europe, net of shipping) (1) | Fixed swap | 10,113 | $0.58 | — | $24.36 | |||
Propane – FEI (Asia, net of shipping) (1) | Fixed swap | 9,809 | $0.61 | — | $25.62 | |||
Propane – ARA to Mont Belvieu Basis | Basis | 4,050 | — | $0.25 | — | |||
Normal Butane – Mont Belvieu (Domestic) | Fixed swap | 4,000 | $0.59 | — | $24.78 | |||
Natural Gasoline – Mont Belvieu (Domestic) | Fixed swap | 17,400 | $1.14 | — | $47.84 | |||
Total C3+ NGLs | 53,872 | |||||||
Total NYMEX Crude Oil | 6,491 | $59.05 | ||||||
(1) Net of shipping. Assumes $0.10/gal shipping to ARA and $0.20/gal shipping to FEI. | ||||||||
Hedge Position as of 10/29/19. | ||||||||
Year ending December 31, 2020: | ||||||||
Propane – Mont Belvieu (Domestic) | Fixed swap | 500 | $0.67 | $28.30 | ||||
Propane – ARA (Europe) (1) | Fixed swap | 9,761 | $0.65 | $27.30 | ||||
Propane – FEI (Asia) (1) | Fixed swap | 2,045 | $0.81 | $34.02 | ||||
Propane – ARA to Mont Belvieu Basis | Basis | 4,273 | — | $0.23 | — | |||
Normal Butane – Mont Belvieu (Domestic) | Fixed swap | 2,000 | $0.57 | $23.94 | ||||
Natural Gasoline – Mont Belvieu (Domestic) | Fixed swap | 15,000 | $1.07 | $44.94 | ||||
Total C3+ NGLs | 33,579 | |||||||
Total NYMEX Crude Oil | 0 |
(1) Net of shipping. Assumes $0.10/gal shipping to ARA and $0.20/gal shipping to FEI. | ||||||||
Hedge Position as of 10/29/19. |
Conference Call
A conference call is scheduled on Wednesday, October 30, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Wednesday, November 6, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13693463.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, November 6, 2019 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Basis of Financial Presentation
In connection with the closing of the previously announced simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of September 30, 2019, Antero Resources owned 32% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to September 30, 2019, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described herein reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue Excluding Unrealized Derivative (Gains) Losses as set forth in this release represents total revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue Excluding Unrealized Derivative (Gains) Losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance. The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses (in thousands):
Three months ended September 30, | |||||
2018 | 2019 | ||||
Total revenue | $ | 1,076,532 | $ | 1,118,881 | |
Commodity derivative fair value gains | (57,019) | (220,788) | |||
Marketing derivative fair value losses | 42 | — | |||
Gains on settled commodity derivatives | 71,143 | 120,003 | |||
Losses on settled marketing derivatives | (16,060) | — | |||
Revenue Excluding Unrealized Derivative Gains (Losses) | $ | 1,074,638 | $ | 1,018,096 |
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income, adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following tables reconcile net income (loss) before income taxes to Adjusted Net Income (Loss) (in thousands):
Three months ended | |||||
September 30, | |||||
2018 | 2019 | ||||
Net loss attributable to Antero Resources Corp | $ | (154,419) | $ | (878,864) | |
Commodity derivative fair value gains | (57,019) | (220,788) | |||
Gains on settled commodity derivatives | 71,143 | 120,003 | |||
Marketing derivative fair value losses | 42 | — | |||
Losses on settled marketing derivatives | (16,060) | — | |||
Impairment of oil and gas properties | 221,095 | 1,041,469 | |||
Impairment of midstream assets | — | 7,800 | |||
Equity-based compensation | 11,674 | 3,875 | |||
Contract termination and rig stacking | — | 62 | |||
Tax effect of reconciling items (1) | (54,696) | (223,342) | |||
Adjusted Net Income (Loss) | $ | 21,760 | $ | (149,785) | |
Fully Diluted Shares Outstanding | 317,082 | 307,781 |
Per Share Amounts
Three months ended | |||||
September 30, 2019 | |||||
2018 | 2019 | ||||
Net loss attributable to Antero Resources Corp | $ | (0.49) | (2.86) | ||
Commodity derivative fair value gains | (0.18) | (0.72) | |||
Gains on settled commodity derivatives | 0.22 | 0.39 | |||
Losses on settled marketing derivatives | (0.05) | — | |||
Impairment of oil and gas properties | 0.70 | 3.38 | |||
Impairment of midstream assets | — | 0.03 | |||
Equity-based compensation | 0.04 | 0.02 | |||
Tax effect of reconciling items (1) | (0.17) | (0.73) | |||
Adjusted Net Income (Loss) | $ | 0.07 | (0.49) |
(1) Deferred taxes were approximately 24% for 2018 and 23% for 2019. |
Adjusted Net Cash Provided by Operating Activities
Adjusted Net Cash Provided by Operating Activities as presented in this release represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated through March 12, 2019. Adjusted Net Cash Provided by Operating Activities is often used accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Net Cash Provided by Operating Activities is also useful because it is often used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Management believes that Adjusted Net Cash Provided by Operating Activities is a useful indicators of the company's ability to internally fund its activities and to service or incur additional debt.
There are significant limitations to using Adjusted Net Cash Provided by Operating Activities and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Net Cash Provided by Operating Activities reported by different companies. Adjusted Net Cash Provided by Operating Activities do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Net Cash Provided by Operating Activities is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. Furthermore, we may calculate such measures differently from similarly titled measures used by other companies.
The following table reconciles net cash provided by operating activities to Adjusted Net Cash Provided by Operating Activities as used in this release (in thousands):
Three months ended September 30, | ||||||
2018 | 2019 | |||||
Net cash provided by operating activities | $ | 421,458 | 198,410 | |||
Antero Midstream Partners net cash provided by (used in) operating activities (1) | (54,446) | — | ||||
Adjusted Net Cash Provided By Operating Activities | $ | 367,012 | 198,410 |
(1) Represents Antero Midstream Partners net cash provided by operating activities that was consolidated in Antero Resources' financial results in 2018. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | September 30, | |||||
2018 | 2019 | |||||
AR bank credit facility | $ | 405,000 | 275,000 | |||
AM bank credit facility (1) | 990,000 | — | ||||
5.375% AR senior notes due 2021 | 1,000,000 | 1,000,000 | ||||
5.125% AR senior notes due 2022 | 1,100,000 | 1,100,000 | ||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | ||||
5.375% AM senior notes due 2024 (1) | 650,000 | — | ||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | ||||
Net unamortized premium | 1,241 | 1,021 | ||||
Net unamortized debt issuance costs (1) | (34,553) | (22,193) | ||||
Consolidated total debt | $ | 5,461,688 | 3,703,828 | |||
Less: AR cash and cash equivalents | — | — | ||||
Less: AM cash and cash equivalents (1) | — | — | ||||
Consolidated net debt | $ | 5,461,688 | 3,703,828 | |||
Less: Antero Midstream Partners debt net of cash and unamortized premium and debt issuance costs (1) | $ | 1,632,147 | — | |||
Net Debt | $ | 3,829,541 | 3,703,828 |
(1) Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero's results |
Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company's financial performance because it:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
The following table represents a reconciliation of Adjusted EBITDAX to net income (loss), including noncontrolling interest, and net cash provided by operating activities per our consolidated statements of cash flows.
Three months ended September 30, | ||||||
(in thousands) | 2018 | 2019 | ||||
Reconciliation of net loss to Adjusted EBITDAX: | ||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (154,419) | (878,864) | |||
Net income and comprehensive income attributable to noncontrolling interests | 76,447 | — | ||||
Commodity derivative fair value gains (1) | (57,019) | (220,788) | ||||
Gains on settled commodity derivatives (1) | 71,143 | 120,003 | ||||
Marketing derivative fair value losses (1) | 42 | — | ||||
Losses on settled marketing derivatives (1) | (16,060) | — | ||||
Interest expense, net | 74,528 | 47,754 | ||||
Income tax expense (benefit) | 18,953 | (272,627) | ||||
Depletion, depreciation, amortization, and accretion | 243,897 | 242,430 | ||||
Impairment of oil and gas properties | 221,095 | 1,041,469 | ||||
Impairment of midstream assets | 1,157 | 7,800 | ||||
Exploration expense | 666 | 208 | ||||
Equity-based compensation expense | 16,202 | 3,875 | ||||
Equity in earnings (loss) of unconsolidated affiliates | (10,705) | 117,859 | ||||
Distributions/dividends from unconsolidated affiliates | 11,765 | 48,714 | ||||
Contract termination and rig stacking | — | 62 | ||||
497,692 | 257,895 | |||||
Net income and comprehensive income attributable to noncontrolling interests | (76,447) | — | ||||
Antero Midstream Partners interest expense, net (2) | (16,895) | — | ||||
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2) | (42,509) | — | ||||
Antero Midstream Partners impairment | (1,157) | — | ||||
Antero Midstream Partners equity-based compensation expense (2) | (4,528) | — | ||||
Antero Midstream Partners equity in earnings of unconsolidated affiliates (2) | 10,705 | — | ||||
Antero Midstream Partners distributions from unconsolidated affiliates (2) | (11,765) | — | ||||
Equity in earnings of Antero Midstream Partners (2) | 23,363 | — | ||||
Distributions from Antero Midstream Partners (2) | 41,031 | — | ||||
Antero Midstream Partners related adjustments | (78,202) | — | ||||
Adjusted EBITDAX | $ | 419,490 | 257,895 | |||
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||
Adjusted EBITDAX | $ | 419,490 | 257,895 | |||
Antero Midstream Partners related adjustments | 78,202 | — | ||||
Interest expense, net | (74,528) | (47,754) | ||||
Exploration expense | (666) | (208) | ||||
Changes in current assets and liabilities | (2,053) | (13,653) | ||||
Other | (379) | |||||
Other non-cash items | 1,013 | 2,509 | ||||
Net cash provided by operating activities | $ | 421,458 | 198,410 |
(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization. |
(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 for further discussion on equity method investments. |
The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended September 30, 2019, as used in this release (in thousands):
Twelve months ended | |||||
(in thousands) | September 30, 2019 | ||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 20,521 | |||
Commodity derivative fair value gains | (249,460) | ||||
Gains on settled commodity derivatives | 236,537 | ||||
Gains on settled marketing derivatives | (5,411) | ||||
Loss on sale of assets | 951 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | ||||
Interest expense | 216,511 | ||||
Income tax benefit | (98,025) | ||||
Depletion, depreciation, amortization, and accretion | 946,034 | ||||
Impairment of oil and gas properties | 1,397,081 | ||||
Impairment of midstream assets | 7,800 | ||||
Exploration expense | 1,584 | ||||
Gain on change in fair value of contingent acquisition consideration | 104,860 | ||||
Equity-based compensation expense | 26,368 | ||||
Equity in (earnings) loss of Antero Midstream Partners LP | (81,774) | ||||
Equity in (earnings) loss of unconsolidated affiliates | 102,457 | ||||
Distributions/dividends from Antero Midstream | 186,608 | ||||
Contract termination and rig stacking | 14,026 | ||||
Simplification transaction fees | 6,297 | ||||
Adjusted EBITDAX | $ | 1,426,923 |
Drilling and Completion Capital Expenditures
The following tables reconcile Antero's drilling and completion costs as reported on a cash basis to drilling and completion costs on an accrual basis (in thousands):
Three months ended September 30, | ||||||
2018 | 2019 | |||||
Drilling and completion costs (as reported; cash basis) | $ | 372,879 | 277,843 | |||
Drilling and completion costs paid to Antero Midstream Partners (cash basis) (1) | 67,951 | — | ||||
Adjusted drilling and completion costs (cash basis) | 440,830 | 277,843 | ||||
Change in accrued capital costs | 7,170 | 12,404 | ||||
Adjusted drilling and completion costs (accrual basis) | $ | 448,000 | 290,247 |
(1) Represents drilling and completion costs paid to Antero Midstream Partners that were consolidated in Antero Resources' financial results in 2018. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Adjusted Net Cash Provided by Operating Activities, leverage targets, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs and cost savings initiatives, including with respect to potential incremental flowback and produced water services by Antero Midstream, future financial position, future technical improvements, future marketing opportunities, and expectations regarding the amount and timing of jury awards, the receipt of which are subject to final orders and the resolutions of appeals processes, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond the Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
ANTERO RESOURCES CORPORATION Condensed Consolidated Balance Sheets December 31, 2018 and September 30, 2019 (In thousands, except per share amounts) | |||||||
(Unaudited) | |||||||
December 31, 2018 | September 30, 2019 | ||||||
Assets | |||||||
Current assets: | |||||||
Accounts receivable | $ | 51,073 | 29,207 | ||||
Accrued revenue | 474,827 | 281,177 | |||||
Derivative instruments | 245,263 | 411,774 | |||||
Other current assets | 35,450 | 7,342 | |||||
Total current assets | 806,613 | 729,500 | |||||
Property and equipment: | |||||||
Oil and gas properties, at cost (successful efforts method): | |||||||
Unproved properties | 1,767,600 | 1,406,464 | |||||
Proved properties | 12,705,672 | 11,568,285 | |||||
Water handling and treatment systems | 1,013,818 | — | |||||
Gathering systems and facilities | 2,470,708 | 5,802 | |||||
Other property and equipment | 65,842 | 70,965 | |||||
18,023,640 | 13,051,516 | ||||||
Less accumulated depletion, depreciation, and amortization | (4,153,725) | (3,136,767) | |||||
Property and equipment, net | 13,869,915 | 9,914,749 | |||||
Operating leases right-of-use assets | — | 3,230,148 | |||||
Derivative instruments | 362,169 | 405,180 | |||||
Investments in unconsolidated affiliates | 433,642 | 1,819,323 | |||||
Other assets | 47,125 | 21,388 | |||||
Total assets | $ | 15,519,464 | 16,120,288 | ||||
Liabilities and Equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 66,289 | 32,496 | ||||
Accounts payable, related parties | — | 100,437 | |||||
Accrued liabilities | 465,070 | 392,726 | |||||
Revenue distributions payable | 310,827 | 231,152 | |||||
Derivative instruments | 532 | — | |||||
Short-term lease liabilities | 2,459 | 409,990 | |||||
Other current liabilities | 8,363 | 4,367 | |||||
Total current liabilities | 853,540 | 1,171,168 | |||||
Long-term liabilities: | |||||||
Long-term debt | 5,461,688 | 3,703,828 | |||||
Deferred income tax liability | 650,788 | 916,031 | |||||
Long-term lease liabilities | 2,873 | 2,823,197 | |||||
Other liabilities | 63,098 | 59,366 | |||||
Total liabilities | 7,031,987 | 8,673,590 | |||||
Commitments and contingencies (Notes 13 and 14) | |||||||
Equity: | |||||||
Stockholders' equity: | |||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | |||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 308,594 shares and 304,161 shares issued and outstanding at December 31, 2018 and September 30, 2019, respectively | 3,086 | 3,041 | |||||
Additional paid-in capital | 6,485,174 | 6,124,042 | |||||
Accumulated earnings | 1,177,548 | 1,319,615 | |||||
Total stockholders' equity | 7,665,808 | 7,446,698 | |||||
Noncontrolling interests in consolidated subsidiary | 821,669 | — | |||||
Total equity | 8,487,477 | 7,446,698 | |||||
Total liabilities and equity | $ | 15,519,464 | 16,120,288 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2018 and 2019 (unaudited) (In thousands, except per share amounts) | |||||||
Three Months Ended September 30, | |||||||
2018 | 2019 | ||||||
Revenue and other: | |||||||
Natural gas sales | $ | 527,122 | 524,448 | ||||
Natural gas liquids sales | 338,269 | 284,958 | |||||
Oil sales | 59,722 | 40,561 | |||||
Commodity derivative fair value gains | 57,019 | 220,788 | |||||
Gathering, compression, water handling and treatment | 4,844 | — | |||||
Marketing | 89,598 | 46,645 | |||||
Marketing derivative fair value losses | (42) | — | |||||
Other income | — | 1,481 | |||||
Total revenue | 1,076,532 | 1,118,881 | |||||
Operating expenses: | |||||||
Lease operating | 36,269 | 35,928 | |||||
Gathering, compression, processing, and transportation | 326,504 | 603,860 | |||||
Production and ad valorem taxes | 30,518 | 28,863 | |||||
Marketing | 151,764 | 108,216 | |||||
Exploration | 666 | 208 | |||||
Impairment of oil and gas properties | 221,094 | 1,041,469 | |||||
Impairment of midstream assets | 1,157 | 7,800 | |||||
Depletion, depreciation, and amortization | 243,186 | 241,503 | |||||
Accretion of asset retirement obligations | 710 | 927 | |||||
General and administrative (including equity-based compensation expense of $16,202 and $3,875 in 2018 and 2019, respectively) | 59,860 | 35,923 | |||||
Contract termination and rig stacking | — | 62 | |||||
Total operating expenses | 1,071,728 | 2,104,759 | |||||
Operating income (loss) | 4,804 | (985,878) | |||||
Other income (expenses): | |||||||
Equity in earnings (loss) of unconsolidated affiliates | 10,705 | (117,859) | |||||
Interest expense, net | (74,528) | (47,754) | |||||
Total other expenses | (63,823) | (165,613) | |||||
Loss before income taxes | (59,019) | (1,151,491) | |||||
Provision for income tax (expense) benefit | (18,953) | 272,627 | |||||
Net loss and comprehensive loss including noncontrolling interests | (77,972) | (878,864) | |||||
Net income and comprehensive income attributable to noncontrolling interests | 76,447 | — | |||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (154,419) | (878,864) | ||||
Loss per common share—basic and diluted | $ | (0.49) | (2.86) | ||||
Weighted average number of shares outstanding: | |||||||
Basic and diluted | 317,082 | 307,781 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2018 and 2019 (In thousands) | |||||||
Nine Months Ended September 30, | |||||||
2018 | 2019 | ||||||
Cash flows provided by (used in) operating activities: | |||||||
Net income (loss) including noncontrolling interests | $ | (64,437) | 189,060 | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||
Depletion, depreciation, amortization, and accretion | 711,581 | 726,827 | |||||
Impairment of oil and gas properties | 406,068 | 1,253,712 | |||||
Impairment of midstream assets | 9,658 | 14,782 | |||||
Commodity derivative fair value gains | (134,793) | (471,847) | |||||
Gains on settled commodity derivatives | 268,369 | 261,794 | |||||
Marketing derivative fair value gains | (94,081) | — | |||||
Gains on settled marketing derivatives | 78,098 | — | |||||
Deferred income tax expense | 2,500 | 32,019 | |||||
Loss on sale of assets | — | 951 | |||||
Equity-based compensation expense | 56,429 | 19,327 | |||||
Equity in earnings (loss) of unconsolidated affiliates | (27,832) | 90,193 | |||||
Distributions/dividends of earnings from unconsolidated affiliates | 29,660 | 109,241 | |||||
Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042) | |||||
Other | 2,945 | 8,179 | |||||
Changes in current assets and liabilities: | |||||||
Accounts receivable | 4,653 | 14,236 | |||||
Accrued revenue | (53,888) | 193,650 | |||||
Other current assets | (3,721) | 2,365 | |||||
Accounts payable including related parties | 8,177 | (971) | |||||
Accrued liabilities | 27,446 | (11,169) | |||||
Revenue distributions payable | 36,215 | (72,176) | |||||
Other current liabilities | (2,649) | 1,387 | |||||
Net cash provided by operating activities | 1,260,398 | 955,518 | |||||
Cash flows provided by (used in) investing activities: | |||||||
Additions to unproved properties | (130,381) | (69,796) | |||||
Drilling and completion costs | (1,125,660) | (957,931) | |||||
Additions to water handling and treatment systems | (77,385) | (24,416) | |||||
Additions to gathering systems and facilities | (337,448) | (48,239) | |||||
Additions to other property and equipment | (5,371) | (5,980) | |||||
Investments in unconsolidated affiliates | (91,419) | (25,020) | |||||
Proceeds from the Antero Midstream Partners LP Transactions | — | 296,611 | |||||
Change in other assets | (2,675) | 7,461 | |||||
Proceeds from asset sales | — | 1,983 | |||||
Net cash used in investing activities | (1,770,339) | (825,327) | |||||
Cash flows provided by (used in) financing activities: | |||||||
Repurchases of common stock | — | (17,924) | |||||
Issuance of senior notes | — | 650,000 | |||||
Borrowings (repayments) on bank credit facilities, net | 682,000 | (45,000) | |||||
Payments of deferred financing costs | — | (8,259) | |||||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (188,775) | (85,076) | |||||
Employee tax withholding for settlement of equity compensation awards | (8,205) | (2,379) | |||||
Other | (3,520) | (2,021) | |||||
Net cash provided by financing activities | 481,500 | 489,341 | |||||
Effect of deconsolidation of Antero Midstream Partners LP | — | (619,532) | |||||
Net decrease in cash and cash equivalents | (28,441) | — | |||||
Cash and cash equivalents, beginning of period | 28,441 | — | |||||
Cash and cash equivalents, end of period | $ | — | — | ||||
Supplemental disclosure of cash flow information: | |||||||
Cash paid during the period for interest | $ | 179,489 | 142,288 | ||||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | $ | 7,325 | (22,103) |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the three months ended September 30, 2018 and 2019: | ||||||||||||
Three months ended September 30, | Amount of Increase | Percent | ||||||||||
(in thousands) | 2018 | 2019 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 527,122 | $ | 524,448 | $ | (2,674) | (1) | % | ||||
NGLs sales | 338,269 | 284,958 | (53,311) | (16) | % | |||||||
Oil sales | 59,722 | 40,561 | (19,161) | (32) | % | |||||||
Commodity derivative fair value gains | 57,019 | 220,788 | 163,769 | 287 | % | |||||||
Gathering, compression, water handling and treatment | 4,844 | — | (4,844) | (100) | % | |||||||
Marketing | 89,598 | 46,645 | (42,953) | (48) | % | |||||||
Marketing derivative fair value loss | (42) | — | 42 | (100) | % | |||||||
Other income | — | 1,481 | 1,481 | * | ||||||||
Total revenue | 1,076,532 | 1,118,881 | 42,349 | 4 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 36,269 | 35,928 | (341) | (1) | % | |||||||
Gathering, compression, processing, and transportation | 326,504 | 603,860 | 277,356 | 85 | % | |||||||
Production and ad valorem taxes | 30,518 | 28,863 | (1,655) | (5) | % | |||||||
Marketing | 151,764 | 108,216 | (43,548) | (29) | % | |||||||
Exploration | 666 | 208 | (458) | (69) | % | |||||||
Impairment of oil and gas properties | 221,094 | 1,041,469 | 820,375 | 371 | % | |||||||
Impairment of midstream assets | 1,157 | 7,800 | 6,643 | 574 | % | |||||||
Depletion, depreciation, and amortization | 243,186 | 241,503 | (1,683) | (1) | % | |||||||
Accretion of asset retirement obligations | 710 | 927 | 217 | 31 | % | |||||||
General and administrative (excluding equity-based compensation) | 43,658 | 32,048 | (11,610) | (27) | % | |||||||
Equity-based compensation | 16,202 | 3,875 | (12,327) | (76) | % | |||||||
Contract termination and rig stacking | — | 62 | 62 | * | ||||||||
Total operating expenses | 1,071,728 | 2,104,759 | 1,033,031 | 96 | % | |||||||
Operating income (loss) | 4,804 | (985,878) | (990,682) | (20,622) | % | |||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliate | 10,705 | (117,859) | (128,564) | (1,201) | % | |||||||
Interest expense | (74,528) | (47,754) | 26,774 | (36) | % | |||||||
Total other expenses | (63,823) | (165,613) | (101,790) | 159 | % | |||||||
Loss before income taxes | (59,019) | (1,151,491) | (1,092,472) | 1,851 | % | |||||||
Income tax (expense) benefit | (18,953) | 272,627 | 291,580 | (1,538) | % | |||||||
Net loss and comprehensive loss including noncontrolling interest | (77,972) | (878,864) | (800,892) | 1,027 | % | |||||||
Net income and comprehensive income attributable to noncontrolling interest | 76,447 | — | (76,447) | (100) | % | |||||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | (154,419) | $ | (878,864) | $ | (724,445) | 469 | % | ||||
Adjusted EBITDAX | $ | 419,491 | $ | 257,895 | $ | (161,596) | (39) | % |
* Not meaningful |
Three months ended September 30, | Amount of Increase | Percent | ||||||||||
2018 | 2019 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 179 | 210 | 31 | 17 | % | |||||||
C2 Ethane (MBbl) | 3,579 | 4,307 | 728 | 20 | % | |||||||
C3+ NGLs (MBbl) | 7,343 | 11,472 | 4,129 | 56 | % | |||||||
Oil (MBbl) | 978 | 865 | (113) | (12) | % | |||||||
Combined (Bcfe) | 250 | 310 | 60 | 24 | % | |||||||
Daily combined production (MMcfe/d) | 2,718 | 3,367 | 649 | 24 | % | |||||||
Average prices before effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 2.95 | $ | 2.50 | $ | (0.45) | (15) | % | ||||
C2 Ethane (per Bbl) | $ | 15.70 | $ | 6.15 | $ | (9.55) | (61) | % | ||||
C3+ NGLs (per Bbl) | $ | 38.41 | $ | 22.53 | $ | (15.88) | (41) | % | ||||
Oil (per Bbl) | $ | 61.06 | $ | 46.86 | $ | (14.20) | (23) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.70 | $ | 2.74 | $ | (0.96) | (26) | % | ||||
Average realized prices after effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 3.51 | $ | 3.05 | $ | (0.46) | (13) | % | ||||
C2 Ethane (per Bbl) | $ | 15.70 | $ | 6.15 | $ | (9.55) | (61) | % | ||||
C3+ NGLs (per Bbl) | $ | 35.32 | $ | 22.67 | $ | (12.65) | (36) | % | ||||
Oil (per Bbl) | $ | 54.00 | $ | 50.00 | $ | (4.00) | (7) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.98 | $ | 3.13 | $ | (0.85) | (21) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.14 | $ | 0.12 | $ | (0.02) | (14) | % | ||||
Gathering, compression, processing, and transportation | $ | 1.77 | $ | 1.95 | $ | 0.18 | 10 | % | ||||
Production and ad valorem taxes | $ | 0.12 | $ | 0.09 | $ | (0.03) | (25) | % | ||||
Marketing expense, net | $ | 0.25 | $ | 0.20 | $ | (0.05) | (20) | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.82 | $ | 0.78 | $ | (0.04) | (5) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.14 | $ | 0.10 | $ | (0.04) | (29) | % |
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SOURCE Antero Resources Corporation
DENVER, Oct. 16, 2019 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its third quarter earnings release on Tuesday, October 29, 2019 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Wednesday, October 30, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources." A telephone replay of the call will be available until Wednesday, November 6, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13693463.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, November 6, 2019 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Oct. 8, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced that Vicky Sutil and Tom Tyree have been appointed to its board of directors (the "Board"), as a Class III director and Class I director, respectively, effective as of October 7, 2019.
Ms. Sutil
Ms. Sutil has an extensive background in the oil and gas industry, previously with California Resources Corporation serving as Vice President of Commercial Analysis for CRC Marketing, Inc. from 2014 to 2016. Prior to that, Ms. Sutil worked in a variety of corporate and asset level capacities with Occidental Petroleum both upstream and midstream from 2000 to 2014. She began her career serving in a number of project management and commercial roles across both the upstream and downstream businesses at ARCO and Mobil Oil between 1988 and 2000. Ms. Sutil served as Occidental's representative on the boards of the general partners of Plains All American Pipeline, L.P. and Plains GP Holdings, L.P. until 2015, and currently serves on the board of Delek U.S. Holdings. Ms. Sutil is currently working with SK E&P Company focusing on strategic planning and has served in that role since 2017. Ms. Sutil received a Bachelor of Science in Mechanical Engineering with a petroleum emphasis from the University of California at Berkeley and a Master of Business Administration degree from the Pepperdine University School of Business and Management.
Paul M. Rady, Chairman and CEO of Antero Resources commented, "We are thrilled to add Vicky to our Board of Directors. Vicky has substantial experience in the oil and gas industry, which includes her background in corporate development, commercial negotiations, corporate planning, mergers and acquisitions and project management. This, combined with her previous Board level experience, will serve as a valuable asset to Antero and our shareholders. Adding another independent director to the Board further strengthens our commitment to good corporate governance at Antero."
Ms. Sutil stated, "I am excited to join the Antero Resources Board of Directors at this phase in its corporate history. With a highly integrated asset base in one of the largest oil and gas plays in the world, there is a lot of opportunity to be impactful. I look forward to representing all shareholders and working closely with the Board to maximize shareholder value as the Company moves forward."
Mr. Tyree
Mr. Tyree has broad expertise in the oil and gas industry both in a leadership role at a number of successful upstream companies and as a financial advisor to oil and gas companies. He is currently the Chairman of Northwoods Energy LLC, an upstream oil and gas company that he founded in January 2018. Previously, Mr. Tyree was a co-founder and served as President, Chief Financial Officer and a Board member of Vantage Energy, LLC from 2006 until its sale to Rice Energy Inc. in October 2016. Prior to Vantage, he served as Chief Financial Officer of Bill Barrett Corporation from 2003 through 2006. Before transitioning to the industry side at Bill Barrett Corporation, Mr. Tyree was an investment banker at Goldman, Sachs & Co. from 1989 to 2003, focused on strategic advisory and financing transactions primarily with energy and industrial companies. Mr. Tyree currently serves on the board of Bonanza Creek Energy, an oil and gas company focused on the DJ Basin of Colorado. He received his Bachelor of Arts from Colgate University and currently serves as a member of the Colgate Board of Trustees. Mr. Tyree received a Master of Business Administration degree from the Wharton School at the University of Pennsylvania.
Mr. Rady commented, "We are also excited to announce the addition of Tom to our Board of Directors. Tom has significant experience in the oil and gas industry over a number of decades and over that time has helped create significant value for his shareholders. Tom's expertise in operations, strategy, finance and capital markets will be a valuable addition to the Antero Resources Board. With the addition of Vicky and Tom, six of our nine directors are now independent directors, furthering our good corporate governance initiatives."
Mr. Tyree stated, "I am pleased to join the Board at Antero Resources, a leading operator in the world class Appalachian Basin. I have followed the Antero trajectory both up close as an executive officer at Vantage Energy as well as from afar as an unconventional resource developer. I look forward to working closely with the Board and leveraging my knowledge and prior experience in the basin to deliver sustainable, long-term value for Antero's shareholders for many years ahead."
Ms. Sutil and Mr. Tyree are independent directors under applicable regulations, and their appointments increase the size of the Board to nine directors, seven of whom are independent for service on the Board and six of whom are independent by audit committee standards.
Antero Resources is an independent oil and natural gas company engaged in the exploration, development and production of natural gas, NGLs, and oil properties located in the Appalachian Basin.
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SOURCE Antero Resources Corporation
DENVER, July 31, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero," "Antero Resources," or the "Company") today released its second quarter 2019 financial and operational results. The relevant condensed consolidated and condensed consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, which has been filed with the Securities and Exchange Commission ("SEC").
Second Quarter 2019 Highlights Include:
Paul Rady, Chairman and CEO said, "Antero achieved strong production volumes and incurred its lowest quarterly capital expenditures to date as a public company. We remain highly focused on creating sustained value by prioritizing key initiatives dedicated to reducing costs, streamlining operations and strategically targeting favorably priced markets for our diverse product portfolio of natural gas and liquids. The first half of 2019 showcased these efforts, with technical and operational initiatives that resulted in our ability to reach our previously announced full year well cost reduction targets by midyear, significantly ahead of schedule. Meanwhile, further well cost reduction initiatives are underway, and we expect well costs to be 10% to 14% lower per foot by 2020, compared to our 2019 budgeted costs per foot. This will primarily be driven through water savings initiatives and continued operational efficiencies. These cost savings combined with our expanded hedge position provide us with greater certainty in our ability to continue to execute our development plan in a challenged commodity price environment."
Recent Developments
Well Cost Savings Update & Outlook
Antero is on track to achieve its targeted reductions in well costs and lease operating expenses. Antero's 2019 well cost was budgeted at $0.97 million per 1,000 feet of lateral assuming a 12,000 foot lateral. During the second half of 2019, Antero is expecting well costs to average $0.93 million per 1,000 feet of lateral. Well cost reductions are ahead of schedule and have been delivered through service cost deflation, sand logistics optimization and operational efficiency gains. For 2020, Antero is targeting well costs of $0.83 million to $0.87 million per 1,000 feet of lateral, on average, 10% to 14% lower than the 2019 initial budgeted costs, or $1.2 to $1.7 million lower per well for a 12,000 foot lateral. The additional cost savings are expected to come from water savings initiatives that include enhanced flowback water management and completion design optimization. Expanded water services are also anticipated to reduce lease operating expenses by at least 20% in 2020.
Second Half 2019 Well Costs
During the second quarter of 2019, Antero approached its vendors and service providers to reduce pricing to reflect the current deflationary market environment. The price reductions achieved to date are included in the well cost assumptions discussed above.
One of the key areas of focus with vendors continues to be sand sourcing and logistics. Total delivered sand costs continue to decrease materially, through a shift to directly-sourced sand and improved "last mile" logistics. Antero previously executed its first direct sourcing sand supply agreement at the end of 2018. The Company executed a similar agreement with a premier sand supplier in the second quarter of 2019, and expects to increase directly-sourced sand supply from 75% currently to 100% of completion needs going forward. In addition, improvements to last mile logistics for sand are underway, as the Company has lowered sand delivery trucking costs during the second quarter of 2019.
Operational efficiency gains continue on both the drilling and completions side of development. Drilling days from spud to final rig release have been reduced from 12.4 days in 2018 to 12.0 days year to date in the Marcellus, despite lateral lengths increasing from 10,100 feet to 11,000 feet over that same time period. The Company has seen material improvement in stages completed per day, with an average of 5.7 stages per day in the second quarter of 2019, a 10% increase from 5.2 stages per day in 2018. Antero expects to continue pushing the stages completed per day higher through further completion optimization. In addition, top-hole optimization and other related drilling efficiencies have been achieved and are now becoming a part of Antero's standard drilling process. The service cost deflation initiative, sand savings and efficiency gains have resulted in per well savings of approximately $500,000 per well, or $0.04 million per 1,000 feet of lateral on a 12,000 foot lateral, resulting in second half of 2019 expected well costs of $0.93 million per 1,000 feet of lateral.
Water Savings Initiatives and Other Efficiency Gains Expected in 2020
Targeted well cost savings and lower lease operating expenses for 2020 are expected to be derived primarily from Antero's water savings initiatives. The water savings initiatives consist of two components (i) a reduction in flowback water costs through the planning and implementation by Antero Midstream of localized water blending and polishing operations and a flowback and produced water pipeline system and (ii) a reduction in fresh water costs from completion design optimization that will consist of both higher mesh sand and lower fresh water usage.
In conjunction with Antero's well cost savings initiatives, Antero Midstream announced plans to expand the scope of its water business to support the growing flowback and produced water volumes from Antero Resources. Antero Midstream plans to implement localized storage and fresh water blending operations, utilize mobile treatment for flowback and produced water volumes in Antero's northern fairway, repurpose portions of the existing fresh water system to transport flowback and produced water, and construct a limited amount of new pipelines to deliver flowback and produced water to localized blending and treatment operations and the Antero Clearwater Facility. Antero Midstream has indicated the fresh water blending and mobile treatment options could be implemented as soon as the second half of 2019 in certain areas of development. The infrastructure buildout will be a flexible, fit-for-purpose system based on Antero Resources' development plan and Antero Midstream believes the system could be phased in beginning in 2020. These localized operations will replace a significant amount of the flowback and produced volumes currently trucked by third parties, which Antero Midstream manages on a cost plus 3% basis. The Company has historically trucked all flowback and produced water, paying third party trucking companies $160 million over the last twelve months. This creates an opportunity for Antero Resources to materially reduce both capital and lease operating costs.
Based on ongoing assessments of drilling and completion designs, Antero also expects to trend lower in water used in completion operations over time. Depending on the areas being developed, Antero expects water use will be reduced by 5 to 7 barrels per foot, from the current design of 40 to 45 barrels per foot to 35 to 38 barrels per foot in the Marcellus beginning in January 2020.
In addition to water savings initiatives, Antero expects further operational efficiency gains related to development plan optimization. Together, Antero expects overall water savings initiatives and operational efficiency gains to result in additional per well savings of $700,000 to $1.2 million, or $0.06 to $0.10 million per 1,000 feet of lateral, which is 6% to 11% of additional savings per well compared to second half of 2019 budgeted well costs.
Lease Operating Expense Reduction
Antero capitalizes the cost of moving flowback water during the first 90 days of a well's life. Antero's lease operating expenses include the cost of transporting produced water after the first 90 days of the well's life. In the first half of 2019, produced water costs represented approximately 80% of total lease operating expenses. Assuming Antero Midstream implements the expanded produced water services, Antero expects it will result in at least a 20% reduction in lease operating costs in 2020 compared to 2019 budgeted costs. Antero estimates lease operating expense savings of at least $50 million on an annualized basis once the expanded produced water services and blending and polishing operations are fully implemented.
Preliminary 2020 Outlook
Antero Resources is targeting 110 to 120 completions in 2020, with an average lateral length of 12,100 feet as compared to 115 to 125 completions in 2019 with an average lateral of 10,200 feet. This represents a 14% increase in total lateral feet completed. Despite the increase in lateral feet completed, Antero's preliminary drilling and completion capital budget for 2020 is $1.2 billion to $1.3 billion. This is a result of the aforementioned 10% to 14% well cost reduction initiative combined with the 19% increase in the average lateral length to be completed in 2020 compared to 2019. In addition to drilling and completion capital, Antero is targeting a land capital budget of approximately $75 million, resulting in a total preliminary capital budget of $1.275 to $1.375 billion.
Based on current strip pricing of $2.45 per MMBtu natural gas, $29 per barrel C3+ NGLs, and $56 per barrel oil, the 2020 drilling and completion capital budget is expected to be funded with cash flow from operations and $125 million from a water earn-out payment from Antero Midstream. Additionally, approximately $150 million net to Antero from previously disclosed natural gas pricing disputes that have been ruled in favor of Antero are expected to be included in cash flow from operations in 2020. Assuming strip pricing, an estimated $350 million of realized hedge gains will more than offset all of Antero's expected net marketing expense in 2020. Antero's 2020 capital budget is subject to Board approval and will be finalized at year-end 2019 based on the commodity price outlook and various other considerations at that time.
Natural Gas Hedges
During the second quarter of 2019, Antero added NYMEX Henry Hub-based natural gas fixed price swaps for 2020 and 2021 of 810 MMBtu/d at a weighted average price of $2.66 per MMBtu and 300 MMBtu/d at a weighted average price of $2.60 per MMBtu, respectively.
As a result, Antero's natural gas production is nearly fully hedged for the remainder of 2019 and for all of 2020, and partially hedged in future years.
Antero has been at the forefront of commodity price risk management through its comprehensive natural gas hedging program, and actions taken during the second quarter of 2019 further support Antero's strategic objectives. The mitigation of commodity price volatility risk through hedging provides key benefits to Antero, most importantly the ability to protect the Company from downside commodity price risk and maintain the Company's development program, which lead to more efficient development at lower overall costs, supporting EBITDAX margins.
2019 Guidance Update
Natural Gas Pricing Update
In 2019, Antero expects to realize a $0.10 to $0.15 per Mcf price premium relative to NYMEX Henry Hub prices for natural gas sales, compared to the original guidance range of a $0.15 to $0.20 per Mcf premium issued in January 2019. The Company continues to see favorable price mix impacts from natural gas volumes sold in higher priced geographic markets including the Gulf Coast and Midwest. However, NYMEX Henry Hub commodity futures prices for the full year have declined by approximately 15% since the issuance of guidance in January. The reduction in natural gas pricing through the year directly results in a lower overall BTU upgrade and premium to NYMEX for Antero's natural gas sales.
Cash Production and Net Marketing Expense
Antero is forecasting a decrease in cash production expenses during 2019 to a range of $2.15 to $2.20 per Mcfe from the prior guidance range of $2.15 to $2.25 per Mcfe. Cash production expenses includes lease operating expenses (LOE), gathering, compression, processing, transportation expenses and production and ad valorem taxes. The decrease is driven primarily by lower transportation costs as a result of utilizing lower cost transportation for Antero's gas production. Based on current strip pricing, Antero expects to continue to utilize the lower cost transport and leave higher cost transport unutilized. As a result, Antero is increasing its net marketing expense guidance to a range of $0.225 to $0.25 per Mcfe, as compared to the original guidance of $0.175 to $0.225 per Mcfe.
Any 2019 projections not discussed in this release are unchanged from previously stated guidance.
Second Quarter 2019 Financial Results
For the three months ended June 30, 2019, Antero reported GAAP net income of $42 million, or $0.14 per diluted share, compared to GAAP net loss of $136 million, or $0.43 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," Adjusted Net Loss was $66 million, or $0.21 per diluted share, compared to Adjusted Net Loss of $2 million during the three months ended June 30, 2018, or $0.01 per diluted share.
Adjusted EBITDAX was $252 million, a 25% decrease compared to $335 million in the prior year period due to lower commodity pricing.
The following table details the components of average net production and average realized prices for the three months ended June 30, 2019:
Three months ended June 30, 2019 | ||||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane (Bbl/d) | Combined | ||||||||||||
Average Net Production | 2,288 | 10,331 | 105,228 | 40,882 | 3,226 | |||||||||||
Average Realized Prices | Natural Gas ($/Mcf) | Oil ($/Bbl) | C3+ NGLs ($/Bbl) | Ethane ($/Bbl) | Combined | |||||||||||
Average realized prices before settled derivatives | $ | 2.66 | $ | 52.19 | $ | 28.57 | $ | 8.16 | $ | 3.09 | ||||||
Settled commodity derivatives | 0.20 | 1.30 | 0.10 | — | 0.15 | |||||||||||
Average realized prices after settled derivatives | $ | 2.86 | $ | 53.49 | $ | 28.67 | $ | 8.16 | $ | 3.24 | ||||||
NYMEX average price | $ | 2.64 | $ | 59.78 | $ | 2.64 | ||||||||||
Premium / (Differential) to NYMEX | $ | 0.22 | $ | (6.29) | $ | 0.60 |
Net daily natural gas equivalent production in the second quarter averaged 3,226 MMcfe/d, including 156,441 Bbl/d of liquids (29% of production), an increase of 28% compared to the prior year period.
Total liquids production grew 38% compared to the prior year period. Liquids revenue represented approximately 39% of total product revenue before hedges. Oil production averaged 10,331 Bbl/d, an increase of 49% over the prior year period. C3+ NGLs production averaged 105,228 Bbl/d, an increase of 49% over the prior year period. Recovered ethane production averaged 40,882 Bbl/d, an increase of 13% over the prior year period.
Antero's average realized natural gas price before hedging was $2.66 per Mcf, representing a 6% decrease versus the prior year period and a $0.02 per Mcf premium to the average NYMEX Henry Hub price. Including hedges, Antero's average realized natural gas price was $2.86 per Mcf, a $0.22 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $43 million, or $0.20 per Mcf.
Antero's average realized C3+ NGL price before hedging was $28.57 per barrel, representing an 18% decrease versus the prior year period. Antero shipped 55% of total C3+ net volume on Mariner East 2 for export and realized a $0.19 per gallon premium to Mont Belvieu pricing on this volume at Marcus Hook. Antero sold the remaining 45% of C3+ net volume at a $0.14 per gallon discount to Mont Belvieu pricing at Hopedale.
Pricing Point | Net C3+ NGL | % by | Premium (Discount) | |||||
Propane / Butane shipped on ME2 | Marcus Hook | 57,864 | 55% | $0.19 | ||||
Remaining C3+ NGL volume (1) | Hopedale | 47,364 | 45% | ($0.14) | ||||
Total C3+ NGLs | 105,228 | 100% | $0.04 |
(1) Represents Antero C3+ volume sold by third-party midstream providers (domestically or internationally). |
Antero's average realized oil price before hedging was $52.19 per barrel, a $7.59 differential to the average NYMEX WTI price and a 15% decrease versus the prior year period. Including hedges, Antero's average realized oil price was $53.49 per barrel, a $6.29 differential to the average NYMEX WTI price, reflecting the realization of a cash settled oil hedge gain of $1 million. The average realized ethane price was $0.19 per gallon, or $8.16 per barrel, an 18% decrease compared to $0.24 per gallon, or $9.93 per barrel, in the prior year period.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.09 per Mcfe, representing an 8% decrease compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.24 per Mcfe, a 14% decrease from the prior year period. The net cash settled commodity derivative gain on all products was $45 million, or $0.15 per Mcfe.
Total revenue in the second quarter was $1.3 billion, a 31% increase compared to $1.0 billion in the prior year quarter. Revenue included a $284 million non-cash gain on unsettled commodity derivatives, while the prior year included a $41 million non-cash loss on unsettled derivatives. Revenue Excluding Unrealized Derivative Gains (Losses) (non-GAAP) was $1.0 billion, nearly equivalent to the prior year period.
The following table presents a calculation of Adjusted EBITDAX margin (non-GAAP measure) on a per Mcfe basis and a reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, and is a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations from period to period by removing the effect of its capital structure from its operating structure.
Three months ended June 30, | |||||||
2018 | 2019 | ||||||
Adjusted EBITDAX margin ($ per Mcfe): | |||||||
Realized price before cash receipts for settled derivatives | $ | 3.35 | 3.09 | ||||
Distributions/dividends from Antero Midstream | 0.18 | 0.17 | |||||
Marketing, net (1) | (0.30) | (0.25) | |||||
Gathering, compression, processing and transportation costs | (1.79) | (1.93) | |||||
Lease operating expense | (0.14) | (0.14) | |||||
Production and ad valorem taxes | (0.11) | (0.11) | |||||
General and administrative (excluding equity-based compensation) | (0.15) | (0.12) | |||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.04 | 0.71 | |||||
Cash receipts for settled commodity derivatives | 0.42 | 0.15 | |||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 1.46 | 0.86 |
(1) Includes cash payments for settled marketing derivative losses of $0.07 per Mcfe in 2018. |
Per unit cash production expense, which equals the sum of lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes was $2.18 per Mcfe, a 7% increase compared to $2.04 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.93 per Mcfe for gathering, compression, processing and transportation costs, $0.14 per Mcfe for lease operating costs, and $0.11 per Mcfe for production and ad valorem taxes. Per unit gathering, compression, processing and transportation costs reflect higher expenses related to the commencement of Mariner East 2 earlier this year that enabled Antero to in turn deliver higher C3+ NGL prices on volumes sold at the Marcus Hook terminal.
Per unit net marketing expense was $0.25 per Mcfe compared to $0.30 per Mcfe reported in the prior year period. Excluding prior year settled marketing derivative losses of $0.07 per Mcfe, net marketing expense modestly increased as the Company elected to utilize lower cost firm transportation based on price differentials in various markets. As a result, while net marketing expenses are tracking slightly above expectations, they are offset by per unit cash production costs modestly below expectations for the full year.
Per unit general and administrative expense, excluding non-cash equity-based compensation expense, decreased by 20% to $0.12 per Mcfe, compared to the prior year period. General and administrative expense on a per Mcfe basis decreased due to increased production levels and lower employee headcount.
Adjusted EBITDAX margin after commodity derivatives was $0.86 per Mcfe, a 41% decrease from the prior year period, primarily due lower realized prices relative to the prior year period.
Operating Update
Second Quarter 2019
Marcellus Shale — 40 horizontal Marcellus wells were placed to sales during the second quarter of 2019 with an average lateral length of 10,227 feet and an average 60-day rate per well of 18.8 MMcfe/d on choke. The 60-day average rate per well included 838 Bbl/d of liquids, representing oil, C3+ NGLs and 25% ethane recovery. Noteworthy results from the wells placed to sales during the quarter are below:
During the period, Antero drilled 23 wells with an average lateral length of 12,500 feet in an average of 12.6 total days from spud to final rig release, representing a 3% reduction in total drilling time from the prior year period despite a 30% increase in average lateral feet drilled per well. Additionally, Antero drilled an average of 5,470 lateral feet per day in the quarter, achieving its highest quarterly rate in the Company's history, representing a 3% sequential increase and a 17% increase compared to the 2018 average in lateral footage performance. Antero also recently achieved a new drilling milestone of 9,650 lateral feet drilled in a rolling 24-hour period, which the Company believes is a new world record. Antero's ongoing emphasis on completion efficiencies also resulted in material improvement during the second quarter, as the Company averaged 5.7 stages completed per day, representing a 14% increase from 5.0 stages per day in the prior year period.
Ohio Utica Shale — Antero placed 6 horizontal Utica wells to sales during the second quarter of 2019 with an average lateral length of 12,900 feet, an average BTU of 1,099 and an average 60-day rate per well of 22.7 MMcf/day on choke.
During the second quarter of 2019, Antero released one drilling rig and one completion crew. Antero plans to operate an average of four drilling rigs, including three large rigs, and an average of three to four completion crews, for the remainder of the year. For the full year, the Company continues to expect to drill 120 to 130 wells and place 115 to 125 wells online, consistent with prior guidance.
Second Quarter 2019 Capital Investment
Antero's accrued drilling and completion capital expenditures for the three months ended June 30, 2019, were $303 million. For a reconciliation of accrued drilling and completion capital expenditures to cash drilling and completion capital expenditures for the three months ended June 30, 2019, see the supplemental table at the end of this press release. In addition to capital invested in drilling and completion costs, the Company invested $29 million for land.
Balance Sheet and Liquidity
As of June 30, 2019, Antero's debt was $3.6 billion, of which $175 million were borrowings outstanding under the Company's revolving credit facility. During the quarter, Antero's 24 banks affirmed the Company's $4.5 billion borrowing base and total lender commitments under the facility remain unchanged at $2.5 billion. Antero's net debt to trailing twelve months Adjusted EBITDAX ratio was 2.3x.
President and CFO, Glen Warren, commented, "Antero remains focused on the best investment opportunities for the Company given the current macroeconomic backdrop. Our strong balance sheet provides us with the flexibility to execute our strategy in the coming years, as financial leverage is at an attractive 2.3x level and we have substantial liquidity. We believe our commodity hedges afford us the ability to advance our position as an industry leader through a measured growth program that captures the best revenue opportunities through our advantaged firm transportation portfolio and results in a reduction in overall costs including net marketing expense going forward. Accordingly, we have prioritized our development program with a commitment to our well cost initiatives that remain front and center at Antero."
Mr. Warren continued, "Antero's second quarter results highlighted the value of the Company's transportation to favorably priced markets. Antero's first full quarter with Mariner East 2 on line allowed the Company to achieve aggregate C3+ NGL realized prices at a $0.04 per gallon premium to Mont Belvieu, as 55% of volumes were exported at Marcus Hook. This is a particularly noteworthy achievement as C3+ products are typically sold at a substantial discount to Mont Belvieu in basin during the quarter. Antero's position as an anchor shipper differentiates the Company with access to international markets at a premium to Mont Belvieu."
Commodity Derivative Positions
Antero has hedged 2.0 Tcf of natural gas at a weighted average index price of $2.94 per MMBtu through 2023 with a combination of fixed price swap positions in 2019 through 2023 and collar agreements in 2019. Antero also has oil and NGL fixed price swap positions, including oil positions that totaled 5,000 Bbl/d at a weighted average price of approximately $60 per barrel from July 2019 through December 2020. As of June 30, 2019, the Company's estimated fair value of commodity derivative instruments was $716 million based on strip pricing.
Antero's estimated natural gas production for the second half of 2019 is fully hedged with a combination of fixed price swap positions and collars. As of June 30, 2019, the Company had fixed price swaps totaling 755,000 MMBtu/d of natural gas for July 2019 through December 2019 fixed at a weighted average price of $3.39 per MMBtu. Collar agreements for July 2019 through December 2019 total 1,575,000 MMBtu/d of natural gas at a weighted average floor and ceiling of $2.50 per MMBtu and $3.41 per MMBtu, respectively. During 2019, Antero also has oil fixed price swap positions on 5,000 Bbl/d at a weighted average price of $61.83 per barrel from July 2019 through December 2019.
Subsequent to June 30, 2019, and not included in the following tables, Antero added an incremental 4,000 Bbl/d of oil fixed price swap positions at a weighted average price of $56.58 per barrel from August 2019 through December 2019. For the period of August 2019 through December 2019, Antero has oil fixed price swap positions totaling 9,000 Bbl/d at a weighted average price of $59.50 per barrel.
Please see Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, for more information on all commodity derivative positions.
The following tables summarize Antero's natural gas hedge position as of June 30, 2019:
Fixed price natural gas positions from July 1, 2019 through December 31, 2023 were as follows:
Natural gas | Weighted | |||||||
Three months ending September 30, 2019: | ||||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.32 | |||||
Three months ending December 31, 2019: | ||||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.45 | |||||
Year ending December 31, 2020: | ||||||||
NYMEX ($/MMBtu) | 2,227,500 | $ | 2.87 | |||||
Year ending December 31, 2021: | ||||||||
NYMEX ($/MMBtu) | 1,010,000 | $ | 2.88 | |||||
Year ending December 31, 2022: | ||||||||
NYMEX ($/MMBtu) | 850,000 | $ | 3.00 | |||||
Year ending December 31, 2023: | ||||||||
NYMEX ($/MMBtu) | 90,000 | $ | 2.91 |
Natural gas collar positions from July 1, 2019 through December 31, 2019 were as follows:
Natural gas | Weighted average index price | ||||||||
MMBtu/day | Ceiling price | Floor price | |||||||
Three months ending September 30, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.30 | $ | 2.50 | ||||
Three months ending December 31, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.52 | $ | 2.50 |
Fixed price oil positions from July 1, 2019 through December 31, 2020 are as follows:
Oil | Weighted price | |||||||
Three months ending September 30, 2019: | ||||||||
NYMEX ($/Bbl) | 5,000 | $ | 61.83 | |||||
Three months ending December 31, 2019: | ||||||||
NYMEX ($/Bbl) | 5,000 | $ | 61.83 | |||||
Year ending December 31, 2020: | ||||||||
NYMEX ($/Bbl) | 5,000 | $ | 59.03 |
Conference Call
A conference call is scheduled on Thursday, August 1, 2019 at 9:00 am MT to discuss financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, August 8, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13689238.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, August 8, 2019 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Basis of Financial Presentation
In connection with the closing of the previously announced simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of June 30, 2019, Antero Resources owned 31% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to June 30, 2019, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described below reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue Excluding Unrealized Derivative (Gains) Losses as set forth in this release represents total revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue Excluding Unrealized Derivative (Gains) Losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance. The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses (in thousands):
Three months ended June 30, | ||||||
2018 | 2019 | |||||
Total revenue | $ | 989,344 | $ | 1,299,664 | ||
Commodity derivative fair value gains | (55,336) | (328,427) | ||||
Marketing derivative fair value losses | 110 | — | ||||
Gains on settled commodity derivatives | 95,884 | 44,699 | ||||
Losses on settled marketing derivatives | (15,884) | — | ||||
Revenue Excluding Unrealized Derivative Gains | $ | 1,014,118 | $ | 1,015,936 |
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income, adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following tables reconcile net income (loss) before income taxes to Adjusted Net Income (Loss) (in thousands):
Three months ended | ||||||
June 30, 2019 | ||||||
2018 | 2019 | |||||
Net income (loss) attributable to Antero Resources Corp | $ | (136,385) | $ | 42,168 | ||
Commodity derivative fair value gains | (55,336) | (328,427) | ||||
Gains on settled commodity derivatives | 95,884 | 44,699 | ||||
Marketing derivative fair value losses | 110 | — | ||||
Losses on settled marketing derivatives | (15,884) | — | ||||
Impairment of oil and gas properties | 134,437 | 130,999 | ||||
Impairment of gathering systems and facilities | 4,470 | — | ||||
Equity-based compensation | 13,204 | 6,549 | ||||
Loss on sale of assets | — | (951) | ||||
Contract termination and rig stacking | — | 5,604 | ||||
Tax effect of reconciling items (1) | (42,214) | 33,315 | ||||
Adjusted Net Loss | $ | (1,714) | $ | (66,044) | ||
Fully Diluted Shares Outstanding | 316,992 | 309,062 |
Per Share Amounts | ||||||
Three months ended | ||||||
June 30, 2019 | ||||||
2018 | 2019 | |||||
Net income (loss) attributable to Antero Resources Corp | $ | (0.43) | 0.14 | |||
Commodity derivative fair value gains | (0.17) | (1.06) | ||||
Gains on settled commodity derivatives | 0.30 | 0.14 | ||||
Losses on settled marketing derivatives | (0.05) | — | ||||
Impairment of oil and gas properties | 0.42 | 0.42 | ||||
Impairment of gathering systems and facilities | 0.01 | — | ||||
Equity-based compensation | 0.04 | 0.02 | ||||
Contract termination and rig stacking | — | 0.02 | ||||
Tax effect of reconciling items (1) | (0.13) | 0.11 | ||||
Adjusted Net Loss | $ | (0.01) | (0.21) |
(1) Deferred taxes were approximately 24% for 2018 and 24% for 2019. |
Adjusted Net Cash Provided by Operating Activities
Adjusted Net Cash Provided by Operating Activities as presented in this release represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated through March 12, 2019. Adjusted Net Cash Provided by Operating Activities is often used by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Net Cash Provided by Operating Activities is also useful because it is often used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Management believes that Adjusted Net Cash Provided by Operating Activities is a useful indicator of the company's ability to internally fund its activities and to service or incur additional debt.
There are significant limitations to using Adjusted Net Cash Provided by Operating Activities as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Net Cash Provided by Operating Activities reported by different companies. Adjusted Net Cash Provided by Operating Activities do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Net Cash Provided by Operating Activities is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. Furthermore, we may calculate such measures differently from similarly titled measures used by other companies.
The following table reconciles net cash provided by operating activities to Adjusted Net Cash Provided by Operating Activities as used in this release (in thousands):
Three months ended June 30, | |||||||
2018 | 2019 | ||||||
Net cash provided by operating activities | $ | 297,391 | 218,104 | ||||
Antero Midstream Partners net cash provided by (used in) operating activities (1) | (68,888) | — | |||||
Adjusted Net Cash Provided By Operating Activities | $ | 228,503 | 218,104 |
(1) Represents Antero Midstream Partners net cash provided by operating activities that was consolidated in Antero Resources' financial results in 2018. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company's financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | June 30, | ||||||
2018 | 2019 | ||||||
AR bank credit facility | $ | 405,000 | 175,000 | ||||
AM bank credit facility (1) | 990,000 | — | |||||
5.375% AR senior notes due 2021 | 1,000,000 | 1,000,000 | |||||
5.125% AR senior notes due 2022 | 1,100,000 | 1,100,000 | |||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | |||||
5.375% AM senior notes due 2024 (1) | 650,000 | — | |||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | |||||
Net unamortized premium | 1,241 | 1,095 | |||||
Net unamortized debt issuance costs (1) | (34,553) | (23,716) | |||||
Consolidated total debt | $ | 5,461,688 | 3,602,379 | ||||
Less: AR cash and cash equivalents | — | — | |||||
Less: AM cash and cash equivalents (1) | — | — | |||||
Consolidated net debt | $ | 5,461,688 | 3,602,379 | ||||
Less: Antero Midstream Partners debt net of cash and unamortized premium and debt issuance costs (1) | $ | 1,632,147 | — | ||||
Net Debt | $ | 3,829,541 | 3,602,379 |
(1) Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero's results |
Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company's financial performance because it:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
The following table represents a reconciliation of Adjusted EBITDAX to net income (loss), including noncontrolling interest, and net cash provided by operating activities per our consolidated statements of cash flows.
Three months ended June 30, | ||||||
(in thousands) | 2018 | 2019 | ||||
Reconciliation of net income (loss) to Adjusted EBITDAX: | ||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (136,385) | 42,168 | |||
Net income and comprehensive income attributable to noncontrolling interests | 69,110 | — | ||||
Commodity derivative fair value gains (1) | (55,336) | (328,427) | ||||
Gains on settled commodity derivatives (1) | 95,884 | 44,699 | ||||
Marketing derivative fair value (gains) losses (1) | 110 | — | ||||
Gains (losses) on settled marketing derivatives (1) | (15,884) | — | ||||
Loss on sale of assets | — | 951 | ||||
Interest expense, net | 69,349 | 54,164 | ||||
Income tax expense (benefit) | (25,573) | 17,249 | ||||
Depletion, depreciation, amortization, and accretion | 238,750 | 243,220 | ||||
Impairment of oil and gas properties | 134,437 | 130,999 | ||||
Impairment of gathering systems and facilities | 8,501 | — | ||||
Exploration expense | 1,471 | 314 | ||||
Equity-based compensation expense | 19,071 | 6,549 | ||||
Equity in earnings of unconsolidated affiliates | (9,264) | (13,585) | ||||
Distributions/dividends from unconsolidated affiliates | 10,810 | 47,922 | ||||
Contract termination and rig stacking | — | 5,604 | ||||
405,051 | 251,827 | |||||
Net income and comprehensive income attributable to noncontrolling interests | (69,110) | — | ||||
Antero Midstream Partners interest expense, net (2) | (14,961) | — | ||||
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2) | (40,414) | — | ||||
Antero Midstream Partners impairment | (4,031) | — | ||||
Antero Midstream Partners equity-based compensation expense (2) | (5,867) | — | ||||
Antero Midstream Partners equity in earnings of unconsolidated affiliates (2) | 9,264 | — | ||||
Antero Midstream Partners distributions from unconsolidated affiliates (2) | (10,810) | — | ||||
Equity in earnings of Antero Midstream Partners (2) | 26,926 | — | ||||
Distributions from Antero Midstream Partners (2) | 38,559 | — | ||||
Antero Midstream Partners related adjustments | (70,444) | — | ||||
Adjusted EBITDAX | $ | 334,607 | 251,827 | |||
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||
Adjusted EBITDAX | $ | 334,607 | 251,827 | |||
Antero Midstream Partners related adjustments | 70,444 | — | ||||
Interest expense, net | (69,349) | (54,164) | ||||
Exploration expense | (1,471) | (314) | ||||
Changes in current assets and liabilities | (37,803) | 31,910 | ||||
Other | — | (5,744) | ||||
Other non-cash items | 963 | (5,411) | ||||
Net cash provided by operating activities | $ | 297,391 | 218,104 | |||
Adjusted EBITDAX | $ | 334,607 | $ | 251,827 | ||
Production (MMcfe) | 229,318 | 293,595 | ||||
Adjusted EBITDAX margin per Mcfe | $ | 1.46 | $ | 0.86 |
(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization. | |||||||
(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 for further discussion on equity method investments. |
The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended June 30, 2019, as used in this release (in thousands):
Twelve months ended | |||||
(in thousands) | June 30, 2019 | ||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 744,966 | |||
Commodity derivative fair value losses | (85,692) | ||||
Gains on settled commodity derivatives | 187,678 | ||||
Marketing derivative fair value gains | 43 | ||||
Losses on settled marketing derivatives | (21,471) | ||||
Loss on sale of assets | 951 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | ||||
Interest expense | 226,390 | ||||
Income tax expense | 193,555 | ||||
Depletion, depreciation, amortization, and accretion | 909,012 | ||||
Impairment of oil and gas properties | 576,707 | ||||
Exploration expense | 2,042 | ||||
Gain on change in fair value of contingent acquisition consideration | 100,840 | ||||
Equity-based compensation expense | 34,167 | ||||
Equity in (earnings) loss of Antero Midstream Partners LP | (58,411) | ||||
Equity in (earnings) loss of unconsolidated affiliates | (15,402) | ||||
Distributions/dividends from Antero Midstream | 178,925 | ||||
Contract termination and rig stacking | 13,964 | ||||
Simplification transaction fees | 6,297 | ||||
Adjusted EBITDAX | $ | 1,588,519 |
Drilling and Completion Capital Expenditures
The following tables reconcile Antero's drilling and completion costs as reported on a cash basis to drilling and completion costs on an accrual basis (in thousands):
Three months ended June 30, | |||||||
2018 | 2019 | ||||||
Drilling and completion costs (as reported; cash basis) | $ | 392,913 | 311,401 | ||||
Drilling and completion costs paid to Antero Midstream Partners (cash basis) (1) | 73,919 | — | |||||
Adjusted drilling and completion costs (cash basis) | 466,832 | 311,401 | |||||
Change in accrued capital costs | (6,830) | (8,624) | |||||
Adjusted drilling and completion costs (accrual basis) | $ | 460,002 | 302,777 |
(1) Represents drilling and completion costs paid to Antero Midstream Partners that were consolidated in Antero Resources' financial results in 2018. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding expected results, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Adjusted Net Cash Provided by Operating Activities, leverage targets, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs and cost savings initiatives, including with respect to potential incremental flowback and produced water services by Antero Midstream, which are subject to approval by the Board of Antero Midstream, and there can be no assurance that such approval will be obtained, future financial position, future technical improvements, future marketing opportunities, expectations regarding the amount and timing of jury awards, the receipt of which are subject to final orders and the resolutions of appeals processes, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond the Antero's control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
ANTERO RESOURCES CORPORATION Condensed Consolidated Balance Sheets December 31, 2018 and June 30, 2019 (Unaudited) (In thousands, except per share amounts) | |||||||
December 31, 2018 | June 30, 2019 | ||||||
Assets | |||||||
Current assets: | |||||||
Accounts receivable | $ | 51,073 | 49,994 | ||||
Accrued revenue | 474,827 | 308,761 | |||||
Derivative instruments | 245,263 | 346,894 | |||||
Other current assets | 35,450 | 7,400 | |||||
Total current assets | 806,613 | 713,049 | |||||
Property and equipment: | |||||||
Oil and gas properties, at cost (successful efforts method): | |||||||
Unproved properties | 1,767,600 | 1,585,355 | |||||
Proved properties | 12,705,672 | 13,357,733 | |||||
Water handling and treatment systems | 1,013,818 | — | |||||
Gathering systems and facilities | 2,470,708 | 17,825 | |||||
Other property and equipment | 65,842 | 69,676 | |||||
18,023,640 | 15,030,589 | ||||||
Less accumulated depletion, depreciation, and amortization | (4,153,725) | (4,115,187) | |||||
Property and equipment, net | 13,869,915 | 10,915,402 | |||||
Operating leases right-of-use assets | — | 3,330,795 | |||||
Derivative instruments | 362,169 | 369,548 | |||||
Investments in unconsolidated affiliates | 433,642 | 1,967,203 | |||||
Other assets | 47,125 | 34,883 | |||||
Total assets | $ | 15,519,464 | 17,330,880 | ||||
Liabilities and Equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 66,289 | 44,758 | ||||
Accounts payable, related parties | — | 98,570 | |||||
Accrued liabilities | 465,070 | 358,680 | |||||
Revenue distributions payable | 310,827 | 301,032 | |||||
Derivative instruments | 532 | 274 | |||||
Short-term lease liabilities | 2,459 | 413,691 | |||||
Other current liabilities | 8,363 | 4,102 | |||||
Total current liabilities | 853,540 | 1,221,107 | |||||
Long-term liabilities: | |||||||
Long-term debt | 5,461,688 | 3,602,379 | |||||
Deferred income tax liability | 650,788 | 1,188,975 | |||||
Long-term lease liabilities | 2,873 | 2,920,754 | |||||
Other liabilities | 63,098 | 57,965 | |||||
Total liabilities | 7,031,987 | 8,991,180 | |||||
Commitments and contingencies (Notes 13 and 14) | |||||||
Equity: | |||||||
Stockholders' equity: | |||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | |||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 308,594 shares and 309,123 shares issued and outstanding at December 31, 2018 and June 30, 2019, respectively | 3,086 | 3,091 | |||||
Additional paid-in capital | 6,485,174 | 6,138,130 | |||||
Accumulated earnings | 1,177,548 | 2,198,479 | |||||
Total stockholders' equity | 7,665,808 | 8,339,700 | |||||
Noncontrolling interests in consolidated subsidiary | 821,669 | — | |||||
Total equity | 8,487,477 | 8,339,700 | |||||
Total liabilities and equity | $ | 15,519,464 | 17,330,880 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2018 and 2019 (Unaudited) (In thousands, except per share amounts) | |||||||
Three Months Ended June 30, | |||||||
2018 | 2019 | ||||||
Revenue and other: | |||||||
Natural gas sales | $ | 473,540 | 553,372 | ||||
Natural gas liquids sales | 255,985 | 303,963 | |||||
Oil sales | 38,873 | 49,062 | |||||
Commodity derivative fair value gains | 55,336 | 328,427 | |||||
Gathering, compression, water handling and treatment | 5,518 | — | |||||
Marketing | 160,202 | 63,080 | |||||
Marketing derivative fair value losses | (110) | — | |||||
Other income | — | 1,760 | |||||
Total revenue | 989,344 | 1,299,664 | |||||
Operating expenses: | |||||||
Lease operating | 30,164 | 40,857 | |||||
Gathering, compression, processing, and transportation | 307,786 | 566,834 | |||||
Production and ad valorem taxes | 25,891 | 30,968 | |||||
Marketing | 213,420 | 137,539 | |||||
Exploration | 1,471 | 314 | |||||
Impairment of oil and gas properties | 134,437 | 130,999 | |||||
Impairment of gathering systems and facilities | 8,501 | — | |||||
Depletion, depreciation, and amortization | 238,050 | 242,302 | |||||
Loss on sale of assets | — | 951 | |||||
Accretion of asset retirement obligations | 700 | 918 | |||||
General and administrative (including equity-based compensation expense of $19,071 and $6,549 in 2018 and 2019, respectively) | 61,687 | 42,382 | |||||
Contract termination and rig stacking | — | 5,604 | |||||
Total operating expenses | 1,022,107 | 1,199,668 | |||||
Operating income (loss) | (32,763) | 99,996 | |||||
Other income (expenses): | |||||||
Equity in earnings of unconsolidated affiliates | 9,264 | 13,585 | |||||
Interest expense, net | (69,349) | (54,164) | |||||
Total other expenses | (60,085) | (40,579) | |||||
Income (loss) before income taxes | (92,848) | 59,417 | |||||
Provision for income tax (expense) benefit | 25,573 | (17,249) | |||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | (67,275) | 42,168 | |||||
Net income and comprehensive income attributable to noncontrolling interests | 69,110 | — | |||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (136,385) | 42,168 | ||||
Earnings (loss) per common share—basic | $ | (0.43) | 0.14 | ||||
Earnings (loss) per common share—assuming dilution | $ | (0.43) | 0.14 | ||||
Weighted average number of shares outstanding: | |||||||
Basic | 316,992 | 309,062 | |||||
Diluted | 316,992 | 309,137 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2018 and 2019 (Unaudited) (In thousands) | |||||||
Six Months Ended June 30, | |||||||
2018 | 2019 | ||||||
Cash flows provided by (used in) operating activities: | |||||||
Net income including noncontrolling interests | $ | 13,535 | 1,067,924 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depletion, depreciation, amortization, and accretion | 467,684 | 484,397 | |||||
Impairment of oil and gas properties | 184,973 | 212,243 | |||||
Impairment of gathering systems and facilities | 8,501 | 6,982 | |||||
Commodity derivative fair value gains | (77,773) | (251,059) | |||||
Gains on settled commodity derivatives | 197,225 | 141,791 | |||||
Marketing derivative fair value gains | (94,124) | — | |||||
Gains on settled marketing derivatives | 94,158 | — | |||||
Deferred income tax expense (benefit) | (16,453) | 304,963 | |||||
Loss on sale of assets | — | 951 | |||||
Equity-based compensation expense | 40,227 | 15,452 | |||||
Equity in earnings of unconsolidated affiliates | (17,126) | (27,666) | |||||
Distributions/dividends of earnings from unconsolidated affiliates | 17,895 | 60,527 | |||||
Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042) | |||||
Other | 1,932 | 5,670 | |||||
Changes in current assets and liabilities: | |||||||
Accounts receivable | 10,237 | 5,848 | |||||
Accrued revenue | (21,092) | 166,066 | |||||
Other current assets | 2,353 | 2,307 | |||||
Accounts payable including related parties | 2,948 | (2,424) | |||||
Accrued liabilities | 24,065 | (22,146) | |||||
Revenue distributions payable | 1,617 | (9,795) | |||||
Other current liabilities | (1,842) | 1,119 | |||||
Net cash provided by operating activities | 838,940 | 757,108 | |||||
Cash flows provided by (used in) investing activities: | |||||||
Additions to unproved properties | (87,861) | (56,814) | |||||
Drilling and completion costs | (752,781) | (680,088) | |||||
Additions to water handling and treatment systems | (58,127) | (24,416) | |||||
Additions to gathering systems and facilities | (206,753) | (48,239) | |||||
Additions to other property and equipment | (3,502) | (4,629) | |||||
Investments in unconsolidated affiliates | (56,297) | (25,020) | |||||
Proceeds from the Antero Midstream Partners LP Transactions | — | 296,611 | |||||
Change in other assets | (7,026) | (4,974) | |||||
Proceeds from asset sales | — | 1,983 | |||||
Net cash used in investing activities | (1,172,347) | (545,586) | |||||
Cash flows provided by (used in) financing activities: | |||||||
Issuance of senior notes | — | 650,000 | |||||
Borrowings (repayments) on bank credit facilities, net | 485,000 | (145,000) | |||||
Payments of deferred financing costs | — | (8,259) | |||||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (119,023) | (85,076) | |||||
Employee tax withholding for settlement of equity compensation awards | (7,967) | (2,295) | |||||
Other | (2,436) | (1,360) | |||||
Net cash provided by financing activities | 355,574 | 408,010 | |||||
Effect of deconsolidation of Antero Midstream Partners LP | — | (619,532) | |||||
Net increase in cash and cash equivalents | 22,167 | — | |||||
Cash and cash equivalents, beginning of period | 28,441 | — | |||||
Cash and cash equivalents, end of period | $ | 50,608 | — | ||||
Supplemental disclosure of cash flow information: | |||||||
Cash paid during the period for interest | $ | 130,231 | 119,180 | ||||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | $ | 2,089 | (33,240) |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the three months ended June 30, 2018 and 2019: | ||||||||||||
Three months ended June 30, | Amount of Increase | Percent | ||||||||||
(in thousands) | 2018 | 2019 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 473,540 | $ | 553,372 | $ | 79,832 | 17 | % | ||||
NGLs sales | 255,985 | 303,963 | 47,978 | 19 | % | |||||||
Oil sales | 38,873 | 49,062 | 10,189 | 26 | % | |||||||
Commodity derivative fair value gains | 55,336 | 328,427 | 273,091 | 494 | % | |||||||
Gathering, compression, water handling and treatment | 5,518 | — | (5,518) | (100) | % | |||||||
Marketing | 160,202 | 63,080 | (97,122) | (61) | % | |||||||
Marketing derivative fair value gains | (110) | — | 110 | (100) | % | |||||||
Other income | — | 1,760 | 1,760 | * | ||||||||
Total revenue | 989,344 | 1,299,664 | 310,320 | 31 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 30,164 | 40,857 | 10,693 | 35 | % | |||||||
Gathering, compression, processing, and transportation | 307,786 | 566,834 | 259,048 | 84 | % | |||||||
Production and ad valorem taxes | 25,891 | 30,968 | 5,077 | 20 | % | |||||||
Marketing | 213,420 | 137,539 | (75,881) | (36) | % | |||||||
Exploration | 1,471 | 314 | (1,157) | (79) | % | |||||||
Impairment of oil and gas properties | 134,437 | 130,999 | (3,438) | (3) | % | |||||||
Impairment of gathering systems and facilities | 8,501 | — | (8,501) | (100) | % | |||||||
Depletion, depreciation, and amortization | 238,050 | 242,302 | 4,252 | 2 | % | |||||||
Loss on sale of assets | — | 951 | 951 | * | ||||||||
Accretion of asset retirement obligations | 700 | 918 | 218 | 31 | % | |||||||
General and administrative (excluding equity-based compensation) | 42,616 | 35,833 | (6,783) | (16) | % | |||||||
Equity-based compensation | 19,071 | 6,549 | (12,522) | (66) | % | |||||||
Contract termination and rig stacking | — | 5,604 | 5,604 | * | ||||||||
Total operating expenses | 1,022,107 | 1,199,668 | 177,561 | 17 | % | |||||||
Operating income (loss) | (32,763) | 99,996 | 132,759 | (405) | % | |||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliate | 9,264 | 13,585 | 4,321 | 47 | % | |||||||
Interest expense | (69,349) | (54,164) | 15,185 | (22) | % | |||||||
Total other expenses | (60,085) | (40,579) | 19,506 | (32) | % | |||||||
Income (loss) before income taxes | (92,848) | 59,417 | 152,265 | (164) | % | |||||||
Income tax (expense) benefit | 25,573 | (17,249) | (42,822) | (167) | % | |||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | (67,275) | 42,168 | 109,443 | (163) | % | |||||||
Net income and comprehensive income attributable to noncontrolling interest | 69,110 | — | (69,110) | (100) | % | |||||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | (136,385) | $ | 42,168 | $ | 178,553 | (131) | % | ||||
Adjusted EBITDAX | $ | 334,607 | $ | 251,827 | $ | (82,780) | (25) | % | ||||
* Not meaningful | ||||||||||||
Three months ended June 30, | Amount of Increase | Percent | ||||||||||
2018 | 2019 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 167 | 208 | 41 | 25 | % | |||||||
C2 Ethane (MBbl) | 3,290 | 3,720 | 430 | 13 | % | |||||||
C3+ NGLs (MBbl) | 6,414 | 9,576 | 3,162 | 49 | % | |||||||
Oil (MBbl) | 632 | 940 | 308 | 49 | % | |||||||
Combined (Bcfe) | 229 | 294 | 65 | 28 | % | |||||||
Daily combined production (MMcfe/d) | 2,520 | 3,226 | 706 | 28 | % | |||||||
Average prices before effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 2.83 | $ | 2.66 | $ | (0.17) | (6) | % | ||||
C2 Ethane (per Bbl) | $ | 9.93 | $ | 8.16 | $ | (1.77) | (18) | % | ||||
C3+ NGLs (per Bbl) | $ | 34.81 | $ | 28.57 | $ | (6.24) | (18) | % | ||||
Oil (per Bbl) | $ | 61.55 | $ | 52.19 | $ | (9.36) | (15) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.35 | $ | 3.09 | $ | (0.26) | (8) | % | ||||
Average realized prices after effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 3.50 | $ | 2.86 | $ | (0.64) | (18) | % | ||||
C2 Ethane (per Bbl) | $ | 9.93 | $ | 8.16 | $ | (1.77) | (18) | % | ||||
C3+ NGLs (per Bbl) | $ | 33.10 | $ | 28.67 | $ | (4.43) | (13) | % | ||||
Oil (per Bbl) | $ | 52.11 | $ | 53.49 | $ | 1.38 | 3 | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.77 | $ | 3.24 | $ | (0.53) | (14) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.14 | $ | 0.14 | $ | — | — | % | ||||
Gathering, compression, processing, and transportation | $ | 1.79 | $ | 1.93 | $ | 0.14 | 8 | % | ||||
Production and ad valorem taxes | $ | 0.11 | $ | 0.11 | $ | — | — | % | ||||
Marketing expense, net | $ | 0.23 | $ | 0.25 | $ | 0.02 | 9 | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.88 | $ | 0.83 | $ | (0.05) | (6) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.15 | $ | 0.12 | $ | (0.03) | (20) | % |
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SOURCE Antero Resources Corporation
DENVER, July 10, 2019 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its second quarter earnings release on Wednesday, July 31, 2019 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, August 1, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, August 8, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13689238.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, August 8, 2019 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, June 12, 2019 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero Resources" or the "Company") announced today the appointment of Benjamin A. Hardesty as Lead Director. The Company also announced that Peter R. Kagan and James R. Levy have resigned from the board of directors of Antero Resources (the "Board") effective immediately. Mr. Kagan and Mr. Levy are both Partners at Warburg Pincus & Co., a leading global private equity firm focused on growth investing, and their resignations follow the recent divestiture of Warburg Pincus' remaining interests in Antero Resources. These resignations have reduced the size of the Antero Resources Board to seven directors, five of whom are independent under the New York Stock Exchange's listing standards. Mr. Kagan will remain on the board of directors of Antero Midstream Corporation.
Paul Rady, Chairman and Chief Executive Officer of Antero Resources, commented on the appointment of Mr. Hardesty as Lead Director, "As former President of Dominion E&P with well-established industry, regulatory and corporate connections in our areas of operation, we believe Ben will be a terrific Lead Director. We look forward to working more closely with him on the strategic direction of our company and on the further development of our world class asset."
Mr. Rady also commented on the resignations of Mr. Kagan and Mr. Levy as directors, "Peter and James have been involved with the board of Antero Resources since its formation in 2003, and have made substantial contributions to the Company. I want to thank Warburg Pincus and both Peter and James for all of their support over the years and wish them well."
Commenting on his and Mr. Levy's resignations, Mr. Kagan said, "It has been a privilege to be associated with Antero Resources for nearly two decades. As seasoned investors in the energy space, Warburg Pincus has made a number of investments in the sector. Antero has consistently proven to be a valued investment partner as illustrated by the quality of its assets as well as its importance in the energy industry. I believe Antero is well-positioned to continue to be an industry leader for years to come, and we wish the Antero team continued success."
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, May 1, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero," "Antero Resources", or the "Company") today released its first quarter 2019 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, which has been filed with the Securities and Exchange Commission ("SEC").
Basis of Financial Presentation
In connection with the closing of the previously announced simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP ("Antero Midstream Partners") on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation ("Antero Midstream") and Antero Midstream Partners became Antero Midstream's wholly owned subsidiary. As of March 31, 2019, Antero Resources owned 31% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners' results were consolidated within Antero Resources' results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources' interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources' results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019 to March 31, 2019, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results discussed below reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.
Antero Resources First Quarter 2019 Highlights Include:
Paul Rady, Chairman and CEO said, "We begin 2019 with significant momentum driven by both organizational and operational achievements. On the organizational front, we closed the midstream simplification transaction in mid-March and reduced leverage to 2.1x with the cash proceeds. We also deconsolidated Antero Midstream financials from Antero Resources. We believe this will result in more transparency for the upstream business and create a simpler story going forward. On the operational front, we began shipping propane and butane on Mariner East 2 to the Marcus Hook dock for export in February. This has resulted in a material uplift to our cash flow, as international spreads to Mont Belvieu have been attractive. We are the anchor shipper on Mariner East 2 with nearly one-third of the total available capacity under contract and additional expansion rights. As the largest liquids producer in the U.S. with this geographical advantage out of the Northeast through Mariner East 2, we are well positioned to achieve superior margins on our liquids volumes going forward."
Recent Developments
Natural Gas Liquids (NGLs) Update
Beginning in February, Antero gained access to the international LPG markets via its commitment on the Mariner East 2 pipeline to the Marcus Hook Terminal located near Philadelphia, Pennsylvania on the Delaware River. Antero has 50,000 Bbl/d of firm capacity on Mariner East 2, comprised of 35,000 Bbl/d for propane and 15,000 Bbl/d for butane, representing nearly one-third of the total Mariner East 2 capacity today. Antero also has expansion rights on Mariner East 2 that would allow the Company to double its total firm capacity to 100,000 Bbl/d.
As a result of this substantial exposure to international LPG markets, Antero was able to realize average C3+ NGL prices that were at a premium to Mont Belvieu pricing during February and March. Antero's average realized C3+ NGL realized price before hedging improved from 52% of WTI in January to 61% of WTI, on average, in February and March. Despite Mont Belvieu prices being at historical lows as a percentage of WTI during the first quarter partly due to various shipping constraints, Antero was able to significantly benefit from exporting nearly 30% of its C3+ NGLs. For example, in February and March, propane and butane products were sold at a weighted average premium to Mont Belvieu of $0.13 and $0.29 per gallon, respectively, at Marcus Hook.
C3+ NGL Product Destination Composition for the First Quarter 2019
As shown in the table below, for the full quarter, Antero shipped 29% of total C3+ net volume on Mariner East 2 for export and realized a $0.17 per gallon premium to Mont Belvieu pricing on this volume at Marcus Hook. Antero sold the remaining 71% of C3+ net volume at a $0.09 discount to Mont Belvieu pricing at Hopedale. For the remaining three quarters of 2019, Antero expects to ship approximately 50% of C3+ NGL production on Mariner East 2 for export assuming that Mariner East 2 does not increase to full capacity of 275,000 Bbl/d before year-end 2019. If the capacity increases, Antero will likely ship a higher percentage of volume on Mariner East 2.
Pricing Point | Net C3+ NGL | % by | Premium (Discount) | ||||
Propane / Butane shipped on ME2 | Marcus Hook | 28,795 | 29% | $0.17 | |||
Remaining C3+ NGL volume (1) | Hopedale | 68,915 | 71% | ($0.09) | |||
Total C3+ NGLs | 97,710 | 100% | ($0.01) |
(1) Represents Antero C3+ volume sold by third-party midstream providers (domestically or internationally via exports). |
C3+ NGL 2019 Pricing Update
For the full year of 2019, Antero expects to receive an approximate $4 per barrel improvement in C3+ NGL pricing compared to the original guidance issued in January 2019 when the WTI futures oil price averaged approximately $50 per barrel for 2019. This equates to 55% to 60% of the current WTI strip pricing of $61 per barrel for 2019. As it pertains to C3+ volumes sold at Hopedale, Antero anticipates wider price differentials relative to Mont Belvieu during the second and third quarters and tighter price differentials during the fourth quarter, based on current strip pricing.
2019 – Initial | 2019 – Revised | 2019 – Variance | |||||||||
Low | High | Low | High | Low | High | ||||||
C3+ NGL Pricing ($/Bbl) | $30.00 | $32.50 | $33.55 | $36.60 | $3.55 | $4.10 | |||||
NYMEX WTI Oil Price ($/Bbl) | $50.00 | $50.00 | $61.00 (1) | $61.00 (1) | |||||||
Implied C3+ NGL Pricing % of WTI | 60% | 65% | 55% | 60% |
(1) Revised WTI based on strip pricing as of April 30, 2019. |
2019 Ethane Production Guidance
During the first quarter, driven by contracted volumes and volumes required to meet pipeline specifications, Antero recovered 38,989 Bbl/d of ethane. This represented approximately 11,000 Bbl/d less volume than Antero's prior guidance, which was based on ethane pricing that supported further economic ethane recovery. This resulted in 50 MMcfe/d less production during the first quarter on a natural gas equivalent basis. Importantly, Antero has the flexibility to reject any remaining ethane in the stream above its contracted volume and volumes required to meet pipeline specifications and sell the ethane at natural gas value to maximize overall profitability and cash flow.
Based on current strip pricing as of April 30, 2019 for ethane, for the remainder of 2019, Antero intends to continue recovering ethane only at levels necessary to fulfill ethane contracts and meet pipeline specs. For the full year of 2019, Antero expects to recover total ethane volumes in a range of 38,000 to 42,000 barrels per day, down from a previously guided range of 48,000 to 52,000 barrels per day set in January 2019. To the extent ethane prices improve to levels that support ethane recovery economics, Antero intends to elect to recover additional ethane volumes. There has been no change to the expected production guidance range for the year of 3,150 MMcfe/d to 3,250 MMcfe/d.
Borrowing Base Reaffirmed at $4.5 Billion
As a result of the recent spring borrowing base redetermination, the borrowing base under Antero Resources' credit facility was reaffirmed at $4.5 billion. Lender commitments under the facility will remain at $2.5 billion. The bank syndicate is currently comprised of 24 banks. As of March 31, 2019, Antero had $50 million of outstanding borrowings under its credit facility.
First Quarter 2019 Financial Results
For the three months ended March 31, 2019, Antero reported GAAP net income of $979 million, or $3.17 per diluted share, compared to GAAP net income of $15 million, or $0.05 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," Adjusted Net Income was $108 million, or $0.35 per diluted share, compared to an Adjusted Net Income of $136 million during the three months ended March 31, 2018, or $0.43 per diluted share.
Adjusted EBITDAX was $443 million, a 9% decrease compared to $488 million in the prior year period, due to a substantial gain for settled marketing derivatives in the prior year period as a result of extreme cold weather conditions in the Northeast in January 2018.
The following table details the components of average net production and average realized prices for the three months ended March 31, 2019:
Three months ended March 31, 2019 | ||||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane (Bbl/d) | Combined | ||||||||||||
Average Net Production | 2,211 | 11,305 | 97,710 | 38,989 | 3,099 | |||||||||||
Average Realized Prices | Natural Gas | Oil ($/Bbl) | C3+ NGLs | Ethane ($/Bbl) | Combined | |||||||||||
Average realized prices before settled derivatives | $ | 3.30 | $ | 47.23 | $ | 31.63 | $ | 10.12 | $ | 3.65 | ||||||
Settled commodity derivatives | 0.49 | — | (0.04) | — | 0.35 | |||||||||||
Average realized prices after settled derivatives | $ | 3.79 | $ | 47.23 | $ | 31.59 | $ | 10.12 | $ | 4.00 | ||||||
NYMEX average price | $ | 3.15 | $ | 54.83 | $ | 3.15 | ||||||||||
Premium / (Differential) to NYMEX | $ | 0.64 | $ | (7.60) | $ | 0.85 |
Net daily natural gas equivalent production in the first quarter averaged 3,099 MMcfe/d, including 148,003 Bbl/d of liquids (29% of production), an increase of 30% compared to the prior year period.
Total liquids production grew 44% compared to the prior year period. Liquids revenue represented approximately 35% of total product revenue before hedges. Oil production averaged 11,305 Bbl/d, an increase of 92% over the prior year period. C3+ NGLs production averaged 97,710 Bbl/d, an increase of 54% over the prior year period. Recovered ethane production averaged 38,989 Bbl/d, an increase of 16% over the prior year period. The Mariner East 1 pipeline was temporarily taken out of service during the quarter. As a result, Antero elected to reject larger ethane volumes and sell as higher BTU natural gas, realizing a better net price relative to ethane netback pricing during the quarter, highlighting the flexibility offered by Antero's firm transportation portfolio during periods of operational downtime.
Antero's average realized natural gas price before hedging was $3.30 per Mcf, representing a 5% increase versus the prior year period and a $0.15 per Mcf premium to the average NYMEX Henry Hub price. Including hedges, Antero's average realized natural gas price was $3.79 per Mcf, a $0.64 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $97 million, or $0.49 per Mcf.
Antero's average realized C3+ NGL price before hedging was $31.63 per barrel, or 58% of the average NYMEX WTI oil price, representing a 13% increase versus the prior year period. Antero's average realized C3+ NGL price before hedging during the February and March months was $34.70 per barrel, representing 61% of the average NYMEX WTI oil price, and improving by 29% from $26.88 per barrel during the month of January. Antero's average realized C2+ NGL price before hedging was $25.50 per barrel, or 47% of the average NYMEX WTI oil price.
Antero's average realized oil price before hedging was $47.23 per barrel, a $7.60 differential to the average NYMEX WTI price and a 17% decrease versus the prior year period. The average realized ethane price was $0.24 per gallon, or $10.12 per barrel, a 13% increase compared to $0.21 per gallon, or $8.94 per barrel, in the prior year period.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.65 per Mcfe, representing a 3% increase compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $4.00 per Mcfe, a 1% decrease from the prior year period. The net cash settled commodity derivative gain on all products was $97 million, or $0.35 per Mcfe.
Total revenue in the first quarter was $1.0 billion, approximately equivalent to the prior year period. Revenue included a $174 million non-cash loss on unsettled commodity derivatives, while the prior year included a $95 million non-cash loss on unsettled derivatives. Revenue Excluding Unrealized Derivative Gains (Losses) (non-GAAP) was $1.2 billion, an 8% increase versus the prior year period.
Adjusted Net Cash Provided by Operating Activities was $485 million during the first quarter.
The following table presents a calculation of Adjusted EBITDAX margin (non-GAAP measure) on a per Mcfe basis and a reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations from period to period by removing the effect of its capital structure from its operating structure.
Three months ended March 31, | ||||||
2018 | 2019 | |||||
Adjusted EBITDAX margin ($ per Mcfe): | ||||||
Realized price before cash receipts for settled derivatives | $ | 3.56 | 3.65 | |||
Distributions from Antero Midstream | 0.19 | 0.17 | ||||
Marketing, net (1) | 0.27 | (0.26) | ||||
Gathering, compression, processing and transportation costs | (1.80) | (1.92) | ||||
Lease operating expense | (0.15) | (0.15) | ||||
Production and ad valorem taxes | (0.12) | (0.12) | ||||
General and administrative (excluding equity-based compensation) (2) | (0.15) | (0.13) | ||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.80 | 1.24 | ||||
Cash receipts for settled commodity derivatives | 0.48 | 0.35 | ||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 2.28 | 1.59 |
(1) Includes cash payments for settled marketing derivative gains of $0.49 per Mcfe in 2018. |
(2) Excludes $6.3 million related to one-time midstream simplification transaction fees. |
Per unit cash production expense, which equals the sum of lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes, was $2.19 per Mcfe, a 6% increase compared to $2.07 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.92 per Mcfe for gathering, compression, processing and transportation costs, $0.15 per Mcfe for lease operating costs, and $0.12 per Mcfe for production and ad valorem taxes. Per unit gathering, compression, processing and transportation costs reflect higher expenses related to the commencement of Mariner East 2 pipeline in February 2019 that enabled Antero to in turn deliver higher C3+ NGL prices on volumes sold at the Marcus Hook terminal.
Per unit net marketing expense was $0.26 per Mcfe compared to $0.27 per Mcfe gain reported in the prior year period. Excluding prior year settled marketing derivative gains of $0.49 per Mcfe, net marketing expense modestly increased due to higher unutilized capacity related to incremental firm transportation that was placed in service during the previous quarter with the completion of TransCanada subsidiary Columbia Pipeline Group's Mountaineer Xpress and Gulf Xpress. All of Antero's natural gas firm transportation commitments are now in service. The first quarter 2019 net marketing expense is expected to decline materially over the next couple of years as the firm transportation commitments are filled with Antero production growth.
Per unit general and administrative expense, excluding non-cash equity-based compensation expense and $6.3 million in non-recurring midstream simplification transaction fees, decreased by 9% to $0.13 per Mcfe, compared to the prior year period. General and administrative expense on a per Mcfe basis decreased due to increased production levels.
Adjusted EBITDAX margin after commodity derivatives was $1.59 per Mcfe, a 30% decrease from the prior year period, primarily due to a substantial gain for settled marketing derivatives in the prior year period. Excluding prior year settled marketing derivatives, adjusted EBITDAX margin declined 4%.
Operating Update
First Quarter 2019
Marcellus Shale — Antero placed 23 horizontal Marcellus wells to sales during the first quarter of 2019 with an average lateral length of 9,500 feet and an average 60-day rate per well of 18.6 MMcfe/day on choke. The 60-day average rate per well included 953 Bbl/d of liquids, including oil, C3+ NGLs and assuming 25% ethane recovery. Noteworthy results from the wells placed to sales during the first quarter are below:
During the period, Antero drilled 36 wells with an average lateral length of 10,000 feet in an average of 11.6 total days from spud to final rig release, which represents a 6% reduction in total drilling time from 2018 levels. In addition, Antero drilled an average of 5,300 lateral feet per day in the quarter, the highest quarterly rate in company history, representing a 14% increase in lateral footage performance compared to 2018. And also, significantly, Antero set what it believes is a world record for a horizontal well by drilling 9,184 feet of lateral in 24 hours. Completion efficiencies also improved materially during the first quarter, as the Company averaged 5.3 stages per day, a 23% increase from 4.3 stages per day during the first quarter of 2018.
For the remainder of 2019, Antero plans to operate an average of four drilling rigs, including three large rigs, and an average of three completion crews. This is a reduction from the five drillings rigs and four completion crews operating in the first quarter. In 2019, the Company expects to drill 120 to 130 wells and place 115 to 125 wells online, which is consistent with the Company's prior guidance.
First Quarter 2019 Capital Investment
Antero's accrued drilling and completion capital expenditures for the three months ended March 31, 2019, were $380 million. Antero placed 23 wells to sales and drilled 36 wells during the first quarter. As a result of the reduced drilling rig and completion crew count for the remainder of 2019, Antero expects the drilling and completion capital expenditures in the second and third quarters of 2019 to be in the low $300 million range. Additionally, Antero is reducing its 2019 drilling and completion capital budget to $1.3 billion to $1.375 billion. Approximately 65 For a reconciliation of accrued drilling and completion capital expenditures to cash drilling and completion capital expenditures for the three months ended March 31, 2019, see the supplemental table at the end of this press release.
In addition to capital invested in drilling and completion costs, the Company invested $27 million for land.
President and CFO, Glen Warren, commented, "Antero Resources is a clear leader in the Appalachian basin, with a highly profitable business driven by our leading natural gas liquids and natural gas sales portfolios. With the largest exposure to favorably priced international markets on the NGL side, and a firm transportation portfolio on the natural gas side that reaches the top demand centers in the U.S., particularly the LNG corridor. Antero is well positioned to continue delivering best-in-class EBITDA margins and growing the business. We believe profitable growth, a strong balance sheet and greater transparency in our financial statements provide an attractive value for investors today."
Mr. Warren continued, "The financial and operational achievements of the first quarter provide us with significant momentum for the remainder of the year. We brought 23 wells to sales during the quarter, and an additional 23 wells in the month of April, driving an attractive growth trajectory, which we expect to achieve at lower quarterly capital expenditures in the coming quarters."
Balance Sheet and Liquidity
As of March 31, 2019, Antero's debt was $3.5 billion, of which $50 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility were $2.5 billion. Debt to trailing twelve months Adjusted EBITDAX ratio was 2.1x.
Commodity Derivative Positions
Antero has hedged 1.3 Tcf of natural gas at a weighted average index price of $3.05 per MMBtu through 2023 with a combination of fixed price swap positions and collar agreements. Antero also has oil hedges entered into subsequent to the end of the first quarter of 2019 that totaled 5,000 Bbls/day at a weighted average price of $60.16 from May 2019 through December 2020. As of March 31, 2019, the Company's estimated fair value of commodity derivative instruments was $432 million.
Antero's estimated natural gas production for 2019 is fully hedged with a combination of fixed price swap positions and collar agreements. As of March 31, 2019, the Company had fixed price swaps totaling 755,000 MMbtu/day of natural gas for April 2019 through December 2019 fixed at a weighted average price of $3.34 per MMbtu. Collar agreements for April 2019 through December 2019 total 1,575,000 MMBtu/day of natural gas at a weighted average floor and ceiling of $2.50 and $3.37, respectively. During 2019, Antero also has oil fixed price swap positions on 5,000 Bbls/day at a weighted average price of $61.83 from May 2019 through December 2019.
Please see Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, for more information on all commodity derivative positions.
The following tables summarize Antero's natural gas hedge position as of March 31, 2019:
Fixed price natural gas positions from April 1, 2019 through December 31, 2023 were as follows:
Natural gas | Weighted | |||||
Three months ending June 30, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.26 | |||
Total | 755,000 | |||||
Three months ending September 30, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.32 | |||
Total | 755,000 | |||||
Three months ending December 31, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.45 | |||
Total | 755,000 | |||||
Year ending December 31, 2020: | ||||||
NYMEX ($/MMBtu) | 1,417,500 | $ | 3.00 | |||
Year ending December 31, 2021: | ||||||
NYMEX ($/MMBtu) | 710,000 | $ | 3.00 | |||
Year ending December 31, 2022: | ||||||
NYMEX ($/MMBtu) | 850,000 | $ | 3.00 | |||
Year ending December 31, 2023: | ||||||
NYMEX ($/MMBtu) | 90,000 | $ | 2.91 |
Natural gas collar positions from April 1, 2019 through December 31, 2019 were as follows:
Natural gas | Weighted average index price | ||||||||
MMbtu/day | Ceiling price | Floor price | |||||||
Three months ending June 30, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.30 | $ | 2.50 | ||||
Three months ending September 30, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.30 | $ | 2.50 | ||||
Three months ending December 31, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.52 | $ | 2.50 |
Fixed price oil positions from May 1, 2019 through December 31, 2020 are as follows:
Oil | Weighted | |||||
Three months ending June 30, 2019: | ||||||
NYMEX WTI ($/Bbl) | 3,352 | $ | 61.83 | |||
Three months ending September 30, 2019: | ||||||
NYMEX WTI ($/Bbl) | 5,000 | $ | 61.83 | |||
Three months ending December 31, 2019: | ||||||
NYMEX WTI ($/Bbl) | 5,000 | $ | 61.83 | |||
Year ending December 31, 2020: | ||||||
NYMEX WTI ($/Bbl) | 5,000 | $ | 59.03 |
Conference Call
A conference call is scheduled on Thursday, May 2, 2019 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, May 9, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International).
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, May 9, 2019 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of, and is not incorporated by reference into, this press release.
Guidance
Included in this release are updates to certain 2019 guidance projections. Any 2019 projections not discussed in this release are unchanged from previously stated guidance.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue Excluding Unrealized Derivative (Gains) Losses as set forth in this release represents total revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue Excluding Unrealized Derivative (Gains) Losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance. The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses (in thousands):
Three months ended March 31, | ||||||
2018 | 2019 | |||||
Total revenue | $ | 1,028,101 | $ | 1,037,407 | ||
Commodity derivative fair value (gains) losses | (22,437) | 77,368 | ||||
Marketing derivative fair value gains | (94,234) | — | ||||
Gains on settled commodity derivatives | 101,341 | 97,092 | ||||
Gains on settled marketing derivatives | 110,042 | — | ||||
Revenue Excluding Unrealized Derivative Gains | $ | 1,122,813 | $ | 1,211,867 |
Adjusted Net Income (Loss)
Adjusted Net Income (Loss) as set forth in this release represents net income, adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted net income (loss) per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income (Loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following tables reconcile net income (loss) before income taxes to Adjusted Net Income (Loss) (in thousands):
Three months ended | ||||||
March 31, 2019 | ||||||
2018 | 2019 | |||||
Net income attributable to Antero Resources Corp | $ | 14,833 | $ | 978,763 | ||
Commodity derivative fair value (gains) losses | (22,437) | 77,368 | ||||
Gains on settled commodity derivatives | 101,341 | 97,092 | ||||
Marketing derivative fair value gains | (94,234) | — | ||||
Gains on settled marketing derivatives | 110,042 | — | ||||
Impairment of unproved properties | 50,536 | 81,244 | ||||
Equity-based compensation | 14,945 | 6,426 | ||||
Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042) | ||||
Contract termination and rig stacking | — | 8,360 | ||||
Simplification transaction fees | — | 6,297 | ||||
Tax effect of reconciling items (1) | (38,751) | 264,809 | ||||
Other tax items (2) | — | (6,513) | ||||
Adjusted Net Income | $ | 136,275 | $ | 107,804 | ||
Fully Diluted Shares Outstanding | 316,911 | 308,788 |
Per Share Amounts | |||||
Three months ended | |||||
March 31, 2019 | |||||
2018 | 2019 | ||||
Net income attributable to Antero Resources Corp | $ | 0.05 | 3.17 | ||
Commodity derivative fair value (gains) losses | (0.07) | 0.25 | |||
Gains on settled commodity derivatives | 0.32 | 0.31 | |||
Marketing derivative fair value gains | (0.30) | — | |||
Gains on settled marketing derivatives | 0.35 | — | |||
Impairment of unproved properties | 0.16 | 0.26 | |||
Equity-based compensation | 0.04 | 0.02 | |||
Gain on deconsolidation of Antero Midstream Partners LP | — | (4.55) | |||
Contract termination and rig stacking | — | 0.03 | |||
Simplification transaction fees | — | 0.02 | |||
Tax effect of reconciling items (1) | (0.12) | 0.86 | |||
Other tax items (2) | — | (0.02) | |||
Adjusted Net Income | $ | 0.43 | 0.35 |
(1) Deferred taxes were approximately 24% for 2018 and 23% for 2019. |
(2) Tax adjustment related to the previously announced simplification transaction. |
Adjusted Net Cash Provided by Operating Activities and Free Cash Flow
Adjusted Net Cash Provided by Operating Activities as presented in this release represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated through March 12, 2019. Adjusted Net Cash Provided by Operating Activities is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Net Cash Provided by Operating Activities is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Free Cash Flow as defined by the Company represents Adjusted Net Cash Provided by Operating Activities, less drilling and completion capital, less drilling and completion capital paid to Antero Midstream Partners from January 1 to March 12, 2019, less land capital.
Management believes that Adjusted Net Cash Provided by Operating Activities and Free Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt.
There are significant limitations to using Adjusted Net Cash Provided by Operating Activities and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Net Cash Provided by Operating Activities and Free Cash Flow reported by different companies. Adjusted Net Cash Provided by Operating Activities and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Net Cash Provided by Operating Activities and Free Cash Flow are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. Furthermore, we may calculate such measures differently from similarly titled measures used by other companies.
The following table reconciles net cash provided by operating activities to Adjusted Net Cash Provided by Operating Activities and Free Cash Flow as used in this release (in thousands):
Three months ended March 31, | |||||
2018 | 2019 | ||||
Net cash provided by operating activities | $ | 541,549 | 539,004 | ||
Antero Midstream Partners net cash provided by operating activities (1) | (43,291) | (54,100) | |||
Adjusted Net Cash Provided By Operating Activities | 498,258 | 484,904 | |||
Additions to unproved properties | (49,569) | (27,463) | |||
Drilling and completion costs (2) | (420,627) | (389,252) | |||
Free Cash Flow | $ | 28,062 | 68,189 |
(1) Represents Antero Midstream Partners net cash provided by operating activities that was consolidated in Antero Resources' financial results in the first quarter of 2018 and from January 1, 2019, to March 12, 2019. |
(2) Represents Antero Resources' drilling and completion costs inclusive of costs paid to Antero Midstream Partners that were consolidated in Antero Resources' financial results in the first quarter of 2018 and from January 1, 2019, to March 12, 2019. |
Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate its financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, | March 31, | ||||
2018 | 2019 | ||||
AR bank credit facility | $ | 405,000 | 50,000 | ||
AM bank credit facility (1) | 990,000 | — | |||
5.375% AR senior notes due 2021 | 1,000,000 | 1,000,000 | |||
5.125% AR senior notes due 2022 | 1,100,000 | 1,100,000 | |||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | |||
5.375% AM senior notes due 2024 (1) | 650,000 | — | |||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | |||
Net unamortized premium | 1,241 | 1,168 | |||
Net unamortized debt issuance costs (1) | (34,553) | (25,218) | |||
Consolidated total debt | $ | 5,461,688 | 3,475,950 | ||
Less: AR cash and cash equivalents | — | — | |||
Less: AM cash and cash equivalents (1) | — | — | |||
Consolidated net debt | $ | 5,461,688 | 3,475,950 | ||
Less: Antero Midstream Partners debt net of cash and unamortized premium and debt issuance costs (1) | $ | 1,632,147 | — | ||
Net Debt | $ | 3,829,541 | 3,475,950 |
(1) Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero's results |
Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration , contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company's financial performance because it:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
The following table represents a reconciliation of Adjusted EBITDAX to net income (loss), including noncontrolling interest, and net cash provided by operating activities per our consolidated statements of cash flows.
Three months ended March 31, | ||||||
(in thousands) | 2018 | 2019 | ||||
Reconciliation of net income to Adjusted EBITDAX: | ||||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 14,833 | $ | 978,763 | ||
Net income and comprehensive income attributable to noncontrolling interests | 65,977 | 46,993 | ||||
Commodity derivative fair value (gains) losses (1) | (22,437) | 77,368 | ||||
Gains on settled commodity derivatives (1) | 101,341 | 97,092 | ||||
Marketing derivative fair value gains (1) | (94,234) | — | ||||
Gains on settled marketing derivatives (1) | 110,042 | — | ||||
Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042) | ||||
Interest expense | 64,426 | 71,950 | ||||
Income tax expense | 9,120 | 288,710 | ||||
Depletion, depreciation, amortization, and accretion | 228,934 | 241,177 | ||||
Impairment of unproved properties | 50,536 | 81,244 | ||||
Impairment of gathering systems and facilities | — | 6,982 | ||||
Exploration expense | 1,885 | 126 | ||||
Equity-based compensation expense | 21,156 | 8,903 | ||||
Equity in earnings of unconsolidated affiliates | (7,862) | (14,081) | ||||
Distributions from unconsolidated affiliates | 7,085 | 12,605 | ||||
Contract termination and rig stacking | — | 8,360 | ||||
Simplification transaction fees | — | 6,297 | ||||
550,802 | 506,447 | |||||
Net income and comprehensive income attributable to noncontrolling interests | (65,977) | (46,993) | ||||
Antero Midstream Partners interest expense (2) | (10,928) | (16,815) | ||||
Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2) | (36,340) | (21,770) | ||||
Antero Midstream Partners impairment | — | (6,982) | ||||
Antero Midstream Partners equity-based compensation expense (2) | (6,211) | (2,477) | ||||
Antero Midstream Partners equity in earnings of unconsolidated affiliates (2) | 7,862 | 12,264 | ||||
Antero Midstream Partners distributions from unconsolidated affiliates (2) | (7,085) | (12,605) | ||||
Equity in earnings of Antero Midstream Partners (2) | 20,128 | (15,021) | ||||
Distributions from Antero Midstream Partners (2) | 36,088 | 46,469 | ||||
Antero Midstream Partners related adjustments | (62,463) | (63,930) | ||||
Adjusted EBITDAX | $ | 488,339 | 442,517 | |||
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: | ||||||
Adjusted EBITDAX | $ | 488,339 | 442,517 | |||
Antero Midstream Partners related adjustments | 62,463 | 63,930 | ||||
Interest expense | (64,426) | (71,950) | ||||
Exploration expense | (1,885) | (126) | ||||
Changes in current assets and liabilities | 56,089 | 109,065 | ||||
Simplification transaction fees | — | (6,297) | ||||
Other | — | (9,216) | ||||
Other non-cash items | 969 | 11,081 | ||||
Net cash provided by operating activities | $ | 541,549 | 539,004 | |||
Adjusted EBITDAX | $ | 488,339 | $ | 442,517 | ||
Production (MMcfe) | 213,854 | 278,868 | ||||
Adjusted EBITDAX margin per Mcfe | $ | 2.28 | $ | 1.59 |
(1) The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives which settled during the period. The adjustments do not include proceeds from derivatives monetization. |
(2) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Partners through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2019 for further discussion on equity method investments. |
The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended March 31, 2019, as used in this release (in thousands):
Twelve months ended | |||
(in thousands) | March 31, 2019 | ||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 566,413 | |
Commodity derivative fair value gains | 187,399 | ||
Gains on settled commodity derivatives | 238,863 | ||
Marketing derivative fair value gains | 153 | ||
Losses on settled marketing derivatives | (37,355) | ||
Gain on deconsolidation of Antero Midstream Partners LP | (1,406,042) | ||
Interest expense | 226,614 | ||
Income tax expense | 150,733 | ||
Depletion, depreciation, amortization, and accretion | 868,075 | ||
Impairment of unproved properties | 580,145 | ||
Impairment of gathering systems and facilities | 4,470 | ||
Exploration expense | 3,199 | ||
Gain on change in fair value of contingent acquisition consideration | 96,893 | ||
Equity-based compensation expense | 40,822 | ||
Equity in (earnings) loss of Antero Midstream Partners LP | (31,485) | ||
Equity in (earnings) loss of unconsolidated affiliates | (1,817) | ||
Distributions from Antero Midstream Partners LP | 169,562 | ||
Contract termination and rig stacking | 8,360 | ||
Simplification transaction fees | 6,297 | ||
Adjusted EBITDAX | $ | 1,671,299 |
Drilling and Completion Capital Expenditures
The following tables reconcile Antero's drilling and completion costs as reported on a cash basis to drilling and completion costs on an accrual basis (in thousands):
Three months ended March 31, | |||||
2018 | 2019 | ||||
Drilling and completion costs (as reported; cash basis) | $ | 359,868 | 368,687 | ||
Drilling and completion costs paid to Antero Midstream Partners (cash basis) (1) | 60,759 | 20,565 | |||
Adjusted drilling and completion costs (cash basis) | 420,627 | 389,252 | |||
Change in accrued capital costs | 21,054 | (9,601) | |||
Adjusted drilling and completion costs (accrual basis) | $ | 441,681 | 379,651 |
(1) Represents drilling and completion costs paid to Antero Midstream Partners that were consolidated in Antero Resources' financial results in the first quarter of 2018 and from January 1, 2019, to March 12, 2019. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding the expected sources of funding and timing for completion of the share repurchase program if at all, statements regarding expected results in 2019, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Adjusted Net Cash Provided by Operating Activities, Free Cash Flow, leverage targets, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Balance Sheets | |||||
March 31, 2018 and 2019 | |||||
(unaudited) | |||||
(In thousands, except per share amounts) | |||||
December 31, 2018 | March 31, 2019 | ||||
Assets | |||||
Current assets: | |||||
Accounts receivable | $ | 51,073 | 48,979 | ||
Accrued revenue | 474,827 | 365,151 | |||
Derivative instruments | 245,263 | 122,425 | |||
Other current assets | 35,450 | 8,341 | |||
Total current assets | 806,613 | 544,896 | |||
Property and equipment: | |||||
Oil and gas properties, at cost (successful efforts method): | |||||
Unproved properties | 1,767,600 | 1,701,002 | |||
Proved properties | 12,705,672 | 13,056,874 | |||
Water handling and treatment systems | 1,013,818 | — | |||
Gathering systems and facilities | 2,470,708 | 17,825 | |||
Other property and equipment | 65,842 | 68,535 | |||
18,023,640 | 14,844,236 | ||||
Less accumulated depletion, depreciation, and amortization | (4,153,725) | (3,872,886) | |||
Property and equipment, net | 13,869,915 | 10,971,350 | |||
Operating leases right-of-use assets | — | 3,433,515 | |||
Derivative instruments | 362,169 | 313,909 | |||
Investments in unconsolidated affiliates | 433,642 | 1,989,612 | |||
Other assets | 47,125 | 35,448 | |||
Total assets | $ | 15,519,464 | 17,288,730 | ||
Liabilities and Equity | |||||
Current liabilities: | |||||
Accounts payable | $ | 66,289 | 48,096 | ||
Accounts payable, related parties | — | 110,980 | |||
Accrued liabilities | 465,070 | 384,707 | |||
Revenue distributions payable | 310,827 | 301,066 | |||
Derivative instruments | 532 | 3,894 | |||
Short-term lease liabilities | 2,459 | 413,103 | |||
Other current liabilities | 8,363 | 4,935 | |||
Total current liabilities | 853,540 | 1,266,781 | |||
Long-term liabilities: | |||||
Long-term debt | 5,461,688 | 3,475,950 | |||
Deferred income tax liability | 650,788 | 1,171,866 | |||
Long-term lease liabilities | 2,873 | 3,024,582 | |||
Other liabilities | 63,098 | 56,753 | |||
Total liabilities | 7,031,987 | 8,995,932 | |||
Commitments and contingencies (Notes 13 and 14) | |||||
Equity: | |||||
Stockholders' equity: | |||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | |||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 308,594 shares and 308,741 shares issued and outstanding at December 31, 2018 and March 31, 2019, respectively | 3,086 | 3,087 | |||
Additional paid-in capital | 6,485,174 | 6,133,400 | |||
Accumulated earnings | 1,177,548 | 2,156,311 | |||
Total stockholders' equity | 7,665,808 | 8,292,798 | |||
Noncontrolling interests in consolidated subsidiary | 821,669 | — | |||
Total equity | 8,487,477 | 8,292,798 | |||
Total liabilities and equity | $ | 15,519,464 | 17,288,730 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||
Three Months Ended March 31, 2018 and 2019 | |||||
(unaudited) | |||||
(In thousands, except per share amounts) | |||||
Three Months Ended March 31, | |||||
2018 | 2019 | ||||
Revenue and other: | |||||
Natural gas sales | $ | 497,663 | 657,266 | ||
Natural gas liquids sales | 234,170 | 313,685 | |||
Oil sales | 30,273 | 48,052 | |||
Commodity derivative fair value gains (losses) | 22,437 | (77,368) | |||
Gathering, compression, water handling and treatment | 4,935 | 4,479 | |||
Marketing | 144,389 | 91,186 | |||
Marketing derivative fair value gains | 94,234 | — | |||
Other income | — | 107 | |||
Total revenue | 1,028,101 | 1,037,407 | |||
Operating expenses: | |||||
Lease operating | 26,722 | 41,732 | |||
Gathering, compression, processing, and transportation | 291,938 | 424,529 | |||
Production and ad valorem taxes | 25,823 | 35,678 | |||
Marketing | 195,739 | 163,084 | |||
Exploration | 1,885 | 126 | |||
Impairment of unproved properties | 50,536 | 81,244 | |||
Impairment of gathering systems and facilities | — | 6,982 | |||
Depletion, depreciation, and amortization | 228,244 | 240,201 | |||
Accretion of asset retirement obligations | 690 | 976 | |||
General and administrative (including equity-based compensation expense of $21,156 and $8,903 in 2018 and 2019, respectively) | 60,030 | 68,202 | |||
Contract termination and rig stacking | — | 8,360 | |||
Total operating expenses | 881,607 | 1,071,114 | |||
Operating income (loss) | 146,494 | (33,707) | |||
Other income (expenses): | |||||
Equity in earnings of unconsolidated affiliates | 7,862 | 14,081 | |||
Interest | (64,426) | (71,950) | |||
Gain on deconsolidation of Antero Midstream Partners LP | — | 1,406,042 | |||
Total other expenses | (56,564) | 1,348,173 | |||
Income before income taxes | 89,930 | 1,314,466 | |||
Provision for income tax expense | (9,120) | (288,710) | |||
Net income and comprehensive income including noncontrolling interests | 80,810 | 1,025,756 | |||
Net income and comprehensive income attributable to noncontrolling interests | 65,977 | 46,993 | |||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 14,833 | 978,763 | ||
Earnings per common share—basic | $ | 0.05 | 3.17 | ||
Earnings per common share—assuming dilution | $ | 0.05 | 3.17 | ||
Weighted average number of shares outstanding: | |||||
Basic | 316,471 | 308,694 | |||
Diluted | 316,911 | 308,788 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Cash Flows | |||||
Three Months Ended March 31, 2018 and 2019 | |||||
(In thousands) | |||||
Three Months Ended March 31, | |||||
2018 | 2019 | ||||
Cash flows provided by (used in) operating activities: | |||||
Net income including noncontrolling interests | $ | 80,810 | 1,025,756 | ||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||
Depletion, depreciation, amortization, and accretion | 228,934 | 241,177 | |||
Impairment of unproved properties | 50,536 | 81,244 | |||
Impairment of gathering systems and facilities | — | 6,982 | |||
Commodity derivative fair value (gains) losses | (22,437) | 77,368 | |||
Gains on settled commodity derivatives | 101,341 | 97,092 | |||
Marketing derivative fair value gains | (94,234) | — | |||
Gains on settled marketing derivatives | 110,042 | — | |||
Deferred income tax expense | 9,120 | 287,854 | |||
Equity-based compensation expense | 21,156 | 8,903 | |||
Equity in earnings of unconsolidated affiliates | (7,862) | (14,081) | |||
Distributions of earnings from unconsolidated affiliates | 7,085 | 12,605 | |||
Gain on deconsolidation of Antero Midstream Partners LP | — | (1,406,042) | |||
Other | 969 | 11,081 | |||
Changes in current assets and liabilities: | |||||
Accounts receivable | 8,204 | 42,168 | |||
Accrued revenue | 20,199 | 109,677 | |||
Other current assets | (1,431) | 1,364 | |||
Accounts payable | (8,042) | (21,370) | |||
Accrued liabilities | 10,359 | (14,965) | |||
Revenue distributions payable | 28,290 | (9,761) | |||
Other current liabilities | (1,490) | 1,952 | |||
Net cash provided by operating activities | 541,549 | 539,004 | |||
Cash flows provided by (used in) investing activities: | |||||
Additions to unproved properties | (49,569) | (27,463) | |||
Drilling and completion costs | (359,868) | (368,687) | |||
Additions to water handling and treatment systems | (40,285) | (24,416) | |||
Additions to gathering systems and facilities | (93,670) | (48,239) | |||
Additions to other property and equipment | (2,571) | (3,128) | |||
Investments in unconsolidated affiliates | (17,389) | (25,020) | |||
Proceeds from the Antero Midstream Partners LP Transactions | — | 296,611 | |||
Change in other assets | (217) | (4,475) | |||
Net cash used in investing activities | (563,569) | (204,817) | |||
Cash flows provided by (used in) financing activities: | |||||
Issuance of senior notes | — | 650,000 | |||
Borrowings (repayments) on bank credit facilities, net | 75,000 | (270,000) | |||
Payments of deferred financing costs | — | (8,259) | |||
Distributions to noncontrolling interests in Antero Midstream Partners LP | (55,915) | (85,076) | |||
Employee tax withholding for settlement of equity compensation awards | (1,084) | (479) | |||
Other | (1,269) | (841) | |||
Net cash provided by financing activities | 16,732 | 285,345 | |||
Effect of deconsolidation of Antero Midstream Partners LP | — | (619,532) | |||
Net decrease in cash and cash equivalents | (5,288) | — | |||
Cash and cash equivalents, beginning of period | 28,441 | — | |||
Cash and cash equivalents, end of period | $ | 23,153 | — | ||
Supplemental disclosure of cash flow information: | |||||
Cash paid during the period for interest | $ | 42,010 | 37,081 | ||
Increase in accounts payable and accrued liabilities for additions to property and equipment | $ | 12,691 | 22,825 |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended March 31, 2018 and 2019:
Amount of | ||||||||||||
Three months ended March 31, | Increase | Percent | ||||||||||
(in thousands) | 2018 | 2019 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 497,663 | $ | 657,266 | $ | 159,603 | 32 | % | ||||
NGLs sales | 234,170 | 313,685 | 79,515 | 34 | % | |||||||
Oil sales | 30,273 | 48,052 | 17,779 | 59 | % | |||||||
Commodity derivative fair value gains (losses) | 22,437 | (77,368) | (99,805) | (445) | % | |||||||
Gathering, compression, water handling and treatment | 4,935 | 4,479 | (456) | (9) | % | |||||||
Marketing | 144,389 | 91,186 | (53,203) | (37) | % | |||||||
Marketing derivative fair value gains | 94,234 | — | (94,234) | (100) | % | |||||||
Other income | — | 107 | 107 | * | ||||||||
Total revenue | 1,028,101 | 1,037,407 | 9,306 | 1 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 26,722 | 41,732 | 15,010 | 56 | % | |||||||
Gathering, compression, processing, and transportation | 291,938 | 424,529 | 132,591 | 45 | % | |||||||
Production and ad valorem taxes | 25,823 | 35,678 | 9,855 | 38 | % | |||||||
Marketing | 195,739 | 163,084 | (32,655) | (17) | % | |||||||
Exploration | 1,885 | 126 | (1,759) | (93) | % | |||||||
Impairment of unproved properties | 50,536 | 81,244 | 30,708 | 61 | % | |||||||
Impairment of gathering systems and facilities | — | 6,982 | 6,982 | * | ||||||||
Depletion, depreciation, and amortization | 228,244 | 240,201 | 11,957 | 5 | % | |||||||
Accretion of asset retirement obligations | 690 | 976 | 286 | 41 | % | |||||||
General and administrative (excluding equity-based compensation) | 38,874 | 59,299 | 20,425 | 53 | % | |||||||
Equity-based compensation | 21,156 | 8,903 | (12,253) | (58) | % | |||||||
Contract termination and rig stacking | — | 8,360 | 8,360 | * | ||||||||
Total operating expenses | 881,607 | 1,071,114 | 189,507 | 21 | % | |||||||
Operating income (loss) | 146,494 | (33,707) | (180,201) | (123) | % | |||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliate | 7,862 | 14,081 | 6,219 | 79 | % | |||||||
Interest expense | (64,426) | (71,950) | (7,524) | 12 | % | |||||||
Gain on deconsolidation of Antero Midstream Partners LP | — | 1,406,042 | — | * | ||||||||
Total other expenses | (56,564) | 1,348,173 | (1,305) | 2 | % | |||||||
Income before income taxes | 89,930 | 1,314,466 | (181,506) | (202) | % | |||||||
Income tax expense | (9,120) | (288,710) | (279,590) | 3,066 | % | |||||||
Net income and comprehensive income including noncontrolling interest | 80,810 | 1,025,756 | (461,096) | (571) | % | |||||||
Net income and comprehensive income attributable to noncontrolling interest | 65,977 | 46,993 | (18,984) | (29) | % | |||||||
Net income and comprehensive income attributable to Antero Resources Corporation | $ | 14,833 | $ | 978,763 | $ | (442,112) | (2,981) | % | ||||
Adjusted EBITDAX | $ | 488,339 | $ | 442,517 | $ | (44,355) | (9) | % |
* Not meaningful |
Amount of | ||||||||||||
Three months ended March 31, | Increase | Percent | ||||||||||
2018 | 2019 | (Decrease) | Change | |||||||||
Production data: | ||||||||||||
Natural gas (Bcf) | 158 | 199 | 41 | 26 | % | |||||||
C2 Ethane (MBbl) | 3,029 | 3,509 | 480 | 16 | % | |||||||
C3+ NGLs (MBbl) | 5,693 | 8,794 | 3,101 | 54 | % | |||||||
Oil (MBbl) | 530 | 1,017 | 487 | 92 | % | |||||||
Combined (Bcfe) | 214 | 279 | 65 | 30 | % | |||||||
Daily combined production (MMcfe/d) | 2,376 | 3,099 | 723 | 30 | % | |||||||
Average prices before effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 3.14 | $ | 3.30 | $ | 0.16 | 5 | % | ||||
C2 Ethane (per Bbl) | $ | 8.94 | $ | 10.12 | $ | 1.18 | 13 | % | ||||
C3+ NGLs (per Bbl) | $ | 36.38 | $ | 31.63 | $ | (4.75) | (13) | % | ||||
Oil (per Bbl) | $ | 57.14 | $ | 47.23 | $ | (9.91) | (17) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.56 | $ | 3.65 | $ | 0.09 | 3 | % | ||||
Average realized prices after effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 3.85 | $ | 3.79 | $ | (0.06) | (2) | % | ||||
C2 Ethane (per Bbl) | $ | 8.94 | $ | 10.12 | $ | 1.18 | 13 | % | ||||
C3+ NGLs (per Bbl) | $ | 35.17 | $ | 31.59 | $ | (3.58) | (10) | % | ||||
Oil (per Bbl) | $ | 51.12 | $ | 47.23 | $ | (3.89) | (8) | % | ||||
Weighted Average Combined (per Mcfe) | $ | 4.04 | $ | 4.00 | $ | (0.04) | (1) | % | ||||
Average costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.15 | $ | 0.15 | $ | — | — | % | ||||
Gathering, compression, processing, and transportation | $ | 1.80 | $ | 1.92 | $ | 0.12 | 7 | % | ||||
Production and ad valorem taxes | $ | 0.12 | $ | 0.12 | $ | — | — | % | ||||
Marketing expense, net | $ | 0.24 | $ | 0.26 | $ | 0.02 | 8 | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.92 | $ | 0.79 | $ | (0.13) | (14) | % | ||||
General and administrative (excluding equity-based compensation) | $ | 0.15 | $ | 0.16 | $ | 0.01 | 7 | % |
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SOURCE Antero Resources Corporation
DENVER, April 11, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its first quarter 2019 earnings release on Wednesday, May 1, 2019 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, May 2, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 877-407-9079 (U.S.), or 201-493-6746 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, May 9, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International).
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, May 9, 2019 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources
DENVER, March 13, 2019 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero Resources", or "AR") today announced receipt of consideration in connection with the closing of the previously announced simplification transaction between Antero Midstream GP LP (NYSE: AMGP) ("AMGP") and Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream Partners" or "AM"). At closing, AMGP was converted from a Limited Partnership to a Corporation and was renamed Antero Midstream Corporation ("New AM"). Beginning on March 13, 2019, New AM's common stock will trade on the NYSE under the ticker symbol AM. With the closing of this transaction, Antero Resources will no longer consolidate Antero Midstream Partners' financial and operating results in Antero Resources' consolidated financial statements. Antero Resources will account for its interest in New AM under the equity method of accounting. This new financial statement presentation will be substantially the same as the previously categorized "Stand-alone" data that was historically reported. Please see the accompanying presentation on our website titled "Simplification and Deconsolidation: Catalyst for Outperformance" for supplemental details.
Highlights Include:
Paul Rady, Chairman and CEO commented, "This improved visibility and simplified corporate structure, alongside a diversified production mix and industry-leading hedge book, result in a low-risk E&P profile positioned to maximize returns across the commodity price cycles. We remain committed to our long-term strategy of spending within cash flow, continuing to delever our already strong balance sheet and then returning free cash flow to shareholders. We project 2019 capital to be at the low end of the guidance range, with a continued focus on keeping capital spending within cash flow."
Glen Warren, President, and Chief Financial Officer added, "With the simplification of our midstream structure and the deconsolidation of our financial statements, we have made significant progress in improving Antero's financial transparency. We believe the deconsolidation showcases the strength of our balance sheet and highlights the independence of the two companies. As of year-end 2018, we have reduced leverage to 2.1x leverage on a pro forma basis, while growing to become the 4th largest natural gas producer and the largest NGL producer in the U.S. today. This was achieved only nine years after placing our first well online."
2019 Capital Budget and Guidance
The following is a summary of Antero Resources' 2019 capital budget for drilling and completion and land capital as previously announced on January 8, 2019, and previously categorized as Stand-alone. As a result of the deconsolidation, all previously communicated consolidated guidance and targets should no longer be relied upon. All other guidance items are unchanged, as detailed in the Form 8-K filed today.
Capital Budget ($ in MM) | ||||||
Low | High | |||||
Drilling & Completion | $1,300 | $1,450 | ||||
Land Capital | $75 | $100 | ||||
Total Capital | $1,375 | $1,550 | ||||
The following is a summary of Antero Resources' 2019 production guidance as previously announced on January 8, 2019. | ||||||
Production Guidance | ||||||
Low | High | |||||
Net Daily Production (MMcfe/d) | 3,150 | 3,250 | ||||
The following is a summary of Antero Resources' 2019 expense guidance as previously announced on January 8, 2019. | ||||||
Cash Expense Guidance | Low | High | ||||
Cash Production Expense ($/Mcfe)(1) | $2.15 | $2.25 | ||||
G&A Expense ($/Mcfe) (2) | $0.10 | $0.14 | ||||
(1) | Includes lease operating expenses, gathering, compression, processing, transportation expenses and production and ad valorem taxes. |
(2) | Excludes equity-based compensation. |
Total Debt and Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate its financial position, including its ability to service its debt obligations.
The following table reconciles pro form Net Debt as used in this release (in thousands):
December 31, | |||||||
2018 | |||||||
AR bank credit facility | 405,000 | ||||||
5.375% AR senior notes due 2021 | 1,000,000 | ||||||
5.125% AR senior notes due 2022 | 1,100,000 | ||||||
5.625% AR senior notes due 2023 | 750,000 | ||||||
5.000% AR senior notes due 2025 | 600,000 | ||||||
Net unamortized premium | 1,241 | ||||||
Net unamortized debt issuance costs | (26,700) | ||||||
Total debt | 3,829,541 | ||||||
Less: AR cash and cash equivalents | — | ||||||
Debt | 3,829,541 | ||||||
Less: Proceeds from Antero Midstream Simplification | 297,000 | ||||||
Pro Forma Net Debt | 3,532,541 |
The following table reconciles Net Income as reported in the Parent column of Antero's guarantor footnote to its financial statements to Adjusted EBITDAX for the twelve months ended December 31, 2018, as used in this release (in thousands):
Twelve months ended | |||||||
(in thousands) | December 31, 2018 | ||||||
Net (loss) and comprehensive (loss) attributable to Antero Resources Corporation | $ | (397,517) | |||||
Commodity derivative fair value losses | 87,594 | ||||||
Gains on settled commodity derivatives | 243,112 | ||||||
Marketing derivative fair value gains | (94,081) | ||||||
Gains on settled marketing derivatives | 72,687 | ||||||
Interest expense | 224,977 | ||||||
Income tax benefit | (128,857) | ||||||
Depletion, depreciation, amortization, and accretion | 845,136 | ||||||
Impairment of unproved properties | 549,437 | ||||||
Impairment of gathering systems and facilities | 4,470 | ||||||
Exploration expense | 4,958 | ||||||
Gain on change in fair value of contingent acquisition consideration | 93,019 | ||||||
Equity-based compensation expense | 49,341 | ||||||
Equity in loss of Antero Midstream Partners LP | 3,664 | ||||||
Distributions from Antero Midstream Partners LP | 159,181 | ||||||
Adjusted EBITDAX | $ | 1,717,121 |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, future capital spending plans, estimated realized natural gas, natural gas liquids and oil prices, acreage quality and expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero Resources' control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, the expected timing and likelihood of completion of the simplification transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
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SOURCE Antero Resources Corporation
DENVER, Feb. 13, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero," "Antero Resources" or the "Company") today released its fourth quarter and full year 2018 financial and operational results and announced estimated proved reserves as of December 31, 2018. The relevant consolidated and consolidating financial statements are included in Antero's Annual Report on Form 10-K for the year ended December 31, 2018, which has been filed with the Securities and Exchange Commission ("SEC"). The relevant Stand-alone financial statements are also included in Antero's Form 10-K within the Parent column of the guarantor footnote (Note 17).
Fourth Quarter 2018 Highlights:
Full Year 2018 Highlights:
Paul Rady, Chairman and CEO said, "2018 was a great year for the Antero family, as we significantly reduced leverage, grew production above the 3 Bcfe/d mark, and announced the midstream simplification. We enter 2019 with significant scale as the largest NGL producer and the 5th largest natural gas producer in the U.S. Driven by the fourth quarter capital invested on pads and roads, we expect to be in a position to invest at the low end of our 2019 drilling and completion guidance range. The 2019 budget represents a 20% reduction relative to capital spending in 2018. On the liquids front, we are excited that Mariner East 2 has been placed in service. Our commitment on this pipeline will allow us to move nearly half of our expected 2019 C3+ NGL production to the export market and realize stronger NGL netback pricing than we have received over the last several years. We believe that our 2019 plan will deliver superior returns to shareholders over the long-term while also keeping capital spending within cash flow. "
Fourth Quarter 2018 Financial Results
As of December 31, 2018, Antero Resources owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Pro forma for the previously announced midstream simplification transaction which is expected to close in March 2019, Antero Resources will own approximately 31% of the common stock of Antero Midstream Corporation ("New AM" or "New Antero Midstream") assuming Antero Midstream unitholders make a mixed consideration election in the transaction. Antero Midstream's results are consolidated within Antero Resources' results for 2018 and 2017, but will be deconsolidated in 2019 assuming the close of the midstream simplification transaction. Antero believes the deconsolidation will provide more transparency to investors around the Stand-alone upstream business and a greater ability to compare results across Antero's peer group.
For the three months ended December 31, 2018, Antero reported a net loss of $122 million, or $0.39 per share, compared to net income of $487 million, or $1.54 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," Adjusted Net Income was $145 million, or $0.46 per diluted share, compared to $74 million, or $0.23 per diluted share, in the prior year period. Stand-alone Adjusted Net Income was $175 million, or $0.56 per diluted share, compared to $55 million, or $0.17 per diluted share, in the prior year period.
Consolidated Adjusted EBITDAX was $584 million, a 34% increase compared to $437 million in the prior year period, and Stand-alone Adjusted EBITDAX was $475 million, a 27% increase compared to $372 million in the prior year period.
The following table details the components of average net production and average realized prices for the three months ended December 31, 2018:
Three Months Ended December 31, 2018 | ||||||||||||||||
Natural Gas (MMcf/d) | Oil (Bbl/d) | C3+ NGLs (Bbl/d) | Ethane (Bbl/d) | Combined Natural Gas Equivalent (MMcfe/d) | ||||||||||||
Average Net Production | 2,240 | 12,229 | 102,860 | 46,988 | 3,213 | |||||||||||
Average Realized Prices | Natural Gas ($/Mcf) | Oil ($/Bbl) | C3+ NGLs ($/Bbl) | Ethane ($/Bbl) | Combined Natural Gas Equivalent ($/Mcfe) | |||||||||||
Average realized prices before settled derivatives | $ | 3.83 | $ | 51.83 | $ | 30.92 | $ | 13.12 | $ | 4.05 | ||||||
Settled commodity derivatives | (0.10) | (0.91) | (0.32) | — | (0.08) | |||||||||||
Average realized prices after settled derivatives | $ | 3.73 | $ | 50.92 | $ | 30.60 | $ | 13.12 | $ | 3.97 | ||||||
NYMEX average price | $ | 3.64 | $ | 59.08 | $ | 3.64 | ||||||||||
Premium / (Differential) to NYMEX | $ | 0.09 | $ | (8.16) | $ | 0.33 |
Net daily natural gas equivalent production in the fourth quarter averaged 3,213 MMcfe/d, including 162,077 Bbl/d of liquids (30% of production), an increase of 37% compared to the prior year period and an 18% increase sequentially. Natural gas production averaged 2,240 MMcf/d, an increase of 32% over the prior year period.
Total liquids production grew 51% compared to the prior year period and 25% sequentially. Liquids revenue represented approximately 34% of total product revenue before hedges. Oil production averaged 12,229 Bbl/d, an increase of 97% over the prior year period. C3+ NGLs production averaged 102,860 Bbl/d, an increase of 47% over the prior year period. Recovered ethane production averaged 46,988 Bbl/d, an increase of 50% over the prior year period. Recovered ethane production represented approximately 27% of potential ethane that could have been recovered during the period, with the remaining 122,000 Bbl/d of ethane remaining in the gas stream.
Antero's average realized natural gas price before hedging was $3.83 per Mcf, a $0.19 per Mcf premium to the average NYMEX Henry Hub price per MMBtu during the period, representing a 37% increase versus the prior year period. Including hedges, Antero's average realized natural gas price was $3.73 per Mcf, a $0.09 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge loss of $21 million, or $0.10 per Mcf.
Antero's average realized C3+ NGL price before hedging was $30.92 per barrel, or 52% of the average NYMEX WTI oil price, representing a 21% decline versus the prior year period due to widening NGL differentials to Mont Belvieu prior to the startup of Mariner East 2. Including hedges, Antero's average realized C3+ NGL price was $30.60 per barrel, reflecting the realization of a cash settled C3+ hedge loss of $3 million, or $0.32 per barrel.
Antero's average realized oil price before hedging was $51.83 per barrel, a $7.25 negative differential to the average NYMEX WTI price and a 5% increase versus the prior year period. Including hedges, the average realized oil price was $50.92 per barrel, reflecting the realization of a cash settled WTI crude oil loss of $1.0 million, or $0.91 per barrel. The average realized ethane price was $0.31 per gallon, or $13.12 per barrel, compared to $0.24 per gallon increase in the prior year period, representing a 31% increase over $10.02 per barrel before hedging and a 29% increase over $10.17 per barrel after hedging.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $4.05 per Mcfe, representing a 17% increase compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.97 per Mcfe, a 4% increase from the prior year period, primarily driven by higher realized natural gas prices. The net cash settled commodity derivative loss on all products was $25 million, or $0.08 per Mcfe.
Total revenue in the fourth quarter was $1.0 billion, nearly equivalent to the prior year period. Revenue included a $567 million commodity derivative fair value loss primarily driven by a $370 million hedge monetization, while the prior year included a $123 million commodity derivative fair value gain. Revenue Excluding Unrealized Derivative Gains (Losses) and Derivative Monetizations (non-GAAP) was $1.2 billion, a 35% increase versus the prior year period. Please see "Non-GAAP Financial Measures" for a description of Revenue Excluding Unrealized Derivative Gains (Losses) and Derivative Monetizations.
The following table presents a calculation of Stand-alone Adjusted EBITDAX margin and Adjusted EBITDAX margin (non-GAAP measures), in each case on a per Mcfe basis with and without the effect of cash receipts for settled commodity derivatives, and reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX and Stand-alone Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations (both on a consolidated and Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure.
Stand-alone | Consolidated | ||||||||||||
Three months ended December 31, | Three months ended December 31, | ||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||
Adjusted EBITDAX margin ($ per Mcfe): | |||||||||||||
Realized price before cash receipts for settled derivatives | $ | 3.46 | 4.05 | $ | 3.46 | 4.05 | |||||||
Gathering, compression, and water handling and treatment revenues | N/A | N/A | 0.02 | 0.02 | |||||||||
Distributions from unconsolidated affiliates | N/A | N/A | 0.05 | 0.06 | |||||||||
Distributions from Antero Midstream | 0.16 | 0.15 | N/A | N/A | |||||||||
Gathering, compression, processing and transportation costs | (1.71) | (1.88) | (1.30) | (1.40) | |||||||||
Lease operating expense | (0.17) | (0.15) | (0.15) | (0.15) | |||||||||
Marketing, net (1) | (0.13) | (0.22) | (0.13) | (0.22) | |||||||||
Production and ad valorem taxes | (0.11) | (0.15) | (0.11) | (0.15) | |||||||||
General and administrative (excluding equity-based compensation) | (0.13) | (0.11) | (0.17) | (0.15) | |||||||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.37 | 1.69 | 1.67 | 2.06 | |||||||||
Cash receipts (payments) for settled commodity derivatives | 0.35 | (0.08) | 0.35 | (0.08) | |||||||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 1.72 | 1.61 | $ | 2.02 | 1.98 |
(1)Includes cash payments for settled marketing derivative losses of $0.02 per Mcfe in 2018.
Stand-alone per unit distributions from Antero Midstream contributed $0.15 per Mcfe compared to $0.16 per Mcfe in the prior year period.
The per unit Stand-alone cash production expense for the quarter included $1.88 per Mcfe for gathering, compression, processing and transportation costs, $0.15 per Mcfe for lease operating costs, and $0.15 per Mcfe for production and ad valorem taxes. Gathering, compression, processing and transportation costs increased in the fourth quarter due to higher transport costs related to new pipeline commitments that were placed in service during the quarter and higher fuel costs related to the higher gas sales price reported for the quarter. New pipeline transportation included phase 2 of the Rover pipeline that enabled Antero to transport natural gas production from the Sherwood Processing Facility in West Virginia that had previously been shipped to local Appalachia markets to the attractively priced Midwest and Gulf Coast markets. Lease operating expenses decreased in the fourth quarter of 2018 compared to the fourth quarter of 2017 due to commissioning costs relating to Antero's Clearwater Facility that occurred in the fourth quarter of 2017 that did not occur in the fourth quarter of 2018.
Stand-alone per unit net marketing expense was $0.22 per Mcfe compared to $0.13 per Mcfe reported in the prior year period. Net marketing expense increased due to higher unutilized capacity related to incremental firm transportation that was placed in service during the quarter. Net marketing expense included a $0.02 per Mcfe loss for settled marketing derivatives related to contracts that had resulted in realized gains in the first quarter of 2018. See Note 11 to the consolidated financial statements in Antero's Annual Report on Form 10-K for the year ended December 31, 2018, for more information on these contracts.
Stand-alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, decreased by 15% to $0.11 per Mcfe, compared to the prior year period. General and administrative expense on a per Mcfe basis decreased due to increased production levels.
Realized price before cash receipts for settled derivatives was $4.05 per Mcfe, a 17% increase from the prior year period, primarily due to higher natural gas prices. Stand-alone Adjusted EBITDAX margins before commodity derivative were $1.69 per Mcfe, a 24% increase from the prior year period, primarily due to higher realized natural gas prices. Stand-alone Adjusted EBITDAX margin after cash payments for settled commodity derivatives was $1.61 per Mcfe, a 6% decrease from the prior year period due to losses on commodity derivatives. Consolidated Adjusted EBITDAX margin was $1.98 per Mcfe, compared to $2.02 per Mcfe in the prior year period.
Stand-alone net cash provided by operating activities was $729 million for the period. Stand-alone Adjusted Operating Cash Flow was $775 million (non-GAAP), a 149% increase from the prior year period, as cash flow included a $357 million in net proceeds from restructuring the hedge portfolio. Excluding the hedge restructuring, Stand-alone Adjusted Operating Cash Flow increased 34% over the prior year period.
Consolidated net cash provided by operating activities was $822 million for the period. Consolidated Adjusted Operating Cash Flow was $863 million during the fourth quarter (non-GAAP), including a $357 million in net proceeds from restructuring the hedge portfolio, a 135% increase compared to the prior year period. Excluding the $357 million hedge restructuring, consolidated Adjusted Operating Cash Flow increased by 38% over the prior year period.
Operating Update
Fourth Quarter 2018
Marcellus Shale — Antero placed 39 horizontal Marcellus wells to sales during the fourth quarter of 2018 with an average lateral length of 10,600 feet and an average 30-day initial rate per well of 21.6 MMcfe/day on choke. The 30-day average rate per well included 1,268 Bbl/d of liquids, including oil, C3+ NGLs and 25% ethane recovery. Notable results from the wells placed to sales during the fourth quarter are below:
During the period, Antero drilled 31 wells with an average lateral length of 10,100 feet in an average of 11.5 total days from spud to final rig release, which represents a 7% reduction in total drilling time from 2017 levels. In addition, Antero drilled an average of 5,100 lateral feet per day in the quarter, a 12% increase in lateral footage performance compared to 2017. Completion efficiencies further improved during the fourth quarter, increasing to 5.7 stages per day from 5.5 stages per day in the third quarter of 2018. Notably, Antero averaged 6.0 stages per day in October and November. For the full year of 2018, Antero averaged 5.2 stages per day, which is an increase of one full stage per day from the 2017 average of 4.2 stages per day.
As recently announced, in 2019 Antero plans to operate an average of five drilling rigs, including four large rigs, and an average of four completion crews. Development plans reflect a reduction of one to two completions crews on average from 2018 levels. In 2019, the Company expects to drill 120 to 130 wells and place 115 to 125 wells to service.
Glen Warren, President and CFO, commented, " Entering 2019, our strategy centers on prudent capital deployment, a continued focus on full-cycle rates of return and generating free cash flow, all while maintaining a strong balance sheet. We have already taken actions to demonstrate our commitment to maintain discipline and achieve these priorities, including a significant reduction in our 2019 drilling and completion capital budget and a reduction in our land budget by 50% from 2018 levels. Our significant scale, diversified product portfolio, industry-leading natural gas hedge book and wide-reaching firm transportation portfolio are amongst our greatest assets, giving us the flexibility to thrive in a volatile commodity price environment."
Fourth Quarter 2018 Capital Investment
Antero invested $363 million in drilling and completion costs for the three months ended December 31, 2018, which included $273 million for drilling and completion activity, $78 million for pads, roads and facilities and $12 million for unit leasehold and permitting costs. The increased activity related to pads, roads and facilities in the fourth quarter results in Antero having 18 pads in progress that are planned to be turned to sales in 2019 and 2020. The pads were also built on larger footprints to optimize drilling and completion efficiencies and significantly reduce cycle times from spud to first sales. Driven by continued efficiencies in stages per day, Antero also placed three additional liquids-rich wells to sales during the quarter than previously forecasted. The additional wells had an average BTU content of 1260 and produced 56 MMcfe/d during the first 30 days, including 2,650 Bbl/d of liquids. As a result of the capital spent on pads and roads in the latter part of 2018 and the three additional liquids-rich wells during the fourth quarter, Antero expects to be at the lower end of its 2019 drilling and completion capital budget of $1.1 to $1.25 billion on a consolidated basis and $1.3 billion to $1.45 billion on a Stand-alone basis.
On a Stand-alone basis, Antero invested $415 million in drilling and completion costs for the three months ended December 31, 2018, which included $325 million for drilling and completion activity, $78 million for pads, roads and facilities and $12 million for unit leasehold and permitting costs.
In addition to capital invested in drilling and completion costs, the Company invested $42 million for land, $107 million for gathering and compression systems and $20 million for water infrastructure projects. For a reconciliation between cash paid for drilling and completion capital expenditures outlined above and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below.
Year End Proved Reserves
At December 31, 2018, Antero's estimated proved reserves were 18.0 Tcfe, a 4% increase over the prior year. Estimated proved reserves were comprised of 63% natural gas, 35% NGLs and 2% oil. The Marcellus Shale accounted for 89% of estimated proved reserves and the Ohio Utica Shale accounted for 11%. For 2018, Antero added 2.8 Tcfe of estimated proved reserves organically, which reflects delineation and developmental drilling. Approximately 1.2 Tcfe was removed from Antero's proved reserves due to the SEC 5-year rule, primarily related to changes in our 5-year development plan.
Estimated proved developed reserves were 10.4 Tcfe, a 22% increase over the prior year. The percentage of estimated proved reserves classified as proved developed increased to 58% at year-end 2018, compared to 49% at year-end 2017. Antero's 427 proved undeveloped locations average an estimated 1247 BTU, with an average lateral length of approximately 11,100 feet.
Antero invested drilling and completion capital of $1.5 billion during 2018, resulting in proved developed finding and development costs, including revisions, of $0.52 per Mcfe. Antero's 7.6 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.44 per Mcfe. For further discussion of proved developed F&D costs, please read "Non-GAAP Financial Measures."
The reserve life of the Company's estimated proved reserves is approximately 18 years based on 2018 production.
The following table presents a summary of changes in estimated proved reserves (in Bcfe).
Proved reserves, December 31, 2017 | 17,261 | ||
Extensions, discoveries, and other additions | 2,781 | ||
Revisions to prior estimates | (1,042) | ||
Production | (989) | ||
Proved reserves, December 31, 2018 | 18,011 | ||
The following table summarizes SEC pricing as of December 31, 2018 and the associated Standardized Measure and PV-10 for estimated proved reserves and hedge values:
SEC Pricing | |||||||
Benchmark Pricing: | 2018 Year-End | 2017 Year-End | Variance | % Variance | |||
WTI Oil Price ($/Bbl) | $65.66 | $51.03 | $14.63 | 29% | |||
Appalachian Oil Price ($/Bbl) (1) | $56.62 | $45.35 | $11.27 | 25% | |||
Nymex Natural Gas Price ($/MMBtu) | $3.09 | $3.11 | ($0.02) | -1% | |||
Appalachian Natural Gas Price ($/MMBtu) (1) | $2.93 | $2.91 | $0.02 | 1% | |||
C3+ Natural Gas Liquids ($/Bbl) (2) | $39.29 | $32.37 | $6.92 | 21% | |||
C2+ Natural Gas Liquids ($/Bbl) (2) | $25.05 | $20.40 | $4.65 | 23% | |||
Proved Reserve Value ($Bn): | |||||||
Standardized measure | $10.5 | $8.6 | $1.9 | 21% | |||
Pre-tax estimated proved reserves PV-10 (3) | $12.6 | $10.2 | $2.4 | 24% |
(1) Represents SEC prices as of December 31 for each respective year on a weighted average Appalachian index basis related to company-specific sales points. |
(2) Represents realized NGL price including regional market differentials for a 1250 BTU area. |
(3) For a reconciliation of PV-10 to standardized measure, see "Non-GAAP Financial Measures." |
Balance Sheet and Liquidity
As of December 31, 2018, Antero's Stand-alone Net Debt was $3.8 billion, of which $405 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility are $2.5 billion and the borrowing base is $4.5 billion. After deducting letters of credit outstanding, the Company had $1.4 billion in available Stand-alone liquidity as of December 31, 2018. As of December 31, 2018, Antero's Stand-alone Net Debt to trailing twelve months Stand-alone Adjusted EBITDAX ratio was 2.2x.
Commodity Derivative Positions
Antero's estimated natural gas production for 2019 is fully hedged. In total, Antero has hedged 2.0 Tcfe of future natural gas equivalent production using fixed price swaps, basis swaps and collar agreements covering the period from January 1, 2019, through December 31, 2023. As of December 31, 2018, the Company's estimated fair value of commodity derivative instruments was $607 million.
The following tables summarize Antero's hedge position as of December 31, 2018:
Natural gas | Weighted | |||||
Three months ending March 31, 2019: | ||||||
NYMEX ($/MMBtu) | 2,330,000 | $ | 3.62 | |||
Three months ending June 30, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.26 | |||
Three months ending September 30, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.32 | |||
Three months ending December 31, 2019: | ||||||
NYMEX ($/MMBtu) | 755,000 | $ | 3.45 | |||
Year ending December 31, 2020: | ||||||
NYMEX ($/MMBtu) | 1,417,500 | $ | 3.00 | |||
Year ending December 31, 2021: | ||||||
NYMEX ($/MMBtu) | 710,000 | $ | 3.00 | |||
Year ending December 31, 2022: | ||||||
NYMEX ($/MMBtu) | 850,000 | $ | 3.00 | |||
Year ending December 31, 2023: | ||||||
NYMEX ($/MMBtu) | 90,000 | $ | 2.91 |
Natural gas collar positions from April 1, 2019 through December 31, 2019 were as follows:
Natural gas | Weighted average index price | ||||||||
MMbtu/day | Ceiling price | Floor price | |||||||
Three months ending June 30, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.30 | $ | 2.50 | ||||
Three months ending September 30, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.30 | $ | 2.50 | ||||
Three months ending December 31, 2019: | |||||||||
NYMEX ($/MMBtu) | 1,575,000 | $ | 3.52 | $ | 2.50 |
As of December 31, 2018, the Company's natural gas basis swap positions, which settle on the basis differential of Chicago City Gate to the NYMEX Henry Hub natural gas price, totaled 225,000 MMbtu/day for January 2019 with pricing premiums ranging from $0.215 to $0.40 per MMBtu.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com. A summary of the results are provided below:
Average Daily Volumes: | Three months ended | Years ended | |||||||||||||
December 31, | December 31, | ||||||||||||||
2017 | 2018 | % Change | 2017 | 2018 | % Change | ||||||||||
Low Pressure Gathering (MMcf/d) | 1,711 | 2,602 | 52% | 1,660 | 2,148 | 29% | |||||||||
Compression (MMcf/d) | 1,355 | 2,215 | 63% | 1,196 | 1,738 | 45% | |||||||||
High Pressure Gathering (MMcf/d) | 1,842 | 2,569 | 39% | 1,770 | 2,112 | 19% | |||||||||
Fresh Water Delivery (MBbl/d) | 149 | 136 | (9)% | 153 | 195 | 27% | |||||||||
Clearwater Treatment Volumes (MBbl/d) | — | 9 | * | — | 7 | * | |||||||||
Gross Joint Venture Processing (MMcf/d) | 425 | 796 | 87% | 267 | 622 | 133% | |||||||||
Gross Joint Venture Fractionation (Bbl/d) | 9,096 | 18,672 | 105% | 5,099 | 13,107 | 157% |
* Not meaningful or applicable. |
Net income for the fourth quarter of 2018 was $249 million, a 288% increase compared to the prior year quarter. Net income per diluted limited partner unit was $1.19, a 395% increase compared to the prior year quarter. Adjusted EBITDA was $194 million, a 36% increase compared to the prior year quarter. Distributable Cash Flow was $167 million, resulting in a DCF coverage ratio of 1.3x. For a description of Antero Midstream's Adjusted EBITDA and Distributable Cash Flow, and reconciliations to their nearest GAAP measures, please read "Non-GAAP Financial Measures."
In connection with Antero Midstream's acquisition of the water business from Antero Resources in 2015, Antero Midstream agreed to pay Antero Resources (a) $125 million in cash if the Partnership delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if the Partnership delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2018, Antero Midstream expects to pay the amount of the contingent consideration for the delivery of 176 million barrels or more of fresh water for the first earn-out, but no longer expects to pay the amount of the contingent consideration to deliver 219 million barrels or more of fresh water for the second earn-out payment based on Antero Resources' recently announced 2019 budget and long-term outlook.
Conference Call
A conference call is scheduled on Thursday, February 14, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, February 28, 2019 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10123136.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 28, 2019 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the February 14, 2019 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Also available at www.anteroresources.com is a presentation detailing results of a fundamental analysis on the natural gas industry entitled Natural Gas Fundamentals.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations
Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations as set forth in this release represents total revenue adjusted for derivative fair value (gains) losses and derivative monetizations. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance. The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations:
Three Months Ended December 31, 2018 | Years Ended December 31, 2018 | |||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||
Total revenue | $ | 1,021,726 | $ | 1,045,648 | $ | 3,655,574 | $ | 4,139,626 | ||||
Commodity derivative fair value (gains) losses | (199,824) | 222,387 | (658,283) | 87,594 | ||||||||
Marketing derivative fair value (gains) losses | 21,394 | — | 21,394 | (94,081) | ||||||||
Gains (losses) on settled commodity derivatives | 76,548 | (25,257) | 213,940 | 243,112 | ||||||||
Gains (losses) on settled marketing derivatives | — | (5,411) | — | 72,687 | ||||||||
Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations | $ | 919,844 | $ | 1,237,367 | $ | 3,232,625 | $ | 4,448,938 |
Adjusted Net Income & Stand-alone Adjusted Net Income
Adjusted Net Income as set forth in this release represents net income, adjusted for certain items. Stand-alone Adjusted Net Income as presented in this release represents net income that will be reported in the Parent column of Antero's guarantor footnote to its financial statements, adjusted for certain items. Antero believes that Adjusted Net Income and Adjusted Net Income per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income and Stand-alone Adjusted Net Income are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following table reconciles net income (loss) to Adjusted Net Income and Stand-alone net (loss) to Stand-alone Adjusted Net Income (in thousands):
Stand-alone | Consolidated | ||||||||||||||||
Three months ended | Three months ended | ||||||||||||||||
December 31, 2018 | December 31, 2018 | ||||||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||||||
Net Income (loss) attributable to Antero Resources Corp. | $ | 486,869 | $ | (121,546) | $ | 486,869 | $ | (121,546) | |||||||||
Commodity derivative fair value (gains) losses | (199,824) | 222,387 | (199,824) | 222,387 | |||||||||||||
Gains (losses) on settled commodity derivatives | 76,548 | (25,257) | 76,548 | (25,257) | |||||||||||||
Marketing derivative fair value losses | 21,394 | — | 21,394 | — | |||||||||||||
Losses on settled marketing derivatives | — | (5,411) | — | (5,411) | |||||||||||||
Impairment of unproved properties | 76,500 | 143,369 | 76,500 | 143,369 | |||||||||||||
Impairment of gathering systems and facilities | — | — | 23,431 | — | |||||||||||||
Equity-based compensation | 17,673 | 9,518 | 24,520 | 13,984 | |||||||||||||
(Gain) loss on change in fair value of contingent acquisition consideration | — | 104,860 | — | — | |||||||||||||
Loss on early extinguishment of debt | 1,205 | — | 1,500 | — | |||||||||||||
Tax effect of reconciling items (1) | 2,447 | (105,804) | (9,056) | (82,171) | |||||||||||||
Other tax items (2) | (427,962) | (47,550) | (427,962) | — | |||||||||||||
Adjusted Net Income | $ | 54,850 | $ | 174,566 | $ | 73,920 | $ | 145,355 | |||||||||
Fully Diluted Shares Outstanding | 316,682 | 314,298 | 316,682 | 314,298 | |||||||||||||
Per Diluted Share Amounts | ||||||||||||
Net Income (loss) attributable to Antero Resources Corp | 1.54 | (0.39) | 1.54 | (0.39) | ||||||||
Commodity derivative fair value (gains) losses | (0.63) | 0.71 | (0.63) | 0.71 | ||||||||
Gains (losses) on settled commodity derivatives | 0.24 | (0.08) | 0.24 | (0.08) | ||||||||
Marketing derivative fair value losses | 0.07 | — | 0.07 | — | ||||||||
Losses on settled marketing derivatives | — | (0.02) | — | (0.02) | ||||||||
Impairment of unproved properties | 0.24 | 0.46 | 0.24 | 0.46 | ||||||||
Impairment of gathering systems and facilities | — | — | 0.07 | — | ||||||||
Equity-based compensation | 0.05 | 0.03 | 0.08 | 0.04 | ||||||||
(Gain) loss on change in fair value of contingent acquisition consideration | — | 0.34 | — | — | ||||||||
Loss on early extinguishment of debt | 0.00 | — | — | — | ||||||||
Tax effect of reconciling items (1) | 0.01 | (0.34) | (0.03) | (0.26) | ||||||||
Other tax items (2) | (1.35) | (0.15) | (1.35) | — | ||||||||
Adjusted Net Income | $ | 0.17 | $ | 0.56 | $ | 0.23 | $ | 0.46 |
(1) | Blended tax rates of approximately 38% for 2017 and 24% for 2018 were applied to reconciling items above. |
(2) | Tax impact of valuation allowance on Colorado net operating losses, changes to Colorado tax law, tax reform legislation enacted in late 2017 and items effecting the Stand-alone financial statements. |
Stand-alone | Consolidated | |||||||||||||||||||
Year ended | Year ended | |||||||||||||||||||
December 31, 2018 | December 31, 2018 | |||||||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||||||
Net Income (loss) attributable to Antero Resources Corp. | $ | 615,070 | $ | (397,517) | $ | 615,070 | $ | (397,517) | ||||||||||||
Commodity derivative fair value (gains) losses | (658,283) | 87,594 | (658,283) | 87,594 | ||||||||||||||||
Gains (losses) on settled commodity derivatives | 213,940 | 243,112 | 213,940 | 243,112 | ||||||||||||||||
Marketing derivative fair value losses | 21,394 | (94,081) | 21,394 | (94,081) | ||||||||||||||||
Losses on settled marketing derivatives | — | 72,687 | — | 72,687 | ||||||||||||||||
Impairment of unproved properties | 159,598 | 553,907 | 159,598 | 559,095 | ||||||||||||||||
Impairment of gathering systems and facilities | — | — | 23,431 | — | ||||||||||||||||
Equity-based compensation | 76,162 | 49,341 | 103,445 | 70,413 | ||||||||||||||||
(Gain) loss on change in fair value of contingent acquisition consideration | — | 93,019 | — | — | ||||||||||||||||
Loss on early extinguishment of debt | 1,205 | — | 1,500 | — | ||||||||||||||||
Tax effect of reconciling items (1) | 69,976 | (240,513) | 50,784 | (223,045) | ||||||||||||||||
Other tax items (2) | (427,962) | (2,987) | (427,962) | (2,987) | ||||||||||||||||
Adjusted Net Income | $ | 71,100 | $ | 364,562 | $ | 102,917 | $ | 315,271 | ||||||||||||
Fully Diluted Shares Outstanding | 316,283 | 316,675 | 316,283 | 316,365 | ||||||||||||||||
Net Income (loss) attributable to Antero Resources Corp | 1.94 | (1.26) | 1.94 | (1.26) | ||||||||||||||||
Commodity derivative fair value (gains) losses | (2.08) | 0.28 | (2.08) | 0.28 | ||||||||||||||||
Gains (losses) on settled commodity derivatives | 0.68 | 0.77 | 0.68 | 0.77 | ||||||||||||||||
Marketing derivative fair value losses | 0.07 | (0.30) | 0.07 | (0.30) | ||||||||||||||||
Losses on settled marketing derivatives | — | 0.23 | — | 0.23 | ||||||||||||||||
Impairment of unproved properties | 0.50 | 1.75 | 0.50 | 1.77 | ||||||||||||||||
Impairment of gathering systems and facilities | 0.00 | — | 0.07 | — | ||||||||||||||||
Equity-based compensation | 0.24 | 0.16 | 0.33 | 0.22 | ||||||||||||||||
(Gain) loss on change in fair value of contingent acquisition consideration | — | 0.29 | — | — | ||||||||||||||||
Loss on early extinguishment of debt | 0.00 | — | 0.00 | — | ||||||||||||||||
Tax effect of reconciling items (1) | 0.22 | (0.76) | 0.16 | (0.70) | ||||||||||||||||
Other tax items (2) | (1.35) | (0.01) | (1.35) | (0.01) | ||||||||||||||||
Adjusted Net Income | $ | 0.22 | $ | 1.15 | $ | 0.33 | $ | 1.00 |
(1) | Blended tax rates of approximately 38% for 2017 and 24% for 2018 were applied to reconciling items above. |
(2) | Tax impact of valuation allowance on Colorado net operating losses, changes to Colorado tax law, tax reform legislation enacted in late 2017 and items effecting the Stand-alone financial statements. |
Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow
Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items. Stand-alone Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Free Cash Flow as defined by the Company represents Stand-alone Adjusted Operating Cash Flow, less Stand-alone Drilling and Completion capital, less Land Maintenance Capital.
Management believes that Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.
There are significant limitations to using Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow reported by different companies. Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Operating Cash Flow and Free Cash Flow are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to Adjusted Operating Cash Flow as used in this release (in thousands):
Stand-alone | Consolidated | |||||||||||||||||||||||||||||
Three months ended | Three months ended | |||||||||||||||||||||||||||||
December 31, 2018 | December 31, 2018 | |||||||||||||||||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||||||||||||||||
Net cash provided by operating activities | $ | 254,078 | 729,082 | $ | 313,483 | 821,589 | ||||||||||||||||||||||||
Net change in working capital | 57,666 | 46,074 | 54,054 | 41,656 | ||||||||||||||||||||||||||
Adjusted Operating Cash Flow | $ | 311,744 | 775,156 | $ | 367,537 | 863,245 | ||||||||||||||||||||||||
Total Debt, Net Debt and Stand-alone Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Consolidated Net Debt and Stand-alone Net Debt to evaluate its financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Consolidated Net Debt and Stand-alone Net Debt as used in this release (in thousands):
Adjusted EBITDAX and Stand-alone Adjusted EBITDAX
December 31, | December 31, | ||||||
2017 | 2018 | ||||||
AR bank credit facility | $ | 185,000 | 405,000 | ||||
AM bank credit facility | 555,000 | 990,000 | |||||
5.375% AR senior notes due 2021 | 1,000,000 | 1,000,000 | |||||
5.125% AR senior notes due 2022 | 1,100,000 | 1,100,000 | |||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | |||||
5.375% AM senior notes due 2024 | 650,000 | 650,000 | |||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | |||||
Net unamortized premium | 1,520 | 1,241 | |||||
Net unamortized debt issuance costs | (41,430) | (34,553) | |||||
Consolidated total debt | $ | 4,800,090 | 5,461,688 | ||||
Less: AR cash and cash equivalents | 20,078 | — | |||||
Less: AM cash and cash equivalents | 8,363 | — | |||||
Consolidated net debt | $ | 4,771,649 | 5,461,688 | ||||
Less: Antero Midstream debt net of cash and unamortized premium and debt issuance costs | $ | 1,187,637 | 1,632,147 | ||||
Stand-alone Net Debt | $ | 3,584,012 | 3,829,541 | ||||
Adjusted EBITDAX as defined by the Company represents net income or loss from continuing operations, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and contract termination and rig stacking costs. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-alone Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses other than proceeds from derivative monetizations), taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's consolidated financial statements. The GAAP financial measure nearest to Stand-alone Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-alone Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-alone Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Stand-alone | Consolidated | ||||||||||||
Three months ended December 31, | Three months ended December 31, | ||||||||||||
(in thousands) | 2017 | 2018 | 2017 | 2018 | |||||||||
Net (loss) and comprehensive (loss) attributable to Antero Resources Corporation | $ | 486,869 | $ | (121,546) | $ | 486,869 | $ (121,546) | ||||||
Net income and comprehensive income attributable to noncontrolling interest | — | — | 42,745 | 140,282 | |||||||||
Commodity derivative fair value (gains) losses | (199,824) | 222,387 | (199,824) | 222,387 | |||||||||
Gains (losses) on settled commodity derivatives | 76,548 | (25,257) | 76,548 | (25,257) | |||||||||
Marketing derivative fair value losses | 21,394 | — | 21,394 | — | |||||||||
Losses on settled marketing derivatives | — | (5,411) | — | (5,411) | |||||||||
Interest expense | 53,687 | 59,458 | 63,390 | 78,440 | |||||||||
Loss on early extinguishment of debt | 1,205 | — | 1,500 | — | |||||||||
Income tax expense (benefit) | (400,138) | (131,357) | (400,138) | (131,357) | |||||||||
Depletion, depreciation, amortization, and accretion | 183,439 | 240,977 | 214,397 | 263,703 | |||||||||
Impairment of unproved properties | 76,500 | 143,369 | 76,500 | 143,369 | |||||||||
Impairment of gathering systems and facilities | — | — | 23,431 | — | |||||||||
Exploration expense | 3,028 | 936 | 3,028 | 936 | |||||||||
Gain on change in fair value of contingent acquisition consideration | (3,804) | 104,860 | — | — | |||||||||
Equity-based compensation expense | 17,673 | 9,518 | 24,520 | 13,984 | |||||||||
Equity in earnings of unconsolidated affiliates | — | — | (7,307) | (12,448) | |||||||||
Distributions from unconsolidated affiliates | — | — | 10,075 | 16,755 | |||||||||
Equity in (earnings) loss of Antero Midstream Partners LP | 22,128 | (66,753) | — | — | |||||||||
Distributions from Antero Midstream Partners LP | 33,614 | 43,503 | — | — | |||||||||
Adjusted EBITDAX | 372,319 | 474,684 | 437,128 | 583,837 | |||||||||
Interest expense | (53,687) | (59,458) | (63,390) | (78,440) | |||||||||
Exploration expense | (3,028) | (936) | (3,028) | (936) | |||||||||
Changes in current assets and liabilities | (57,666) | (46,074) | (54,054) | (41,656) | |||||||||
Proceeds from derivative monetizations | — | 370,365 | — | 370,365 | |||||||||
Premium paid on derivative contracts | — | (13,318) | — | (13,318) | |||||||||
Other non-cash items | (3,860) | 3,829 | (3,173) | 1,736 | |||||||||
Net cash provided by operating activities | $ | 254,078 | $ | 729,092 | $ | 313,483 | $ | 821,588 | |||||
Adjusted EBITDAX | $ | 372,319 | $ | 474,684 | $ | 437,128 | $ | 583,837 | |||||
Production (MMcfe) | 215,921 | 295,576 | 215,921 | 295,576 | |||||||||
Adjusted EBITDAX margin per Mcfe | $ | 1.72 | 1.61 | $ | 2.02 | $ | 1.98 |
The following table reconciles net income as reported in the Parent column of Antero's guarantor footnote to its financial statements to Stand-alone Adjusted EBITDAX for the twelve months ended December 31, 2018, as used in this release (in thousands):
Stand-alone | |||||||||||||
Twelve months ended | |||||||||||||
(in thousands) | December 31, 2018 | ||||||||||||
Net (loss) and comprehensive (loss) attributable to Antero Resources Corporation | $ | (397,517) | |||||||||||
Commodity derivative fair value (gains) losses | 87,594 | ||||||||||||
Gains on settled commodity derivatives | 243,112 | ||||||||||||
Marketing derivative fair value gains | (94,081) | ||||||||||||
Gains on settled marketing derivatives | 72,687 | ||||||||||||
Interest expense | 224,977 | ||||||||||||
Income tax benefit | (128,857) | ||||||||||||
Depletion, depreciation, amortization, and accretion | 845,136 | ||||||||||||
Impairment of unproved properties | 549,437 | ||||||||||||
Impairment of gathering systems and facilities | 4,470 | ||||||||||||
Exploration expense | 4,958 | ||||||||||||
Gain on change in fair value of contingent acquisition consideration | 93,019 | ||||||||||||
Equity-based compensation expense | 49,341 | ||||||||||||
Equity in (earnings) loss of Antero Midstream Partners LP | 3,664 | ||||||||||||
Distributions from Antero Midstream Partners LP | 159,181 | ||||||||||||
Stand-alone Adjusted EBITDAX | $ | 1,717,121 |
The following tables reconcile Antero's drilling and completion costs as reported on a cash basis to drilling and completion costs on an accrual basis:
Drilling and Completion Costs
Three Months Ended December 31, 2018 | Years Ended December 31, 2018 | |||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||
Drilling and completion costs (as reported; cash basis) | $ | 335,476 | $ | 362,912 | $ | 1,281,985 | $ | 1,488,573 | ||||
Change in accrued capital costs | (14,391) | (25,539) | (14,005) | (2,363) | ||||||||
Drilling and completion costs (accrual basis) | $ | 321,086 | $ | 337,374 | $ | 1,267,980 | $ | 1,486,210 |
Stand-alone Drilling and Completion Costs
Three Months Ended December 31, 2018 | Years Ended December 31, 2018 | |||||||||||||||||
2017 | 2018 | 2017 | 2018 | |||||||||||||||
Stand-alone drilling and completion costs (as reported; cash basis) | $ | 373,350 | $ | 415,298 | $ | 1,455,554 | $ | 1,743,587 | ||||||||||
Change in accrued capital costs | (2,820) | (36,633) | 241,303 | (15,238) | ||||||||||||||
Stand-alone drilling and completion costs (accrual basis) | $ | 370,530 | $ | 378,665 | $ | 1,696,857 | $ | 1,728,349 | ||||||||||
Proved Developed F&D Cost Per Unit & Pre-Tax PV-10 Value
Proved developed F&D costs per unit and pre-tax PV-10 are non-GAAP metrics commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. Proved developed F&D costs per unit is a statistical indicator that has limitations, including its predictive and comparative value. In addition, because proved developed F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. This reserve metric may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for proved developed F&D costs per unit, and therefore a reconciliation to GAAP is not practicable.
The calculation for proved developed F&D cost per unit is based on costs incurred in 2018. The calculation for proved developed F&D cost per unit does not include future development costs required for the development of proved undeveloped reserves.
The pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. Antero believes that the presentation of pre-tax PV-10 is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies. Antero believes that PV-10 estimates using strip pricing can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2018:
(In millions, except per Mcf data) | |||
At December 31, 2018 | |||
Future net cash flows | $ | 30,739 | |
Present value of future net cash flows: | |||
Before income tax (PV-10) | $ | 12,589 | |
Income taxes | $ | (2,111) | |
After income tax (Standardized measure) | $ | 10,478 |
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero Midstream Adjusted EBITDA & Distributable Cash Flow
Antero Midstream views Adjusted EBITDA as an important indicator of its performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, gain on sale of assets, depreciation expense, impairment expense, change in fair value of contingent acquisition consideration, accretion, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are Non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The Non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Three months ended | Years ended | ||||||||||
December 31, | December 31, | ||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||
Net income | $ | 64,155 | $ | 248,609 | $ | 307,315 | $ | 585,944 | |||
Impairment of property and equipment | 23,431 | — | 23,431 | 5,771 | |||||||
Change in fair value of contingent acquisition consideration | — | (105,872) | — | (105,872) | |||||||
Adjusted Net Income | $ | 87,586 | $ | 142,737 | $ | 344,872 | $ | 485,843 | |||
Interest expense, net | 10,395 | 18,993 | 37,557 | 61,906 | |||||||
Depreciation | 30,958 | 22,692 | 119,562 | 130,013 | |||||||
Accretion of contingent acquisition consideration | 3,804 | 1,012 | 13,476 | 12,853 | |||||||
Accretion of asset retirement obligation | — | 34 | 135 | ||||||||
Equity-based compensation | 6,847 | 4,467 | 27,283 | 21,073 | |||||||
Equity in earnings of unconsolidated affiliates | (7,307) | (12,448) | (20,194) | (40,280) | |||||||
Distributions from unconsolidated affiliates | 10,075 | 16,755 | 20,195 | 46,415 | |||||||
Gain on sale of assets – Antero Resources | — | — | — | (583) | |||||||
Adjusted EBITDA | $ | 142,358 | $ | 194,242 | $ | 528,625 | $ | 717,375 | |||
Interest paid | (4,136) | (9,268) | (46,666) | (62,844) | |||||||
Decrease (increase) in cash reserved for bond interest (1) | (8,734) | (8,734) | 291 | 0 | |||||||
Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards | (514) | (1,029) | (5,945) | (5,529) | |||||||
Maintenance capital expenditures(2) | (12,063) | (7,988) | (55,159) | (52,729) | |||||||
Distributable Cash Flow | $ | 116,911 | $ | 167,223 | $ | 421,146 | $ | 596,273 | |||
Distributions Declared to Antero Midstream Holders | |||||||||||
Limited partners | 68,231 | 88,045 | 247,132 | 320,915 | |||||||
Incentive distribution rights | 23,772 | 43,492 | 69,720 | 142,906 | |||||||
Total Aggregate Distributions | $ | 92,003 | $ | 131,537 | $ | 316,852 | $ | 463,821 | |||
DCF coverage ratio | 1.27x | 1.27x | 1.33x | 1.29x |
(1) | Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. |
(2) | Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding the expected sources of funding and timing for completion of the share repurchase program if at all, statements regarding the simplification transaction, including the expected consideration to be received in connection with the closing of the simplification transaction, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Free Cash Flow and leverage targets, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, the expected timing and likelihood of completion of the simplification transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
This release provides a summary of Antero's reserves as of December 31, 2018, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
No Offer or Solicitation
This communication includes a discussion of a proposed business combination transaction between Antero Midstream and AMGP. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Additional Information And Where To Find It
In connection with the transaction, AMGP has filed with the U.S. Securities and Exchange Commission ("SEC") a registration statement on Form S-4, that includes a joint proxy statement of Antero Midstream and AMGP and a prospectus of AMGP. The transaction will be submitted to Antero Midstream unitholders and AMGP shareholders for their consideration. Antero Midstream and AMGP may also file other documents with the SEC regarding the transaction. The registration statement on Form S-4 became effective on January 30, 2019, and the definitive joint proxy statement/prospectus is being sent to the shareholders of AMGP and unitholders of Antero Midstream of record as of January 11, 2019. This document is not a substitute for the registration statement and joint proxy statement/prospectus that has been filed with the SEC or any other documents that AMGP or Antero Midstream may file with the SEC or send to shareholders of AMGP or unitholders of Antero Midstream in connection with the transaction. INVESTORS AND SECURITY HOLDERS OF ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders are able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or Antero Midstream through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Antero Midstream will be made available free of charge on Antero Midstream's website at http://investors.anteromidstream.com/investor-relations/AM, under the heading "SEC Filings," or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310.
ANTERO RESOURCES CORPORATION Consolidated Balance Sheets December 31, 2017 and 2018 (In thousands, except per share amounts) | ||||||
2017 | 2018 | |||||
Assets | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 28,441 | — | |||
Accounts receivable, net of allowance for doubtful accounts of $1,320 and $-0- at December 31, 2017 and 2018, respectively | 34,896 | 51,073 | ||||
Accrued revenue | 300,122 | 474,827 | ||||
Derivative instruments | 460,685 | 245,263 | ||||
Other current assets | 8,943 | 35,450 | ||||
Total current assets | 833,087 | 806,613 | ||||
Property and equipment: | ||||||
Natural gas properties, at cost (successful efforts method): | ||||||
Unproved properties | 2,266,673 | 1,767,600 | ||||
Proved properties | 11,096,462 | 12,705,672 | ||||
Water handling and treatment systems | 946,670 | 1,013,818 | ||||
Gathering systems and facilities | 2,050,490 | 2,470,708 | ||||
Other property and equipment | 57,429 | 65,842 | ||||
16,417,724 | 18,023,640 | |||||
Less accumulated depletion, depreciation, and amortization | (3,182,171) | (4,153,725) | ||||
Property and equipment, net | 13,235,553 | 13,869,915 | ||||
Derivative instruments | 841,257 | 362,169 | ||||
Investments in unconsolidated affiliates | 303,302 | 433,642 | ||||
Other assets | 48,291 | 47,125 | ||||
Total assets | $ | 15,261,490 | 15,519,464 | |||
Liabilities and Equity | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 62,982 | 66,289 | |||
Accrued liabilities | 443,225 | 465,070 | ||||
Revenue distributions payable | 209,617 | 310,827 | ||||
Derivative instruments | 28,476 | 532 | ||||
Other current liabilities | 17,796 | 10,822 | ||||
Total current liabilities | 762,096 | 853,540 | ||||
Long-term liabilities: | ||||||
Long-term debt | 4,800,090 | 5,461,688 | ||||
Deferred income tax liability | 779,645 | 650,788 | ||||
Derivative instruments | 207 | — | ||||
Other liabilities | 43,316 | 65,971 | ||||
Total liabilities | 6,385,354 | 7,031,987 | ||||
Commitments and contingencies (Notes 13 and 14) | ||||||
Equity: | ||||||
Stockholders' equity: | ||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 308,594 shares issued and outstanding at December 31, 2017 and 2018, respectively | 3,164 | 3,086 | ||||
Additional paid-in capital | 6,570,952 | 6,485,174 | ||||
Accumulated earnings | 1,575,065 | 1,177,548 | ||||
Total stockholders' equity | 8,149,181 | 7,665,808 | ||||
Noncontrolling interests in consolidated subsidiary | 726,955 | 821,669 | ||||
Total equity | 8,876,136 | 8,487,477 | ||||
Total liabilities and equity | $ | 15,261,490 | 15,519,464 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) Three Months and Years Ended December 31, 2017 and 2018 (In thousands, except per share amounts) | |||||||||||||
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||
Revenue and other: | |||||||||||||
Natural gas sales | $ | 439,222 | 789,614 | $ | 1,769,284 | 2,287,939 | |||||||
Natural gas liquids sales | 280,437 | 349,353 | 870,441 | 1,177,777 | |||||||||
Oil sales | 28,196 | 58,310 | 108,195 | 187,178 | |||||||||
Commodity derivative fair value gains (losses) | 199,824 | (222,386) | 658,283 | (87,594) | |||||||||
Gathering, compression, water handling and treatment | 4,055 | 6,047 | 12,720 | 21,344 | |||||||||
Marketing | 91,386 | 64,712 | 258,045 | 458,901 | |||||||||
Marketing derivative fair value gains (losses) | (21,394) | (1) | (21,394) | 94,081 | |||||||||
Total revenue and other | 1,021,726 | 1,045,649 | 3,655,574 | 4,139,626 | |||||||||
Operating expenses: | |||||||||||||
Lease operating | 33,023 | 42,998 | 89,057 | 136,153 | |||||||||
Gathering, compression, processing, and transportation | 279,929 | 413,130 | 1,095,639 | 1,339,358 | |||||||||
Production and ad valorem taxes | 24,180 | 44,242 | 94,521 | 126,474 | |||||||||
Marketing | 119,983 | 125,132 | 366,281 | 686,055 | |||||||||
Exploration | 3,028 | 936 | 8,538 | 4,958 | |||||||||
Impairment of unproved properties | 76,500 | 143,370 | 159,598 | 549,437 | |||||||||
Impairment of gathering systems and facilities | 23,431 | — | 23,431 | 9,658 | |||||||||
Depletion, depreciation, and amortization | 213,731 | 262,985 | 824,610 | 972,465 | |||||||||
Accretion of asset retirement obligations | 666 | 719 | 2,610 | 2,819 | |||||||||
General and administrative (including equity-based compensation expense) | 60,196 | 58,767 | 251,196 | 240,344 | |||||||||
Total operating expenses | 834,667 | 1,092,279 | 2,915,481 | 4,067,721 | |||||||||
Operating income (loss) | 187,059 | (46,630) | 740,093 | 71,905 | |||||||||
Other income (expenses): | |||||||||||||
Equity in earnings of unconsolidated affiliates | 7,307 | 12,449 | 20,194 | 40,280 | |||||||||
Interest | (63,390) | (78,440) | (268,701) | (286,743) | |||||||||
Loss on early extinguishment of debt | (1,500) | — | (1,500) | — | |||||||||
Total other expenses | (57,583) | (65,991) | (250,007) | (246,463) | |||||||||
Income (loss) before income taxes | 129,476 | (112,621) | 490,086 | (174,558) | |||||||||
Provision for income tax benefit | 400,138 | 131,357 | 295,051 | 128,857 | |||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests | 529,614 | 18,736 | 785,137 | (45,701) | |||||||||
Net income and comprehensive income attributable to noncontrolling interests | 42,745 | 140,282 | 170,067 | 351,816 | |||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 486,869 | (121,546) | $ | 615,070 | (397,517) | |||||||
Earnings (loss) per common share—basic | $ | 1.54 | (0.39) | $ | 1.95 | (1.26) | |||||||
Earnings (loss) per common share—assuming dilution | $ | 1.54 | (0.39) | $ | 1.94 | (1.26) | |||||||
Weighted average number of shares outstanding: | |||||||||||||
Basic | 315,875 | 313,618 | 315,426 | 316,036 | |||||||||
Diluted | 316,682 | 313,618 | 316,283 | 316,036 |
ANTERO RESOURCES CORPORATION Consolidated Statements of Cash Flows Years Ended December 31, 2016, 2017 and 2018 (In thousands) | ||||||||||
2016 | 2017 | 2018 | ||||||||
Cash flows provided by (used in) operating activities: | ||||||||||
Net income (loss) including noncontrolling interests | $ | (749,448) | 785,137 | (45,701) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||
Depletion, depreciation, amortization, and accretion | 812,346 | 827,220 | 975,284 | |||||||
Impairment of unproved properties | 162,935 | 159,598 | 549,437 | |||||||
Impairment of gathering systems and facilities | — | 23,431 | 9,658 | |||||||
Commodity derivative fair value (gains) losses | 514,181 | (658,283) | 87,594 | |||||||
Gains on settled commodity derivatives | 1,003,083 | 213,940 | 243,112 | |||||||
Premium paid on derivative contracts | — | — | (13,318) | |||||||
Proceeds from derivative monetizations | — | 749,906 | 370,365 | |||||||
Marketing derivative fair value (gains) losses | — | 21,394 | (94,081) | |||||||
Gains on settled marketing derivatives | — | — | 72,687 | |||||||
Deferred income tax benefit | (485,392) | (295,126) | (128,857) | |||||||
Gain on sale of assets | (97,635) | — | — | |||||||
Equity-based compensation expense | 102,421 | 103,445 | 70,414 | |||||||
Loss on early extinguishment of debt | 16,956 | 1,500 | — | |||||||
Equity in earnings of unconsolidated affiliates | (485) | (20,194) | (40,280) | |||||||
Distributions of earnings from unconsolidated affiliates | 7,702 | 20,195 | 46,415 | |||||||
Other | (12,488) | (1,907) | 4,681 | |||||||
Changes in current assets and liabilities: | ||||||||||
Accounts receivable | 39,857 | (5,214) | (15,156) | |||||||
Accrued revenue | (133,718) | (38,162) | (174,706) | |||||||
Other current assets | 1,774 | (2,755) | (5,817) | |||||||
Accounts payable | 7,365 | 9,462 | 9,307 | |||||||
Accrued liabilities | 18,853 | 64,862 | 63,562 | |||||||
Revenue distributions payable | 34,040 | 45,628 | 101,210 | |||||||
Other current liabilities | (1,091) | 2,214 | (3,823) | |||||||
Net cash provided by operating activities | 1,241,256 | 2,006,291 | 2,081,987 | |||||||
Cash flows provided by (used in) investing activities: | ||||||||||
Additions to proved properties | (134,113) | (175,650) | — | |||||||
Additions to unproved properties | (611,631) | (204,272) | (172,387) | |||||||
Drilling and completion costs | (1,327,759) | (1,281,985) | (1,488,573) | |||||||
Additions to water handling and treatment systems | (188,188) | (194,502) | (97,699) | |||||||
Additions to gathering systems and facilities | (231,044) | (346,217) | (444,413) | |||||||
Additions to other property and equipment | (2,694) | (14,127) | (7,514) | |||||||
Investments in unconsolidated affiliates | (75,516) | (235,004) | (136,475) | |||||||
Change in other assets | 3,977 | (12,029) | (3,663) | |||||||
Proceeds from asset sales | 171,830 | 2,156 | — | |||||||
Net cash used in investing activities | (2,395,138) | (2,461,630) | (2,350,724) | |||||||
Cash flows provided by (used in) financing activities: | ||||||||||
Issuance of common stock | 1,012,431 | — | — | |||||||
Issuance of common units by Antero Midstream Partners LP | 65,395 | 248,956 | — | |||||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation | 178,000 | 311,100 | — | |||||||
Repurchases of common stock | — | — | (129,084) | |||||||
Issuance of senior notes | 1,250,000 | — | — | |||||||
Repayment of senior notes | (525,000) | — | — | |||||||
Borrowings (repayments) on bank credit facilities, net | (677,000) | 90,000 | 660,379 | |||||||
Make-whole premium on debt extinguished | (15,750) | — | — | |||||||
Payments of deferred financing costs | (18,759) | (16,377) | (2,169) | |||||||
Distributions to noncontrolling interests in consolidated subsidiary | (75,082) | (152,352) | (267,271) | |||||||
Employee tax withholding for settlement of equity compensation awards | (26,895) | (24,174) | (17,020) | |||||||
Other | (5,321) | (4,983) | (4,539) | |||||||
Net cash provided by financing activities | 1,162,019 | 452,170 | 240,296 | |||||||
Net increase (decrease) in cash and cash equivalents | 8,137 | (3,169) | (28,441) | |||||||
Cash and cash equivalents, beginning of period | 23,473 | 31,610 | 28,441 | |||||||
Cash and cash equivalents, end of period | $ | 31,610 | 28,441 | — | ||||||
Supplemental disclosure of cash flow information: | ||||||||||
Cash paid during the period for interest | $ | 239,369 | 263,919 | 275,769 | ||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment | $ | (152,093) | (547) | (47,717) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended December 31, 2017 and 2018: | |||||||||||||
Three Months Ended December 31, | Amount of | Percent | |||||||||||
(in thousands) | 2017 | 2018 | (Decrease) | Change | |||||||||
Operating revenues and other: | |||||||||||||
Natural gas sales | $ | 439,222 | $ | 789,614 | $ | 350,392 | 80 | % | |||||
NGLs sales | 280,437 | 349,353 | 68,916 | 25 | % | ||||||||
Oil sales | 28,196 | 58,310 | 30,114 | 107 | % | ||||||||
Commodity derivative fair value gains (losses) | 199,824 | (222,386) | (422,210) | (211) | % | ||||||||
Gathering, compression, water handling and treatment | 4,055 | 6,047 | 1,992 | 49 | % | ||||||||
Marketing | 91,386 | 64,712 | (26,674) | (29) | % | ||||||||
Marketing derivative fair value gains | (21,394) | (1) | 21,393 | (100) | % | ||||||||
Total operating revenues and other | 1,021,726 | 1,045,649 | 23,923 | 2 | % | ||||||||
Operating expenses: | |||||||||||||
Lease operating | 33,023 | 42,998 | 9,975 | 30 | % | ||||||||
Gathering, compression, processing, and transportation | 279,929 | 413,130 | 133,201 | 48 | % | ||||||||
Production and ad valorem taxes | 24,180 | 44,242 | 20,062 | 83 | % | ||||||||
Marketing | 119,983 | 125,132 | 5,149 | 4 | % | ||||||||
Exploration | 3,028 | 936 | (2,092) | (69) | % | ||||||||
Impairment of unproved properties | 76,500 | 143,370 | 66,870 | 87 | % | ||||||||
Impairment of gathering systems and facilities | 23,431 | — | (23,431) | (100) | % | ||||||||
Depletion, depreciation, and amortization | 213,731 | 262,985 | 49,254 | 23 | % | ||||||||
Accretion of asset retirement obligations | 666 | 719 | 53 | 8 | % | ||||||||
General and administrative (excluding equity-based compensation) | 35,676 | 44,782 | 9,106 | 26 | % | ||||||||
Equity-based compensation | 24,520 | 13,985 | (10,535) | (43) | % | ||||||||
Total operating expenses | 834,667 | 1,092,279 | 257,612 | 31 | % | ||||||||
Operating income (loss) | 187,059 | (46,630) | (233,689) | (125) | % | ||||||||
Other earnings (expenses): | |||||||||||||
Equity in earnings of unconsolidated affiliates | 7,307 | 12,449 | 5,142 | 70 | % | ||||||||
Interest expense | (63,390) | (78,440) | (15,050) | 24 | % | ||||||||
Loss on early extinguishment of debt | (1,500) | — | 1,500 | (100) | % | ||||||||
Total other expenses | (57,583) | (65,991) | (8,408) | 15 | % | ||||||||
Income (loss) before income taxes | 129,476 | (112,621) | (242,097) | (187) | % | ||||||||
Income tax (expense) benefit | 400,138 | (131,357) | (531,495) | (66) | % | ||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | 529,614 | 18,736 | (510,878) | (96) | % | ||||||||
Net income and comprehensive income attributable to noncontrolling interest | 42,745 | 140,282 | 97,537 | 228 | % | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 486,869 | $ | (121,546) | $ | (608,415) | (125) | % | |||||
Adjusted EBITDAX | $ | 437,128 | $ | 583,837 | $ | 146,709 | 34 | % | |||||
Three Months Ended December 31, | Amount of | Percent | |||||||||||
(Exploration and Production segment) | 2017 | 2018 | (Decrease) | Change | |||||||||
Production data: | |||||||||||||
Natural gas (Bcf) | 157 | 206 | 49 | 31 | % | ||||||||
C2 Ethane (MBbl) | 2,891 | 4,323 | 1,432 | 50 | % | ||||||||
C3+ NGLs (MBbl) | 6,422 | 9,463 | 3,041 | 47 | % | ||||||||
Oil (MBbl) | 571 | 1,125 | 554 | 97 | % | ||||||||
Combined (Bcfe) | 216 | 296 | 80 | 37 | % | ||||||||
Daily combined production (MMcfe/d) | 2,347 | 3,213 | 866 | 37 | % | ||||||||
Average prices before effects of derivative settlements: | |||||||||||||
Natural gas (per Mcf) | $ | 2.80 | $ | 3.83 | $ | 1.03 | 37 | % | |||||
C2 Ethane (per Bbl) | $ | 10.02 | $ | 13.12 | $ | 3.10 | 31 | % | |||||
C3+ NGLs (per Bbl) | $ | 39.16 | $ | 30.92 | $ | (8.24) | (21) | % | |||||
Oil (per Bbl) | $ | 49.37 | $ | 51.83 | $ | 2.46 | 5 | % | |||||
Weighted Average Combined (per Mcfe) | $ | 3.46 | $ | 4.05 | $ | 0.59 | 17 | % | |||||
Average realized prices after effects of derivative settlements: | |||||||||||||
Natural gas (per Mcf) | $ | 3.67 | $ | 3.73 | $ | 0.06 | 2 | % | |||||
C2 Ethane (per Bbl) | $ | 10.17 | $ | 13.12 | $ | 2.95 | 29 | % | |||||
C3+ NGLs (per Bbl) | $ | 29.92 | $ | 30.60 | $ | 0.68 | 2 | % | |||||
Oil (per Bbl) | $ | 49.06 | $ | 50.92 | $ | 1.86 | 4 | % | |||||
Weighted Average Combined (per Mcfe) | $ | 3.82 | $ | 3.97 | $ | 0.15 | 4 | % | |||||
Average Costs (per Mcfe): | |||||||||||||
Lease operating | $ | 0.17 | $ | 0.15 | $ | (0.02) | (12) | % | |||||
Gathering, compression, processing, and transportation | $ | 1.72 | $ | 1.88 | $ | 0.16 | 9 | % | |||||
Production and ad valorem taxes | $ | 0.11 | $ | 0.15 | $ | 0.04 | 36 | % | |||||
Marketing expense, net | $ | 0.13 | $ | 0.20 | $ | 0.07 | 54 | % | |||||
Depletion, depreciation, amortization, and accretion | $ | 0.85 | $ | 0.82 | $ | (0.03) | (4) | % | |||||
General and administrative (excluding equity-based compensation) | $ | 0.13 | $ | 0.11 | $ | (0.02) | (15) | % |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the years ended December 31, 2017 and 2018: | |||||||||||||
Year Ended December 31, | Amount of | Percent | |||||||||||
(in thousands) | 2017 | 2018 | (Decrease) | Change | |||||||||
Operating revenues and other: | |||||||||||||
Natural gas sales | $ | 1,769,284 | $ | 2,287,939 | $ | 518,655 | 29 | % | |||||
NGLs sales | 870,441 | 1,177,777 | 307,336 | 35 | % | ||||||||
Oil sales | 108,195 | 187,178 | 78,983 | 73 | % | ||||||||
Commodity derivative fair value gains (losses) | 658,283 | (87,594) | (745,877) | (113) | % | ||||||||
Gathering, compression, water handling and treatment | 12,720 | 21,344 | 8,624 | 68 | % | ||||||||
Marketing | 258,045 | 458,901 | 200,856 | 78 | % | ||||||||
Marketing derivative fair value gains | (21,394) | 94,081 | 115,475 | (540) | % | ||||||||
Total operating revenues and other | 3,655,574 | 4,139,626 | 484,052 | 13 | % | ||||||||
Operating expenses: | |||||||||||||
Lease operating | 89,057 | 136,153 | 47,096 | 53 | % | ||||||||
Gathering, compression, processing, and transportation | 1,095,639 | 1,339,358 | 243,719 | 22 | % | ||||||||
Production and ad valorem taxes | 94,521 | 126,474 | 31,953 | 34 | % | ||||||||
Marketing | 366,281 | 686,055 | 319,774 | 87 | % | ||||||||
Exploration | 8,538 | 4,958 | (3,580) | (42) | % | ||||||||
Impairment of unproved properties | 159,598 | 549,437 | 389,839 | 244 | % | ||||||||
Impairment of gathering systems and facilities | 23,431 | 9,658 | (13,773) | (59) | % | ||||||||
Depletion, depreciation, and amortization | 824,610 | 972,465 | 147,855 | 18 | % | ||||||||
Accretion of asset retirement obligations | 2,610 | 2,819 | 209 | 8 | % | ||||||||
General and administrative (excluding equity-based compensation) | 147,751 | 169,930 | 22,179 | 15 | % | ||||||||
Equity-based compensation | 103,445 | 70,414 | (33,031) | (32) | % | ||||||||
Total operating expenses | 2,915,481 | 4,067,721 | 1,152,240 | 40 | % | ||||||||
Operating income (loss) | 740,093 | 71,905 | (668,188) | (90) | % | ||||||||
Other earnings (expenses): | |||||||||||||
Equity in earnings of unconsolidated affiliates | 20,194 | 40,280 | 20,086 | 99 | % | ||||||||
Interest expense | (268,701) | (286,743) | (18,042) | 7 | % | ||||||||
Loss on early extinguishment of debt | (1,500) | — | 1,500 | (100) | % | ||||||||
Total other expenses | (250,007) | (246,463) | 3,544 | (1) | % | ||||||||
Income (loss) before income taxes | 490,086 | (174,558) | (664,644) | (136) | % | ||||||||
Income tax benefit | 295,051 | 128,857 | (166,194) | (56) | % | ||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | 785,137 | (45,701) | (830,838) | (106) | % | ||||||||
Net income and comprehensive income attributable to noncontrolling interest | 170,067 | 351,816 | 181,749 | 107 | % | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | 615,070 | $ | (397,517) | $ | (1,012,587) | (165) | % | |||||
Adjusted EBITDAX | $ | 1,459,571 | $ | 2,037,382 | $ | 577,811 | 40 | % | |||||
Year Ended December 31, | Amount of | Percent | |||||||||||
(Exploration and Production segment) | 2017 | 2018 | (Decrease) | Change | |||||||||
Production data: | |||||||||||||
Natural gas (Bcf) | 591 | 710 | 119 | 20 | % | ||||||||
C2 Ethane (MBbl) | 10,539 | 14,221 | 3,682 | 35 | % | ||||||||
C3+ NGLs (MBbl) | 25,507 | 28,913 | 3,406 | 13 | % | ||||||||
Oil (MBbl) | 2,451 | 3,265 | 814 | 33 | % | ||||||||
Combined (Bcfe) | 822 | 989 | 167 | 20 | % | ||||||||
Daily combined production (MMcfe/d) | 2,253 | 2,709 | 456 | 20 | % | ||||||||
Average prices before effects of derivative settlements: | |||||||||||||
Natural gas (per Mcf) | $ | 2.99 | $ | 3.22 | $ | 0.23 | 8 | % | |||||
C2 Ethane (per Bbl) | $ | 8.83 | $ | 12.14 | $ | 3.31 | 37 | % | |||||
C3+ NGLs (per Bbl) | $ | 30.48 | $ | 34.76 | $ | 4.28 | 14 | % | |||||
Oil (per Bbl) | $ | 44.14 | $ | 57.34 | $ | 13.20 | 30 | % | |||||
Weighted Average Combined (per Mcfe) | $ | 3.34 | $ | 3.69 | $ | 0.35 | 10 | % | |||||
Average realized prices after effects of derivative settlements: | |||||||||||||
Natural gas (per Mcf) | $ | 3.61 | $ | 3.65 | $ | 0.04 | 1 | % | |||||
C2 Ethane (per Bbl) | $ | 9.04 | $ | 12.14 | $ | 3.10 | 34 | % | |||||
C3+ NGLs (per Bbl) | $ | 24.27 | $ | 33.25 | $ | 8.98 | 37 | % | |||||
Oil (per Bbl) | $ | 45.85 | $ | 52.11 | $ | 6.26 | 14 | % | |||||
Weighted Average Combined (per Mcfe) | $ | 3.60 | $ | 3.94 | $ | 0.34 | 9 | % | |||||
Average Costs (per Mcfe): | |||||||||||||
Lease operating | $ | 0.11 | $ | 0.14 | $ | 0.03 | 27 | % | |||||
Gathering, compression, processing, and transportation | $ | 1.75 | $ | 1.81 | $ | 0.06 | 3 | % | |||||
Production and ad valorem taxes | $ | 0.11 | $ | 0.12 | $ | 0.01 | 9 | % | |||||
Marketing expense, net | $ | 0.13 | $ | 0.23 | $ | 0.10 | 77 | % | |||||
Depletion, depreciation, amortization, and accretion | $ | 0.86 | $ | 0.85 | $ | (0.01) | (1) | % | |||||
General and administrative (excluding equity-based compensation) | $ | 0.14 | $ | 0.13 | $ | (0.01) | (7) | % |
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SOURCE Antero Resources Corporation
DENVER, Jan. 29, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced that Richard W. Connor has resigned from the board of directors of Antero Resources (the "Board") effective as of January 24, 2019 for personal reasons. The resignation was not the result of any disagreement with the Company or any of its affiliates on any matter relating to the Company's operations, policies or practices. In connection with Mr. Connor's resignation from the Board and from his position as chairman of the Board's audit committee, the size of the Board was reduced from ten members to nine members and Paul J. Korus, currently a member of the Board's audit committee, was appointed as the chairman of the audit committee.
Paul M. Rady, Chairman and CEO of Antero Resources commented, "I would like to thank Rick for his contribution to Antero's success through these past years. Rick joined the Board prior to our initial public offering and has contributed significantly to the Company's progress during his tenure. We are grateful for his contributions to Antero Resources and wish him the very best in the future."
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Jan. 17, 2019 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its fourth quarter and full year 2018 earnings release on Wednesday, February 13, 2019 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, February 14, 2019 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, February 28, 2019 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10123136.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, February 28, 2019 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Jan. 8, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") today announced its 2019 capital budget and production guidance, reflecting a disciplined plan with Stand-alone drilling and completion capital spending at Stand-alone Adjusted Operating Cash Flow levels assuming $50 per barrel WTI oil and $3.00 per MMBtu NYMEX natural gas, while generating double digit production growth.
Guidance Highlights:
Paul Rady, Chairman and Chief Executive Officer of Antero Resources commented, "Our 2019 drilling and completion plan reflects the impacts from efficiencies that continue to improve our development program. These efficiencies allow us to forecast attractive, double digit production growth despite fewer completion crews budgeted for 2019. We remain focused on capital discipline and have the operational and financial flexibility to adjust our development plan with changing commodity prices. Our diversified production mix along with our industry-leading hedge book and firm transportation portfolio have enabled us to effectively reduce commodity price risk including local basis risk. We believe these attributes will continue to provide Antero with a competitive advantage moving forward. To the extent that commodity prices strengthen, we expect capital allocation to reflect an appropriate mix of growth and return of capital to shareholders while continuing to maintain a strong balance sheet."
Commenting on the 2019 outlook, Glen Warren, President, and Chief Financial Officer of Antero Resources said, "The strength of our balance sheet gives us flexibility with respect to our 2019 and future development plans, which is critical given the recent commodity price volatility. Going forward, our strategy will be focused on low leverage, prudent capital spending and a mix of production growth and return of capital to shareholders. If commodity prices deteriorate further, we have built in the flexibility to adjust our development plan accordingly. Long-term, we remain committed to a strategy of spending within cash flow, maintaining a strong balance sheet that includes an appropriate amount of commodity price hedging and returning the majority of free cash flow to shareholders."
Recent Developments
During the fourth quarter of 2018 Antero initiated its $600 million share repurchase program. As previously announced, through year-end 2018, Antero returned $129 million of cash to shareholders by repurchasing 9.1 million shares, thereby reducing shares outstanding by 3%. Additionally, during the fourth quarter, Antero monetized $357 million of its hedge position allowing the Company to further deleverage while maintaining upside to the natural gas strip in 2019.
In November 2018, Antero began delivering ethane under its 11,500 Bbl/d ten-year export agreement with Borealis. The ethane is being delivered through Mariner East 1 to Marcus Hook and loaded for shipment to Borealis' steam cracker in Sweden. The Mariner East 2 pipeline was placed in service on December 29, 2018, enabling Antero to transport up to 50,000 Bbl/d of propane and butane to Marcus Hook for export. Mariner East 2 is expected to improve propane and butane netbacks by approximately $2.00 to $4.00 per barrel on an annual basis.
In the fourth quarter of 2018, Antero executed its first supply agreement with a premier sand supplier to directly source its sand needs for completions. The first shipment of sand was received in mid-November. The Company expects to directly source high quality, low-cost sand for over 70% of its 2019 development program through similar agreements with additional sand suppliers. Antero anticipates well cost savings of approximately $200,000 per well compared to 2018 levels due to sand self-sourcing.
2019 Capital Budget and Guidance
The following is a summary of Antero Resources' 2019 consolidated and Stand-alone capital budgets for drilling and completion and land capital.
Capital Budget ($ in MM) | Consolidated | Stand-alone | ||||||||
Low | High | Low | High | |||||||
Drilling & Completion | $1,100 | $1,250 | $1,300 | $1,450 | ||||||
Land Capital | $75 | $100 | $75 | $100 | ||||||
Total E&P Capital | $1,175 | $1,350 | $1,375 | $1,550 |
The following is a summary of Antero Resources' 2019 operational, production, pricing and cash expense guidance.
Average Operated Drilling Rigs | 5 | ||||||
Average Operated Completion Crews | 4 | ||||||
Operated Wells Completed | 115 to 125 | ||||||
Operated Wells Drilled | 120 to 130 | ||||||
Production Guidance | |||||||
Net Daily Production (MMcfe/d) | 3,150 – 3,250 | ||||||
Net Daily Natural Gas Production (MMcf/d) | 2,225 – 2,275 | ||||||
Total Net Daily Liquids Production (Bbl/d): | 154,000 – 164,000 | ||||||
Net Daily Oil Production (Bbl/d) | 8,500 – 9,500 | ||||||
Net Daily C3+ NGL Production (Bbl/d) | 97,500 – 102,500 | ||||||
Net Daily Ethane Production (Bbl/d) | 48,000 – 52,000 | ||||||
Realized Pricing Guidance | |||||||
Natural Gas Realized Price vs. NYMEX Henry Hub ($/Mcf) | $0.15 – $0.20 | ||||||
Oil Realized Price vs. WTI Oil ($/Bbl) | ($7.00) – ($8.00) | ||||||
C3+ NGL Realized Price (% of WTI Oil) | 60% – 65% | ||||||
Ethane Realized Price vs. Mont Belvieu ($/Gal) | ($0.05) – ($0.07) |
Consolidated | Stand-alone | ||||||||
Cash Expense Guidance | Low | High | Low | High | |||||
Cash Production Expense ($/Mcfe)(1) | $1.85 | $1.95 | $2.15 | $2.25 | |||||
Marketing Expense, Net of Marketing Revenue ($/Mcfe) | $0.175 | $0.225 | $0.175 | $0.225 | |||||
G&A Expense ($/Mcfe) (2) | $0.125 | $0.175 | $0.10 | $0.14 | |||||
(1) | Includes lease operating expenses, gathering, compression, processing, transportation expenses and production and ad valorem taxes. Stand-alone cash production expense includes 100% of gathering and compression and water fees paid to Antero Midstream that are eliminated on a consolidated basis. |
(2) | Excludes equity-based compensation. |
Natural Gas and NGL Price Realizations and Cash Costs
The Company expects to realize a $0.15 to $0.20 price premium compared to the NYMEX Henry Hub price for its natural gas sales during 2019, driven by an increase in the percentage of sales to both Gulf Coast and Midwest price indices and a reduction in overall sales to regional markets in 2019 compared to 2018. Antero is forecasting an oil price discount to WTI of $7.00 to $8.00 per barrel in 2019. Driven by the Mariner East 2 project, Antero is forecasting an average realized price for C3+ NGLs of 60% to 65% of WTI oil prices in 2019. Antero expects to sell approximately 50% of its C3+ NGL production in 2019 at Marcus Hook, PA at a premium to Mont Belvieu, which compares to an approximate $6.00 per barrel discount to Mont Belvieu received on C3+ production during 2018.
Antero is forecasting an increase in cash production expenses due to an increase in transportation expenses. The increase in transportation expenses is primarily related to Antero's firm commitment on the Mariner East 2 project and is forecasted to be more than offset by the premium pricing at Marcus Hook.
Long-Term Outlook
Depending on the commodity price environment, Antero Resources plans to grow production at a 10% to 15% compound annual growth rate ("CAGR") from 2020 through 2023. Antero has a clear path to this production growth profile due to its Appalachian Basin-leading firm transportation portfolio for natural gas. The Company's activity level and production growth will vary on an annual basis depending on natural gas, oil and NGL price expectations with the objective of maintaining Stand-alone drilling and completion capital spending within Stand-alone Adjusted Operating Cash Flow levels, keeping leverage low while also maximizing the return of capital to shareholders.
Assuming flat $50 per barrel WTI oil prices and $2.85 per MMBtu NYMEX natural gas prices from 2020 through 2023, Antero Resources expects to grow production at the lower end of the production growth range, invest at levels that result in approximate Free Cash Flow neutrality and maintain leverage in the low 2x area declining below 2x leverage in the final two years of the outlook period (defined as Stand-alone Net Debt to Stand-alone Adjusted EBITDAX).
Assuming Wall Street analyst consensus commodity pricing of flat $65 per barrel WTI oil and $3.15 per MMBtu NYMEX natural gas prices from 2020 through 2023, Antero Resources expects to grow production at the high end of its production CAGR range, generate $2.5 to $3.0 billion of Free Cash Flow through 2023 and be in a position to both substantially reduce leverage and return significant capital to shareholders.
Non-GAAP Financial Measures
Stand-alone Adjusted Operating Cash Flow and Free Cash Flow
Free Cash Flow as presented in this release and defined by the Company represents Stand-alone Adjusted Operating Cash Flow, less Stand-alone Drilling and Completion capital, less Land Maintenance Capital. Stand-alone Adjusted Operating Cash Flow represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Stand-alone Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Stand-alone Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Management believes that Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.
There are significant limitations to using Stand-alone Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Stand-alone Adjusted Operating Cash Flow and Free Cash Flow reported by different companies. Stand-alone Adjusted Operating Cash Flow and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
Total Debt, Net Debt and Stand-alone Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Consolidated Net Debt and Stand-alone Net Debt to evaluate its financial position, including its ability to service its debt obligations.
Adjusted EBITDAX and Stand-alone Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-alone Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. The GAAP financial measure nearest to Stand-alone Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-alone Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-alone Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Antero has not included reconciliations of Stand-alone Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Resources' control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero Resources expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, future earnings, future capital spending plans, improved and/or increasing capital efficiency, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, expected drilling and development plans (including the number and lateral length of wells to be drilled, the number of drilling rigs) and future financial position, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements, including statements set forth in the 2019 capital budget. To the extent a forward-looking statement contained in this release speaks as of a period covered by prior guidance, the information in this release is intended to supersede, and investors should not rely on, such prior guidance.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero Resources' control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2017.
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SOURCE Antero Resources Corporation
DENVER, Dec. 18, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that it has monetized a portion of its natural gas hedge position for $357 million. In addition, Antero has repurchased $129 million worth of shares of its common stock quarter-to-date, or 3% of shares outstanding.
Hedge Monetization Highlights:
Share Repurchase Activity:
Fourth Quarter 2018 Update:
Glen Warren, President and CFO, commented, "The monetization and restructuring of a portion of our hedge portfolio allows Antero to further delever, while maintaining upside to the natural gas strip in 2019. Antero was able to capture a portion of the value in its 2019 fixed price swaps. We believe that futures prices do not accurately reflect current low storage levels and strong demand growth fundamentals. This monetization builds upon the delevering process that we started in 2017 with our initial hedge monetization. At that time, Antero had a stand-alone leverage ratio of 3.2x. The monetization will further strengthen our balance sheet as we target a stand-alone leverage profile below 2.2x by year-end 2018."
Mr. Warren continued, "In addition, the sharp increase in natural gas prices this fall and the shift of more of our gas to Midwest markets due to the opening of the ET Rover Sherwood Lateral in November substantially offset the negative impact of lower oil and natural gas liquids ("NGL") prices during the fourth quarter. The repurchase of $129 million of our stock, or 3% of shares outstanding, was primarily funded through the free cash flow we are generating this quarter, delivering on our stated goal of returning the majority of free cash flow to our shareholders. Given our discounted valuation based on our firm value to EBITDAX multiple and NAV metrics, we believe repurchasing shares is an attractive use of capital."
Hedge Monetization Details
Antero monetized a portion of its natural gas hedge portfolio for $235 million in net proceeds via an early settlement of 68% of its April through December 2019 swaps, replacing the monetized volumes with collars. The 1.575 Bcf/d of new collars for the April through December 2019 period have a $2.50 per MMBtu floor and a ceiling ranging from $3.31 to $3.54 per MMBtu. The monetization allows Antero to maintain a low risk profile with a floor of $2.50 per MMBtu during the period, while enabling the Company to participate in the upside to current strip pricing during that period. The Company also reset 70% of its 2020 fixed price swaps from $3.25 per MMBtu to $3.00 per MMBtu for proceeds of $122 million. Proceeds from the monetization were used to repay a portion of borrowings under Antero's revolving credit facility. Total volume hedged remains unchanged, with approximately greater than 70% of the Company's targeted 2019 and 2020 natural gas production hedged. Antero plans for 2019 drilling and completion capital spend to remain within cash flow from operations assuming current strip pricing.
Share Repurchase Activity
Quarter-to-date, Antero has repurchased 9.1 million shares for $129 million, comprising about 3% of shares outstanding. The weighted average repurchase price was $14.10 per share. The previously announced $600 million open market share repurchase program is authorized through the first quarter of 2020, subject to leverage thresholds. Leverage reduction continues to be a priority and Antero is forecasting stand-alone leverage below 2.2x at year-2018. The $600 million program is expected to be funded with cash proceeds from the following:
Fourth Quarter 2018 Update
On November 3, 2018, the ET Rover Pipeline lateral to the Sherwood processing complex in West Virginia entered into service, increasing Antero's access to premium-priced Midwest markets with no additional transport fees. Antero projects that approximately 30% of its natural gas will be sold into the Midwest market during the fourth quarter of 2018, an increase from 16% before the Rover Sherwood Lateral in-service date. In addition to the increased sales into premium-priced Midwest markets, Antero expects to produce approximately 400 MMcf/d of unhedged natural gas volumes during the fourth quarter. The positive impacts from the increased exposure to rising natural gas prices and Midwest regional pricing during the quarter substantially offset the decline in oil and NGL prices.
The following table summarizes Antero's natural gas hedge position as of December 17, 2018, following the hedge monetizations and restructuring:
Period |
Natural Gas MMBtu/d | Average Index price ($/MMBtu) | ||||
1Q 2019: | ||||||
NYMEX Henry Hub Swap - Unchanged | 2,330,000 | $3.62 | ||||
2Q 2019: | ||||||
NYMEX Henry Hub Swap - Unchanged | 755,000 | $3.26 | ||||
NYMEX Henry Hub Call – Short Position - Restructured | 1,575,000 | $3.31 | ||||
NYMEX Henry Hub Put – Long Position - Restructured | 1,575,000 | $2.50 | ||||
2Q 2019 Total | 2,330,000 | ‒ | ||||
3Q 2019: | ||||||
NYMEX Henry Hub Swap - Unchanged | 755,000 | $3.32 | ||||
NYMEX Henry Hub Call – Short Position - Restructured | 1,575,000 | $3.31 | ||||
NYMEX Henry Hub Put – Long Position - Restructured | 1,575,000 | $2.50 | ||||
3Q 2019 Total | 2,330,000 | ‒ | ||||
4Q 2019: | ||||||
NYMEX Henry Hub Swap - Unchanged | 755,000 | $3.45 | ||||
NYMEX Henry Hub Call – Short Position - Restructured | 1,575,000 | $3.54 | ||||
NYMEX Henry Hub Put – Long Position - Restructured | 1,575,000 | $2.50 | ||||
4Q 2019 Total | 2,330,000 | ‒ | ||||
2020 NYMEX Henry Hub Swap - Reset | 1,417,500 | $3.00 | ||||
2021 NYMEX Henry Hub Swap - Unchanged | 710,000 | $3.00 | ||||
2022 NYMEX Henry Hub Swap - Unchanged | 850,000 | $3.00 | ||||
2023 NYMEX Henry Hub Swap - Unchanged | 90,000 | $2.91 |
Presentation
An updated company presentation is expected to be posted to the Company's website today. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Antero is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
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SOURCE Antero Resources Corporation
DENVER, Dec. 10, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced that Paul J. Korus has been appointed to its board of directors (the "Board"), as a Class II director, effective as of December 7, 2018. Mr. Korus is an independent director under the director independence standards set forth in the rules and regulations of the Securities and Exchange Commission and the applicable listing standards of the New York Stock Exchange.
Mr. Korus was the Senior Vice President and Chief Financial Officer of Cimarex Energy from September 2002 until his retirement in 2015, and held the same positions with its predecessor, Key Production Company, from 1999 through 2002. Mr. Korus was a senior research analyst with Petrie Parkman & Co from 1995 through 1999. He also held positions in corporate planning and investor relations with Apache Corporation for thirteen years from 1982 to 1995. Mr. Korus graduated with a Bachelor of Science in Economics and a Master of Science in Accounting from the University of North Dakota.
Paul M. Rady, Chairman and CEO of Antero commented, "We are very excited to add Paul to the Board of Antero Resources. Paul's extensive background in the oil and gas industry and his strong financial expertise will be a valuable asset to Antero and our shareholders. Adding another independent director to the Board with Paul's credentials further strengthens our commitment to good corporate governance at Antero."
"I am thrilled to join the Board of Antero, a leader in Appalachia with a forward-thinking management team and a bright future ahead. Antero's leadership, acreage footprint and integrated business strategy present a tremendous opportunity. I look forward to representing the shareholders and working with the Board to oversee the execution of the company's business plan," said Korus.
Mr. Korus' appointment increases the size of the Board to ten directors, eight of whom are independent directors under the director independence standards of the NYSE and five of whom are independent by audit committee standards. Mr. Korus will be a member of the Board's Audit Committee.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as Antero's ability to execute its business plan, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Oct. 31, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its third quarter 2018 financial and operational results. The relevant consolidated and consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2018, which has been filed with the Securities and Exchange Commission ("SEC"). The relevant Stand-Alone financial statements are also included in Antero's Form 10-Q within the Parent column of the guarantor footnote (Note 16).
Highlights Include:
Commenting on the quarter, Paul Rady, Chairman and CEO said, "We completed more wells in the third quarter than any quarter in Antero's history with 73 wells turned to sales, a testament to the Company's outstanding operational team. This level of activity could not have been achieved without the excellent coordination between our upstream and midstream businesses. Due to the efficiency gains realized during the first nine months of 2018, which accelerated the completion pace and reduced completion crew needs, capital spending is expected to decline substantially during the fourth quarter of 2018 as we are currently operating only five drilling rigs and three completion crews. Having recently surpassed the 3 Bcfe/d of production milestone for the month of October, the fourth quarter is expected to be an important inflection point for the Company as we expect to deliver attractive cash flow from operations growth combined with a reduction in capital spending."
Mr. Rady further commented, "In addition to the operational success, we recently announced the simplification of our midstream structure. It is an immediately accretive transaction to both Antero Midstream and AMGP that was a win-win-win across the Antero family. Importantly, our organic growth strategy and integration with Antero Midstream remains unchanged. We believe the new midstream business structure will be better aligned with Antero Resources shareholder interests and allow us to accelerate plans to return capital to shareholders from the combination of transaction proceeds and expected stand-alone free cash flow generation."
Recent Developments
$600 Million Share Repurchase Program
As announced on October 9, 2018, Antero's board approved a share repurchase program of up to $600 million, to be executed over the next 12 to 18 months. The open market share repurchase program is expected to commence during the fourth quarter of 2018, with the 18-month window providing the company flexibility to be opportunistic regarding the share repurchase price. Leverage targets remain a top priority for Antero, with a 2.25x Stand-Alone Net Debt to Non-GAAP Stand-Alone Adjusted EBITDAX target for year-end 2018 and at or below 2.0x for year-end 2019 expected, including the share repurchase program. This program is expected to be fully funded with cash proceeds from the following:
Antero Midstream Simplification Transaction
On October 9, 2018, Antero Midstream Partners LP ("Antero Midstream") and Antero Midstream GP LP ("AMGP") announced that they entered into a definitive agreement for AMGP to acquire all outstanding Antero Midstream common units in a stock and cash transaction. The transaction results in the elimination of the outstanding incentive distribution rights ("IDRs") and simplifies the structure of the midstream business into one publicly-traded corporation ("New AM"). New AM will be a corporation for both tax and governance purposes with a majority of independent directors upon closing. Under the terms of the agreement, Antero Resources will be entitled to receive a combination of $3.00 in cash and 1.6023 shares of New AM stock for each AM unit owned, resulting in aggregate consideration valued at $30.43 per AM unit, based on the October 8, 2018 closing price. AM public unitholders will be entitled to $3.145 in cash and 1.635 shares of New AM stock for each AM unit owned. For further details and transaction merits, please visit the investor relations section of Antero Resources, Antero Midstream and AMGP websites, which includes press releases and accompanying presentations relating to the transaction.
Third Quarter 2018 Financial Results
As of September 30, 2018, Antero Resources owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Pro forma for the previously announced midstream simplification transaction which is expected to close in the first quarter of 2019, Antero Resources will own a 31% common stock interest in Antero Midstream assuming Antero Resources receives its proportionate share of cash consideration in the transaction. Antero Midstream's results will continue to be consolidated within Antero Resources' results.
For the three months ended September 30, 2018, Antero reported a GAAP net loss of $154 million, or $0.49 per diluted share, compared to a net loss of $135 million, or $0.43 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," Non-GAAP Adjusted Net Income was $77 million, or $0.24 per diluted share, compared to a $9 million, or $0.03 per diluted share, in the prior year period. Non- GAAP Stand-Alone Adjusted Net Income was $73 million, or $0.23 per diluted share, compared to $5 million, or $0.01 per diluted share, in the prior year period. Non- GAAP Adjusted EBITDAX was $498 million, a 48% increase compared to $336 million in the prior year period, and Non- GAAP Stand-Alone Adjusted EBITDAX was $419 million, a 48% increase compared to $284 million in the prior year period. Third quarter 2018 results include settled marketing derivative losses of $16 million.
The following table details the components of average net production and average realized prices for the three months ended September 30, 2018:
Three Months Ended September 30, 2018 | ||||||||||||||||
Natural Gas | Oil (Bbl/d) | C3+ NGLs | Ethane (Bbl/d) | Combined | ||||||||||||
Average Net Production | 1,942 | 10,632 | 79,819 | 38,901 | 2,718 | |||||||||||
Average Realized Prices | Gas ($/Mcf) | Oil ($/Bbl) | C3+ NGLs | Ethane ($/Bbl) | Combined Gas | |||||||||||
Average realized prices before settled derivatives | $ | 2.95 | $ | 61.06 | $ | 38.41 | $ | 15.70 | $ | 3.70 | ||||||
Settled commodity derivatives | 0.56 | (7.06) | (3.09) | — | 0.28 | |||||||||||
Average realized prices after settled derivatives | $ | 3.51 | $ | 54.00 | $ | 35.32 | $ | 15.70 | $ | 3.98 | ||||||
NYMEX average price | $ | 2.90 | $ | 69.76 | $ | 2.90 | ||||||||||
Premium / (Differential) to NYMEX | $ | 0.61 | $ | (15.76) | $ | 1.08 |
Net daily natural gas equivalent production in the third quarter averaged 2,718 MMcfe/d, including 129,352 Bbl/d of liquids (29% of production), an increase of 17% compared to the prior year period and an 8% increase sequentially. As described in more detail below, Antero experienced production curtailments during the latter part of the second quarter and into the third quarter due to oil hauling constraints. The Company estimates that the curtailment negatively impacted production by 86 MMcfe/d during the third quarter. Natural gas production averaged 1,942 MMcf/d, oil production averaged 10,632 Bbl/d, C3+ NGLs production averaged 79,819 Bbl/d, and recovered ethane production averaged 38,901 Bbl/d. Total liquids production grew 15% compared to the prior year period and 14% sequentially. Liquids revenue represented approximately 43% of total product revenue before hedges, an increase from 38% of total product revenue in the prior year period. This increase reflects the continued effect of Antero's development plan on liquids-rich Marcellus acreage as well as the substantial increase in liquids pricing year-over-year. Furthermore, Antero exited the third quarter of 2018 with strong momentum driven by 73 wells brought to sales primarily on liquids-rich Marcellus acreage.
Antero experienced production curtailments during the latter part of the second quarter and into the third quarter due to oil hauling constraints. The Company estimates that the curtailments negatively impacted production by an average of 86 MMcfe/d during the third quarter. Production constraints were alleviated in September, as trucking capacity sufficiently met oil production and worked down an oil inventory surplus by the end of the period. The Company does not anticipate further trucking constraints, as fourth quarter oil inventory levels have largely normalized and trucking capacity now equals oil production.
Antero's average realized natural gas price before hedging was $2.95 per Mcf, a $0.05 per Mcf premium to the average NYMEX Henry Hub price during the period, representing a 9% increase versus the prior year period. Including hedges, Antero's average realized natural gas price was $3.51 per Mcf, a $0.61 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $101 million, or $0.56 per Mcf. Antero's average realized C3+ NGL price before hedging was $38.41 per barrel, or 55% of the average NYMEX WTI oil price, representing a 33% increase versus the prior year period. Including hedges, Antero's average realized C3+ NGL price was $35.32 per barrel, reflecting the realization of a cash settled C3+ hedge loss of $23 million, or $3.09 per barrel.
Antero's average realized oil price before hedging was $61.06 per barrel, a $8.70 negative differential to the average NYMEX WTI price and a 44% increase versus the prior year period. Including hedges, the average realized oil price was $54.00 per barrel, reflecting the realization of a cash settled WTI crude oil loss of $7 million, or $7.06 per barrel. The average realized ethane price was $0.37 per gallon, or $15.70 per barrel, a 76% increase compared to $0.21 per gallon, or $8.53 per barrel, in the prior year period.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.70 per Mcfe, representing a 19% increase compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.98 per Mcfe, a 17% increase from the prior year period, primarily driven by higher realized liquids prices and hedge gains. Net cash settled hedge gains on all products were $71 million, or $0.28 per Mcfe.
Total revenue in the third quarter was $1.1 billion, compared to $648 million in the prior year period. Revenue included a $14 million non-cash loss on unsettled commodity derivatives and a $16 million non-cash gain on unsettled marketing derivatives, while the prior year included an $877 million non-cash loss on unsettled commodity derivatives primarily driven by a $750 million hedge monetization. Non-GAAP revenue excluding gains and losses on unsettled derivatives was $1.1 billion, a 39% increase versus the prior year period. Please see "Non-GAAP Financial Measures" for a description of Revenue Excluding Unrealized Derivative Gains (Losses).
The following table presents a calculation of Non-GAAP Stand-Alone Adjusted EBITDAX margin and Non-GAAP Adjusted EBITDAX margin, in each case on a per Mcfe basis with and without the effect of cash receipts for settled commodity derivatives, and reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Consolidated and Stand-Alone EBITDAX margin represents adjusted EBITDAX divided by production, a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations (both on a consolidated and Stand-Alone basis) from period to period by removing the effect of its capital structure from its operating structure.
Stand-Alone | Consolidated | ||||||||||||
Three months ended September 30, | Three months ended September 30, | ||||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||||
Adjusted EBITDAX margin ($ per Mcfe): | |||||||||||||
Realized price before cash receipts for settled derivatives | $ | 3.10 | 3.70 | $ | 3.10 | 3.70 | |||||||
Gathering, compression, and water handling and treatment revenues | N/A | N/A | 0.01 | 0.02 | |||||||||
Distributions from unconsolidated affiliates | N/A | N/A | 0.02 | 0.05 | |||||||||
Distributions from Antero Midstream | 0.15 | 0.18 | N/A | N/A | |||||||||
Gathering, compression, processing and transportation costs | (1.73) | (1.77) | (1.32) | (1.31) | |||||||||
Lease operating expense | (0.11) | (0.14) | (0.11) | (0.15) | |||||||||
Marketing, net (1) | (0.13) | (0.31) | (0.13) | (0.31) | |||||||||
Production and ad valorem taxes | (0.10) | (0.12) | (0.11) | (0.12) | |||||||||
General and administrative (excluding equity-based compensation) | (0.14) | (0.14) | (0.17) | (0.17) | |||||||||
Adjusted EBITDAX margin before settled commodity derivatives | 1.04 | 1.40 | 1.29 | 1.71 | |||||||||
Cash receipts for settled commodity derivatives | 0.29 | 0.28 | 0.29 | 0.28 | |||||||||
Adjusted EBITDAX margin ($ per Mcfe): | $ | 1.33 | 1.68 | $ | 1.58 | 1.99 |
(1)Includes cash payments for settled marketing derivative losses of $0.06 per Mcfe in 2018. Includes marketing revenues of $89.6 million and marketing expense of $151.8 million. |
Stand-Alone per unit distributions from Antero Midstream contributed $0.18 per Mcfe compared to $0.15 per Mcfe in the prior year period.
Stand-Alone per unit cash production expense, which equals the sum of the GAAP measures lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes, was $2.03 per Mcfe, a 5% increase compared to $1.94 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.77 per Mcfe for gathering, compression, processing and transportation costs, $0.14 per Mcfe for lease operating costs, and $0.12 per Mcfe for production and ad valorem taxes. Lease operating expenses increased in the third quarter due to an increase in produced water from newer wells that were completed with higher water intensity advanced completions.
Stand-Alone per unit net marketing expense was $0.31 per Mcfe compared to $0.13 per Mcfe reported in the prior year period. Net marketing expense increased due to higher unutilized excess capacity related to the Rover mainline that was placed in service in late 2017 and the inability to utilize the Rover Sherwood Lateral which is still pending FERC approval to be placed in service. Net marketing expense included a $0.06 per Mcfe loss for settled marketing derivatives related to contracts that had resulted in realized gains in the first quarter of 2018. See note 11 to the condensed consolidated financial statements in Antero's Form 10-Q for more information on these contracts.
Stand-Alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.14 per Mcfe, consistent with the prior year period.
Realized price before cash receipts for settled derivatives was $3.70 per Mcfe, a 19% increase from the prior year period, primarily due to the improving natural gas liquids prices. Stand-Alone Adjusted EBITDAX margins before commodity derivative were $1.40 per Mcfe, a 35% increase from the prior year period, primarily due to improving NGL and oil prices. Stand-Alone Adjusted EBITDAX margin after commodity derivatives was $1.68 per Mcfe, a 26% increase from the prior year period. Consolidated Adjusted EBITDAX margin was $1.99 per Mcfe, compared to $1.58 per Mcfe in the prior year period.
Stand-Alone Adjusted EBITDAX was $419 million for the third quarter of 2018, a 48% increase compared to $284 million in the prior year period. The increase was primarily driven by increased production and pricing. Stand-Alone Adjusted EBITDAX in the fourth quarter of 2018 is expected to increase to $500 to $525 million on the strength of a substantial increase in production and continued favorable liquids pricing. Consolidated Adjusted EBITDAX was $498 million, compared to $336 million in the prior year period, a 48% increase over the prior year period.
Stand-Alone net cash provided by operating activities was $367 million for the period. Stand-Alone Adjusted Operating Cash Flow was $362 million, a 63% decrease from the prior year period, as prior year period cash flow included a $750 million hedge monetization. Excluding the hedge monetization, Stand-Alone Adjusted Operating Cash Flow increased 63% over the prior year period. Stand-Alone Adjusted Operating Cash Flow in the fourth quarter of 2018 is expected to increase to $425 to $475 million, a sequential increase of nearly 25% at the midpoint.
Consolidated net cash provided by operating activities was $421 million for the period. Consolidated Adjusted Operating Cash Flow was $424 million during the third quarter, a 58% decrease compared to the prior year period. Excluding the $750 million hedge monetization, consolidated Adjusted Operating Cash Flow increased by 60% over the prior year period.
Operating Update
Third Quarter 2018
Marcellus Shale — Antero placed 58 horizontal Marcellus wells to sales during the third quarter of 2018 with an average lateral length of 9,100 feet and an average 30-day rate per well of 18.3 MMcfe/day on choke. The 30-day average rate per well included 1,073 Bbl/d of liquids, representing oil, C3+ NGLs and 25% ethane recovery.
Two Marcellus pads and one westerly well are highlighted below. The results are particularly encouraging given that the wells were curtailed at various times due to trucking constraints during the third quarter.
Completion efficiencies continued to improve during the third quarter, increasing from 5.0 completion stages per day in the second quarter to 5.5 stages per day in the third quarter. During the month of September, Antero averaged 6.0 stages per day. These efficiency gains allowed Antero to release three completion crews during the quarter, which will result in an average of four crews during the second half of 2018, compared to six crews in the first half of 2018. Antero is currently running five drilling rigs in the Marcellus Shale. The Company expects to place a total of 27 wells to sales in the Marcellus during the fourth quarter with an average lateral length of approximately 9,500'. The significant reduction in activity compared to the previous quarters in 2018, is expected to substantially reduce capital spending during the fourth quarter of 2018 compared to the third quarter.
Ohio Utica Shale — Antero placed 15 horizontal Ohio Utica wells to sales during the third quarter of 2018 with an average lateral length of approximately 10,400 feet and an average 30-day rate per well of 17.7 MMcfe/d on choke. The Company does not plan to operate any drilling rigs or completion crews in the Ohio Utica Shale during the fourth quarter of 2018 as the development plan continues to focus on liquids-rich locations in the Marcellus.
President and CFO, Glen Warren, commented, "The operational achievements realized through the first nine months of 2018 provide Antero with significant momentum as we exit the year. The robust quarterly activity, combined with the strength in liquids pricing, positions Antero for an exciting inflection point of generating strong operating cash flow with capital discipline in the fourth quarter of 2018. The increase in liquids pricing and the 19% year-over-year increase in realized gas equivalent product price for Antero illustrates Antero's pricing leverage despite its fully hedged natural gas production. Antero's liquids exposure is underscored by our position as one of the largest NGL producers in the U.S."
Mr. Warren continued, "With the Board's recent approval of a $600 million share repurchase program, Antero is well-positioned to deliver on its stated goal of returning capital to shareholders, while simultaneously reducing leverage. Combined with expected proceeds of approximately $300 million from the closing of the simplification transaction, we plan to return the majority of forecast free cash flow in the fourth quarter of 2018 and in 2019 to our shareholders."
Third Quarter 2018 Capital Investment
Antero invested $373 million on drilling and completion capital expenditures for the three months ended September 30, 2018. In addition, the Company invested $43 million for land, $131 million for gathering and compression systems and $19 million for water infrastructure projects. Antero's Stand-Alone drilling and completion capital expenditures for the three months ended September 30, 2018, were $441 million. In the fourth quarter of 2018, Antero expects consolidated drilling and completion capital expenditures to be in the range of $200 to $250 million. Despite a 50% reduction in completion crews from six to three, record completion efficiencies continued to outpace expectations, shifting forward completion stages originally scheduled for early 2019 into late 2018. Antero made the decision to pull forward its McKim Pad to optimize the efficiency of its completion crews, as well as take advantage of the favorable liquids pricing environment. This 9-well pad is anticipated to have capital expenditures of $92 million, average 1,260 BTU and is scheduled to be turned to sales in January of 2019. As a result of accelerating the McKim Pad, for the full year 2018, Antero expects consolidated drilling and completion capital expenditures to be in the range of $1.35 – $1.4 billion, a modest increase of $50 to $100 million from previous expectations.
Balance Sheet and Liquidity
As of September 30, 2018, Antero's total debt was $5.4 billion and Non-GAAP Stand-Alone net debt was $4.0 billion, of which $547 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility were $2.5 billion and the borrowing base is $4.5 billion. After deducting letters of credit outstanding, the Company had $1.5 billion in available Stand-Alone liquidity as of September 30, 2018. As of September 30, 2018, Antero's Stand-Alone Net Debt to trailing twelve months Stand-Alone Adjusted EBITDAX ratio was 2.5x.
Commodity Derivative Positions
Antero's estimated natural gas production for the fourth quarter of 2018 at the midpoint of guidance is approximately fully hedged at an average index price of $3.53 per MMBtu. The Company's target natural gas production for 2019 is fully hedged at an average index price of $3.50 per MMBtu. In total, Antero has hedged 2.2 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2018, through December 31, 2023, at an average index price of $3.30 per MMBtu. As of September 30, 2018, the Company's estimated fair value of commodity derivative instruments was $1.2 billion.
The following table summarizes Antero's hedge position as of September 30, 2018:
Period | Natural Gas MMBtu/d | Average Index price ($/MMBtu) | Liquids Bbl/d | Average Index price | ||
4Q 2018: | ||||||
NYMEX Henry Hub | 2,002,500 | $3.53 | — | — | ||
Propane MB ($/Gal) | — | — | 26,000 | $0.77 | ||
NYMEX WTI ($/Bbl) | — | — | 6,000 | $56.99 | ||
4Q 18 Total(1) | 2,002,500 | $3.53 | 32,000 | N/A (1) | ||
2019: | ||||||
NYMEX Henry Hub | 2,330,000 | $3.50 | — | — | ||
2020: | ||||||
NYMEX Henry Hub | 1,417,500 | $3.25 | — | — | ||
2021: | ||||||
NYMEX Henry Hub | 710,000 | $3.00 | — | — | ||
2022: | ||||||
NYMEX Henry Hub | 850,000 | $3.00 | — | — | ||
2023: | ||||||
NYMEX Henry Hub | 90,000 | $2.91 | — | — |
(1) | Average index price is not applicable as 2018 liquids hedges include propane and oil hedges. |
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com. A summary of the results are provided below:
Three Months Ended | ||||||
September, | ||||||
Average Daily Volumes: | 2017 | 2018 | % Change | |||
Low Pressure Gathering (MMcf/d) | 1,586 | 2,166 | 37% | |||
Compression (MMcf/d) | 1,207 | 1,756 | 45% | |||
High Pressure Gathering (MMcf/d) | 1,918 | 2,173 | 13% | |||
Fresh Water Delivery (MBbl/d) | 142 | 195 | 37% | |||
Wastewater Treatment (MBbl/d) | — | 12 | * | |||
Gross Joint Venture Processing (MMcf/d) | 368 | 606 | 65% | |||
Gross Joint Venture Fractionation (MBbl/d) | 6,431 | 17,365 | 170% |
Net income for the third quarter of 2018 was $120 million, a 48% increase compared to the prior year quarter. Net income per limited partner unit was $0.44 per unit, a 33% increase compared to the prior year quarter. Adjusted EBITDA was $186 million, a 46% increase compared to the prior year quarter. Distributable Cash Flow was $157 million, a 52% increase over the prior year quarter, resulting in a DCF coverage ratio of 1.3x. For a description of Antero Midstream's Adjusted EBITDA and Distributable Cash Flow, and reconciliations to their nearest GAAP measures, please read "Non-GAAP Financial Measures."
Conference Call
A conference call is scheduled on Thursday, November 1, 2018 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, November 8, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10123136.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, November 8, 2018 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the November 1, 2018 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Guidance
Included in this release are updated 2018 guidance projections. Any 2018 projections not discussed in this release are unchanged from previously stated guidance.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue Excluding Unrealized Derivative (Gains) Losses as set forth in this release represents total revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue Excluding Unrealized Derivative (Gains) Losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance. The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses:
Three months ended | Nine months ended | ||||||||||
September 30, | September 30, | ||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||
Total revenue | $ | 647,880 | $ | 1,076,533 | $ | 2,633,848 | $ | 3,093,978 | |||
Commodity derivative fair value (gains) losses | 65,957 | (57,020) | (458,459) | (134,793) | |||||||
Marketing derivative fair value (gains) losses | — | 43 | — | (94,081) | |||||||
Gains on settled commodity derivatives | 61,479 | 71,144 | 137,392 | 268,369 | |||||||
Gains (losses) on settled marketing derivatives | — | (16,060) | — | 78,098 | |||||||
Revenue Excluding Unrealized Derivative (Gains) Losses | $ | 775,316 | $ | 1,074,640 | $ | 2,312,781 | $ | 3,211,571 |
Adjusted Net Income & Stand-Alone Adjusted Net Income
Adjusted Net Income as set forth in this release represents net income, adjusted for certain items. Stand-Alone Adjusted Net Income as presented in this release represents net income that will be reported in the Parent column of Antero's guarantor footnote to its financial statements, adjusted for certain items. Antero believes that Adjusted Net Income and adjusted net income per share is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted Net Income and Stand-Alone Adjusted Net Income are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following table reconciles net (loss) before income taxes to Adjusted Net Income and Stand-Alone net (loss) to Stand-Alone Adjusted Net Income (in thousands):
Stand-Alone Three months ended | Consolidated Three months ended | ||||||||||
September 30, | September 30, | ||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||
Net Income (loss) attributable to Antero Resources Corp | $ | (135,063) | (154,419) | $ | (135,063) | $ | (154,419) | ||||
Income tax expense (benefit) | (45,078) | 18,953 | (45,078) | 18,953 | |||||||
Commodity derivative fair value (gains) losses | 65,957 | (57,020) | 65,957 | (57,020) | |||||||
Gains on settled commodity derivatives | 61,479 | 71,144 | 61,479 | 71,144 | |||||||
Marketing derivative fair value losses | — | 43 | — | 43 | |||||||
Losses on settled marketing derivatives | — | (16,060) | — | (16,060) | |||||||
Impairment of unproved properties | 41,000 | 221,095 | 41,000 | 221,095 | |||||||
Impairment of gathering systems and facilities | — | — | — | 1,157 | |||||||
Equity-based compensation | 19,248 | 11,674 | 26,447 | 16,202 | |||||||
Income before income taxes, as adjusted | $ | 7,543 | $ | 95,410 | $ | 14,742 | $ | 101,095 | |||
Income tax, at the blended statutory rate (1) | (2,854) | (22,603) | (5,578) | (23,950) | |||||||
Adjusted Net Income | $ | 4,689 | $ | 72,807 | $ | 9,164 | $ | 77,145 | |||
Fully Diluted Shares Outstanding | 315,463 | 317,082 | 315,463 | 317,082 | |||||||
Per Diluted Share Amounts Net income (loss) per diluted share attributable to Antero Resources Corp | $ | (0.43) | $ | (0.49) | $ | (0.43) | $ | (0.49) | |||
Income tax expense (benefit) | (0.14) | 0.06 | (0.14) | 0.06 | |||||||
Commodity derivative fair value (gains) losses | 0.21 | (0.18) | 0.21 | (0.18) | |||||||
Gains on settled commodity derivatives | 0.19 | 0.22 | 0.19 | 0.22 | |||||||
Marketing derivative fair value losses | — | 0.00 | — | 0.00 | |||||||
Losses on settled marketing derivatives | — | (0.05) | — | (0.05) | |||||||
Impairment of unproved properties | 0.13 | 0.70 | 0.13 | 0.70 | |||||||
Impairment of gathering systems and facilities | — | — | — | 0.00 | |||||||
Equity-based compensation | 0.06 | 0.04 | 0.08 | 0.05 | |||||||
Income before income taxes, as adjusted | 0.02 | 0.30 | 0.05 | 0.32 | |||||||
Income tax expense, at the blended statutory rate (1) | (0.01) | (0.07) | (0.02) | (0.08) | |||||||
Adjusted Net Income Per Share | $ | 0.01 | $ | 0.23 | $ | 0.03 | $ | 0.24 |
(1) Deferred taxes to be approximately 38% for 2017 and 24% for 2018. |
Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow and Free Cash Flow
Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items. Stand-Alone Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Free Cash Flow as defined by the Company represents Stand-Alone Adjusted Operating Cash Flow, less Stand-Alone Drilling and Completion capital, less Land Maintenance Capital.
Management believes that Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow and Free Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-Alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.
There are significant limitations to using Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow and Free Cash Flow reported by different companies. Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Operating Cash Flow and Free Cash Flow are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to Adjusted Operating Cash Flow as used in this release (in thousands):
Stand-Alone | Consolidated | ||||||||||
Three months ended | Three months ended | ||||||||||
September 30, | September 30, | ||||||||||
2017 | 2018 | 2017 | 2018 | ||||||||
Net cash provided by operating activities | $ | 1,009,906 | 367,012 | $ | 1,045,222 | 421,458 | |||||
Net change in working capital | (38,129) | (5,505) | (29,899) | 2,053 | |||||||
Adjusted Operating Cash Flow | $ | 971,777 | 361,507 | $ | 1,015,323 | 423,511 |
Antero has not included a reconciliation of fourth quarter 2018 Stand-Alone Adjusted EBITDAX to their nearest GAAP financial measures for the fourth quarter of 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero is able to forecast the following reconciling items for the fourth quarter of 2018 between Stand-alone Adjusted EBITDAX to net income from continuing operations including noncontrolling interest:
(in thousands) | Stand-alone | ||||
Low | High | ||||
Interest expense | $50,000 | $60,000 | |||
Depreciation, depletion, amortization, and accretion expense | 210,000 | 230,000 | |||
Exploration expense | 500 | 1,000 | |||
Equity-based compensation expense | 11,000 | 13,000 | |||
Distributions from limited partner interest in Antero Midstream | 40,000 | 45,000 |
Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets, for the fourth quarter of 2018.
Antero has not included reconciliations of Stand-alone Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for the fourth quarter of 2018 because it would be impractical to forecast changes in current assets and liabilities.
Total Debt, Net Debt and Stand-Alone Net Debt
Net Debt is calculated as total debt less cash and cash equivalents. Management uses Consolidated Net Debt and Stand-Alone Net Debt to evaluate its financial position, including its ability to service its debt obligations.
The following table reconciles consolidated total debt to Consolidated Net Debt and Stand-Alone Net Debt as used in this release (in thousands):
December 31, | September 30, | ||||
2017 | 2018 | ||||
AR bank credit facility | $ | 185,000 | 547,000 | ||
AM bank credit facility | 555,000 | 875,000 | |||
5.375% AR senior notes due 2021 | 1,000,000 | 1,000,000 | |||
5.125% AR senior notes due 2022 | 1,100,000 | 1,100,000 | |||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | |||
5.375% AM senior notes due 2024 | 650,000 | 650,000 | |||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | |||
Net unamortized premium | 1,520 | 1,312 | |||
Net unamortized debt issuance costs | (41,430) | (36,308) | |||
Consolidated total debt | $ | 4,800,090 | 5,487,004 | ||
Less: AR cash and cash equivalents | 20,078 | — | |||
Less: AM cash and cash equivalents | 8,363 | — | |||
Consolidated Net Debt | $ | 4,771,649 | 5,487,004 | ||
Less: Antero Midstream debt net of cash and unamortized premium and debt issuance costs | $ | 1,187,637 | 1,516,854 | ||
Stand-Alone Net Debt | $ | 3,584,012 | 3,970,150 |
Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-Alone Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. The GAAP financial measure nearest to Stand-Alone Adjusted EBITDAX is Stand-Alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Stand-Alone | Consolidated | |||||||||||
Three months ended September 30, | Three months ended September 30, | |||||||||||
(in thousands) | 2017 | 2018 | 2017 | 2018 | ||||||||
Net (loss) attributable to Antero Resources Corporation | $ | (135,063) | (154,419) | $ | (135,063) | (154,419) | ||||||
Net Income attributable to noncontrolling interest | — | — | 45,063 | 76,447 | ||||||||
Commodity derivative fair value (gains) losses | 65,957 | (57,020) | 65,957 | (57,020) | ||||||||
Gains on settled commodity derivatives | 61,479 | 71,144 | 61,479 | 71,144 | ||||||||
Marketing derivative fair value losses | — | 43 | — | 43 | ||||||||
Losses on settled marketing derivatives | — | (16,060) | — | (16,060) | ||||||||
Interest expense | 60,906 | 57,633 | 70,059 | 74,528 | ||||||||
Income tax expense (benefit) | (45,078) | 18,953 | (45,078) | 18,953 | ||||||||
Depletion, depreciation, amortization, and accretion | 177,070 | 205,408 | 207,626 | 243,897 | ||||||||
Impairment of unproved properties | 41,000 | 221,095 | 41,000 | 221,095 | ||||||||
Impairment of gathering systems and facilities | — | — | — | 1,157 | ||||||||
Exploration expense | 1,599 | 666 | 1,599 | 666 | ||||||||
Gain on change in fair value of contingent acquisition consideration | (2,556) | (4,020) | — | — | ||||||||
Equity-based compensation expense | 19,248 | 11,674 | 26,447 | 16,202 | ||||||||
Equity in earnings of unconsolidated affiliates | — | — | (7,033) | (10,706) | ||||||||
Distributions from unconsolidated affiliates | — | — | 4,300 | 11,765 | ||||||||
Equity in (earnings) loss of Antero Midstream Partners LP | 4,874 | 23,363 | — | — | ||||||||
Distributions from Antero Midstream Partners LP | 34,839 | 41,031 | — | — | ||||||||
Adjusted EBITDAX | 284,275 | 419,491 | 336,356 | 497,692 | ||||||||
Interest expense | (60,906) | (57,633) | (70,059) | (74,528) | ||||||||
Exploration expense | (1,599) | (666) | (1,599) | (666) | ||||||||
Changes in current assets and liabilities | 38,129 | 5,505 | 29,899 | (2,053) | ||||||||
Proceeds from derivative monetizations | 749,906 | — | 749,906 | — | ||||||||
Other non-cash items | 101 | 315 | 719 | 1,013 | ||||||||
Net cash provided by operating activities | $ | 1,009,906 | 367,012 | $ | 1,045,222 | 421,458 | ||||||
Adjusted EBITDAX | $ | 284,275 | 419,491 | $ | 336,356 | 497,692 | ||||||
Production (MMcfe) | 213,159 | 250,046 | 213,159 | 250,046 | ||||||||
Adjusted EBITDAX margin per Mcfe | $ | 1.33 | 1.68 | $ | 1.58 | 1.99 |
The following table reconciles Antero's Stand-Alone net income to Adjusted EBITDAX for the twelve months ended September 30, 2018, as used in this release (in thousands):
Stand-Alone | ||||||
Twelve months ended September 30, | ||||||
(in thousands) | 2018 | |||||
Net income attributable to Antero Resources Corporation | $ | 210,898 | ||||
Commodity derivative fair value gains | (334,617) | |||||
Gains on settled commodity derivatives | 344,917 | |||||
Marketing derivative fair value gains | (72,687) | |||||
Gains on settled marketing derivatives | 78,098 | |||||
Interest expense | 219,206 | |||||
Loss on early extinguishment of debt | 1,205 | |||||
Income tax benefit | (397,638) | |||||
Depletion, depreciation, amortization, and accretion | 787,598 | |||||
Impairment of unproved properties | 482,568 | |||||
Impairment of gathering systems and facilities | 4,470 | |||||
Exploration expense | 7,050 | |||||
Gain on change in fair value of contingent acquisition consideration | (15,645) | |||||
Equity-based compensation expense | 57,496 | |||||
Equity in (earnings) loss of Antero Midstream | 92,545 | |||||
Distributions from Antero Midstream | 149,292 | |||||
Adjusted EBITDAX | $ | 1,614,756 |
Antero Midstream Adjusted EBITDA & Distributable Cash Flow
Antero Midstream views Adjusted EBITDA as an important indicator of its performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, gain on sale of assets, depreciation expense, impairment expense, accretion, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are Non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The Non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Three Months Ended September 30, | |||||
2017 | 2018 | ||||
Net income | $ | 80,893 | 119,764 | ||
Interest expense | 9,311 | 16,988 | |||
Impairment of property and equipment expense | — | 1,157 | |||
Depreciation expense | 30,556 | 38,456 | |||
Accretion of contingent acquisition consideration | 2,556 | 4,020 | |||
Accretion of asset retirement obligations | — | 33 | |||
Equity-based compensation | 7,199 | 4,528 | |||
Equity in earnings of unconsolidated affiliates | (7,033) | (10,706) | |||
Distributions from unconsolidated affiliates | 4,300 | 11,765 | |||
Adjusted EBITDA | 127,782 | 186,005 | |||
Interest paid | (20,554) | (24,958) | |||
Decrease in cash reserved for bond interest (1) | 8,831 | 8,734 | |||
Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards (2) | (1,500) | (1,500) | |||
Maintenance capital expenditures (3) | (10,771) | (10,964) | |||
Distributable Cash Flow | $ | 103,788 | 157,317 | ||
Distributions Declared to Antero Midstream Holders | |||||
Limited Partners | $ | 63,454 | 82,302 | ||
Incentive distribution rights | 19,067 | 37,815 | |||
Total Aggregate Distributions | $ | 82,521 | 120,117 | ||
DCF coverage ratio | 1.3x | 1.3x |
(1) | Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. |
(2) | Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter. |
(3) | Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding the expected sources of funding and timing for completion of the share repurchase program if at all, statements regarding the simplification transaction, including the expected consideration to be received in connection with the closing of the simplification transaction, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Stand-Alone Adjusted EBITDAX, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, leverage targets, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, the expected timing and likelihood of completion of the simplification transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
No Offer or Solicitation
This communication relates to a proposed business combination transaction between Antero Midstream and AMGP. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Additional Information And Where To Find It
In connection with the transaction, AMGP will file with the U.S. Securities and Exchange Commission ("SEC") a registration statement on Form S-4, that will include a joint proxy statement of Antero Midstream and AMGP and a prospectus of AMGP. The transaction will be submitted to Antero Midstream unitholders and AMGP shareholders for their consideration. Antero Midstream and AMGP may also file other documents with the SEC regarding the transaction. The definitive joint proxy statement/prospectus will be sent to the shareholders of AMGP and unitholders of Antero Midstream. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that AMGP or Antero Midstream may file with the SEC or send to shareholders of AMGP or unitholders of Antero Midstream in connection with the transaction. INVESTORS AND SECURITY HOLDERS OF ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or Antero Midstream through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Antero Midstream will be made available free of charge on Antero Midstream's website at http://investors.anteromidstream.com/investor-relations/AM, under the heading "SEC Filings," or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310.
Participants In The Solicitation
Antero, AMGP, Antero Midstream and the directors and executive officers of AMGP's and Antero Midstream's respective general partners and of Antero may be deemed to be participants in the solicitation of proxies in respect to the proposed transaction.
Information regarding the directors and executive officers of Antero Midstream's general partner is contained in Antero Midstream's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at http://www.sec.gov or by accessing Antero Midstream's website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AMGP's general partner is contained in AMGP's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing AMGP's website at http://www.anteromidstream.com. Information regarding Antero's executive officers and directors is contained in Antero's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing Antero's website at http:// www.anteroresources.com.
Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the proposed transaction by reading the joint proxy statement/prospectus regarding the proposed transaction when it becomes available. You may obtain free copies of this document as described above.
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Balance Sheets | ||||||
December 31, 2017 and September 30, 2018 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
December 31, 2017 | September 30, 2018 | |||||
Assets | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 28,441 | — | |||
Accounts receivable, net of allowance for doubtful accounts of $1,320 at December 31, 2017 and $1,195 at September 30, 2018, respectively | 34,896 | 46,604 | ||||
Accrued revenue | 300,122 | 354,010 | ||||
Derivative instruments | 460,685 | 493,354 | ||||
Other current assets | 8,943 | 12,664 | ||||
Total current assets | 833,087 | 906,632 | ||||
Property and equipment: | ||||||
Natural gas properties, at cost (successful efforts method): | ||||||
Unproved properties | 2,266,673 | 1,928,990 | ||||
Proved properties | 11,096,462 | 12,306,198 | ||||
Water handling and treatment systems | 946,670 | 993,285 | ||||
Gathering systems and facilities | 2,050,490 | 2,384,041 | ||||
Other property and equipment | 57,429 | 62,739 | ||||
16,417,724 | 17,675,253 | |||||
Less accumulated depletion, depreciation, and amortization | (3,182,171) | (3,890,834) | ||||
Property and equipment, net | 13,235,553 | 13,784,419 | ||||
Derivative instruments | 841,257 | 672,768 | ||||
Investments in unconsolidated affiliates | 303,302 | 392,893 | ||||
Other assets | 48,291 | 45,823 | ||||
Total assets | $ | 15,261,490 | 15,802,535 | |||
Liabilities and Equity | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 62,982 | 91,940 | |||
Accrued liabilities | 443,225 | 457,216 | ||||
Revenue distributions payable | 209,617 | 245,832 | ||||
Derivative instruments | 28,476 | 10,456 | ||||
Other current liabilities | 17,796 | 8,427 | ||||
Total current liabilities | 762,096 | 813,871 | ||||
Long-term liabilities: | ||||||
Long-term debt | 4,800,090 | 5,487,004 | ||||
Deferred income tax liability | 779,645 | 782,145 | ||||
Derivative instruments | 207 | — | ||||
Other liabilities | 43,316 | 48,363 | ||||
Total liabilities | 6,385,354 | 7,131,383 | ||||
Commitments and contingencies | ||||||
Equity: | ||||||
Stockholders' equity: | ||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued | — | — | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 317,086 shares issued and outstanding at December 31, 2017 and September 30, 2018, respectively | 3,164 | 3,171 | ||||
Additional paid-in capital | 6,570,952 | 6,611,348 | ||||
Accumulated earnings | 1,575,065 | 1,299,094 | ||||
Total stockholders' equity | 8,149,181 | 7,913,613 | ||||
Noncontrolling interests in consolidated subsidiary | 726,955 | 757,539 | ||||
Total equity | 8,876,136 | 8,671,152 | ||||
Total liabilities and equity | $ | 15,261,490 | 15,802,535 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||
Three Months Ended September 30, 2017 and 2018 | |||||
(unaudited) | |||||
(In thousands, except per share amounts) | |||||
Three Months Ended September 30, | |||||
2017 | 2018 | ||||
Revenue: | |||||
Natural gas sales | $ | 409,141 | 527,122 | ||
Natural gas liquids sales | 224,533 | 338,269 | |||
Oil sales | 26,527 | 59,722 | |||
Commodity derivative fair value gains (losses) | (65,957) | 57,019 | |||
Gathering, compression, water handling and treatment | 2,869 | 4,844 | |||
Marketing | 50,767 | 89,598 | |||
Marketing derivative fair value losses | — | (42) | |||
Total revenue | 647,880 | 1,076,532 | |||
Operating expenses: | |||||
Lease operating | 23,491 | 36,269 | |||
Gathering, compression, processing, and transportation | 282,134 | 326,504 | |||
Production and ad valorem taxes | 22,995 | 30,518 | |||
Marketing | 78,884 | 151,764 | |||
Exploration | 1,599 | 666 | |||
Impairment of unproved properties | 41,000 | 221,094 | |||
Impairment of gathering systems and facilities | — | 1,157 | |||
Depletion, depreciation, and amortization | 206,968 | 243,186 | |||
Accretion of asset retirement obligations | 658 | 710 | |||
General and administrative (including equity-based compensation expense of $26,447 and $16,202 in 2017 and 2018, respectively) | 62,203 | 59,860 | |||
Total operating expenses | 719,932 | 1,071,728 | |||
Operating income (loss) | (72,052) | 4,804 | |||
Other income (expenses): | |||||
Equity in earnings of unconsolidated affiliates | 7,033 | 10,705 | |||
Interest | (70,059) | (74,528) | |||
Total other expenses | (63,026) | (63,823) | |||
Loss before income taxes | (135,078) | (59,019) | |||
Provision for income tax (expense) benefit | 45,078 | (18,953) | |||
Net loss and comprehensive loss including noncontrolling interests | (90,000) | (77,972) | |||
Net income and comprehensive income attributable to noncontrolling interests | 45,063 | 76,447 | |||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (135,063) | (154,419) | ||
Loss per common share—basic and diluted | $ | (0.43) | (0.49) | ||
Weighted average number of shares outstanding: | |||||
Basic and diluted | 315,463 | 317,082 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Cash Flows | |||||
Nine Months Ended September 30, 2017 and 2018 | |||||
(In thousands) | |||||
Nine Months Ended September 30, | |||||
2017 | 2018 | ||||
Cash flows provided by (used in) operating activities: | |||||
Net income (loss) including noncontrolling interests | $ | 255,523 | (64,437) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||
Depletion, depreciation, amortization, and accretion | 612,823 | 711,581 | |||
Impairment of unproved properties | 83,098 | 406,068 | |||
Impairment of gathering systems and facilities | — | 9,658 | |||
Commodity derivative fair value gains | (458,459) | (134,793) | |||
Gains on settled commodity derivatives | 137,392 | 268,369 | |||
Proceeds from derivative monetizations | 749,906 | — | |||
Marketing derivative fair value gains | — | (94,081) | |||
Gains on settled marketing derivatives | — | 78,098 | |||
Deferred income tax expense | 105,087 | 2,500 | |||
Equity-based compensation expense | 78,925 | 56,429 | |||
Equity in earnings of unconsolidated affiliates | (12,887) | (27,832) | |||
Distributions of earnings from unconsolidated affiliates | 10,120 | 29,660 | |||
Other | 1,191 | 2,945 | |||
Changes in current assets and liabilities: | |||||
Accounts receivable | 1,771 | 4,653 | |||
Accrued revenue | 28,375 | (53,888) | |||
Other current assets | (3,836) | (3,721) | |||
Accounts payable | 4,731 | 8,177 | |||
Accrued liabilities | 43,043 | 27,446 | |||
Revenue distributions payable | 56,982 | 36,215 | |||
Other current liabilities | (977) | (2,649) | |||
Net cash provided by operating activities | 1,692,808 | 1,260,398 | |||
Cash flows used in investing activities: | |||||
Additions to proved properties | (179,318) | — | |||
Additions to unproved properties | (182,207) | (130,381) | |||
Drilling and completion costs | (946,508) | (1,125,660) | |||
Additions to water handling and treatment systems | (143,470) | (77,385) | |||
Additions to gathering systems and facilities | (254,619) | (337,448) | |||
Additions to other property and equipment | (11,417) | (5,371) | |||
Investments in unconsolidated affiliates | (216,776) | (91,419) | |||
Change in other assets | (16,148) | (2,675) | |||
Other | 2,156 | — | |||
Net cash used in investing activities | (1,948,307) | (1,770,339) | |||
Cash flows provided by (used in) financing activities: | |||||
Issuance of common units by Antero Midstream Partners LP | 248,949 | — | |||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation | 311,100 | — | |||
Borrowings (repayments) on bank credit facilities, net | (198,000) | 682,000 | |||
Distributions to noncontrolling interests in consolidated subsidiary | (102,053) | (188,775) | |||
Employee tax withholding for settlement of equity compensation awards | (8,500) | (8,205) | |||
Other | (3,913) | (3,520) | |||
Net cash provided by financing activities | 247,583 | 481,500 | |||
Net decrease in cash and cash equivalents | (7,916) | (28,441) | |||
Cash and cash equivalents, beginning of period | 31,610 | 28,441 | |||
Cash and cash equivalents, end of period | $ | 23,694 | — | ||
Supplemental disclosure of cash flow information: | |||||
Cash paid during the period for interest | $ | 174,324 | 179,489 | ||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | $ | (3,084) | 7,325 |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the three months ended September 30, 2017 and 2018: | ||||||||||||
Three Months Ended September 30, | Amount of | Percent | ||||||||||
(in thousands) | 2017 | 2018 | (Decrease) | Change | ||||||||
Revenue: | ||||||||||||
Natural gas sales | $ | 409,141 | $ | 527,122 | $ | 117,980 | 29 | % | ||||
NGLs sales | 224,533 | 338,269 | 113,736 | 51 | % | |||||||
Oil sales | 26,527 | 59,722 | 33,196 | 125 | % | |||||||
Commodity derivative gains (losses) | (65,957) | 57,019 | 122,977 | (186) | % | |||||||
Gathering, compression, water handling and treatment | 2,869 | 4,844 | 1,976 | 69 | % | |||||||
Marketing | 50,767 | 89,598 | 38,831 | 76 | % | |||||||
Marketing derivative loss | — | (42) | (43) | * | ||||||||
Total revenue | 647,880 | 1,076,533 | 428,653 | 66 | % | |||||||
Operating expenses: | ||||||||||||
Lease operating | 23,491 | 36,269 | 12,778 | 54 | % | |||||||
Gathering, compression, processing, and transportation | 282,134 | 326,504 | 44,370 | 16 | % | |||||||
Production and ad valorem taxes | 22,995 | 30,518 | 7,523 | 33 | % | |||||||
Marketing | 78,884 | 151,764 | 72,881 | 92 | % | |||||||
Exploration | 1,599 | 666 | (933) | (58) | % | |||||||
Impairment of unproved properties | 41,000 | 221,094 | 180,095 | 439 | % | |||||||
Impairment of gathering systems and facilities | — | 1,157 | 1,157 | * | ||||||||
Depletion, depreciation, and amortization | 206,968 | 243,186 | 36,218 | 17 | % | |||||||
Accretion of asset retirement obligations | 658 | 710 | 53 | 8 | % | |||||||
General and administrative (before equity-based compensation) | 35,756 | 43,658 | 7,901 | 22 | % | |||||||
Equity-based compensation | 26,447 | 16,202 | (10,245) | (39) | % | |||||||
Total operating expenses | 719,932 | 1,071,728 | 351,798 | 49 | % | |||||||
Operating income (loss) | (72,052) | 4,804 | 76,855 | * | ||||||||
Other earnings (expenses): | ||||||||||||
Equity in earnings of unconsolidated affiliate | 7,033 | 10,705 | 3,673 | 52 | % | |||||||
Interest expense | (70,059) | (74,528) | (4,469) | 6 | % | |||||||
Total other expenses | (63,026) | (63,823) | (796) | 1 | % | |||||||
Income (loss) before income taxes | (135,078) | (59,019) | 76,059 | * | ||||||||
Income tax (expense) benefit | 45,078 | (18,953) | (64,031) | * | ||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | (90,000) | (77,972) | 12,028 | * | ||||||||
Net income and comprehensive income attributable to noncontrolling interest | 45,063 | 76,447 | 31,384 | 70 | % | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ | (135,063) | $ | (154,419) | $ | (19,356) | 14 | % | ||||
Adjusted EBITDAX | $ | 336,356 | $ | 497,692 | $ | 161,336 | 48 | % | ||||
Production data: | ||||||||||||
Natural gas (Bcf) | 151 | 179 | 28 | 19 | % | |||||||
C2 Ethane (MBbl) | 2,789 | 3,579 | 790 | 28 | % | |||||||
C3+ NGLs (MBbl) | 6,927 | 7,343 | 416 | 6 | % | |||||||
Oil (MBbl) | 624 | 978 | 354 | 57 | % | |||||||
Combined (Bcfe) | 213 | 250 | 37 | 17 | % | |||||||
Daily combined production (MMcfe/d) | 2,317 | 2,718 | 401 | 17 | % | |||||||
Average prices before effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 2.71 | $ | 2.95 | $ | 0.24 | 9 | % | ||||
C2 Ethane (per Bbl) | $ | 8.68 | $ | 15.70 | $ | 7.02 | 81 | % | ||||
C3+ NGLs (per Bbl) | $ | 28.92 | $ | 38.41 | $ | 9.49 | 33 | % | ||||
Oil (per Bbl) | $ | 42.50 | $ | 61.06 | $ | 18.56 | 44 | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.10 | $ | 3.70 | $ | 0.60 | 19 | % | ||||
Average realized prices after effects of derivative settlements: | ||||||||||||
Natural gas (per Mcf) | $ | 3.37 | $ | 3.51 | $ | 0.14 | 4 | % | ||||
C2 Ethane (per Bbl) | $ | 8.53 | $ | 15.70 | $ | 7.17 | 84 | % | ||||
C3+ NGLs (per Bbl) | $ | 23.15 | $ | 35.32 | $ | 12.17 | 53 | % | ||||
Oil (per Bbl) | $ | 45.40 | $ | 54.00 | $ | 8.60 | 19 | % | ||||
Weighted Average Combined (per Mcfe) | $ | 3.39 | $ | 3.98 | $ | 0.59 | 17 | % | ||||
Average Costs (per Mcfe): | ||||||||||||
Lease operating | $ | 0.11 | $ | 0.14 | $ | 0.03 | 27 | % | ||||
Gathering, compression, processing, and transportation | $ | 1.73 | $ | 1.77 | $ | 0.04 | 2 | % | ||||
Production and ad valorem taxes | $ | 0.10 | $ | 0.12 | $ | 0.02 | 20 | % | ||||
Marketing expense (gain), net | $ | 0.13 | $ | 0.25 | $ | 0.12 | 92 | % | ||||
Depletion, depreciation, amortization, and accretion | $ | 0.83 | $ | 0.82 | $ | (0.01) | -1 | % | ||||
General and administrative (before equity-based compensation) | $ | 0.14 | $ | 0.14 | $ | ---- | 0 | % |
*Not meaningful or applicable |
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SOURCE Antero Resources Corporation
DENVER, Oct. 16, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its third quarter 2018 earnings release on Wednesday, October 31, 2018 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, November 1, 2018 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, November 8, 2018 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10123136.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, November 8, 2018 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Oct. 9, 2018 /PRNewswire/ -- Antero Midstream GP LP (NYSE: AMGP) ("AMGP") and Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream Partners" or "AM") today announced that they have entered into a definitive agreement for AMGP to acquire all outstanding AM common units, both those held by the public and those held by Antero Resources (NYSE: AR) ("Antero Resources"), in a stock and cash transaction. In connection with the transaction, AMGP will convert into a corporation and the combined entity will be renamed Antero Midstream Corporation ("New AM"). Under the terms of the agreement, Antero Midstream Partners public unitholders will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM stock per AM unit owned, resulting in aggregate consideration valued at $31.41 per AM unit, based on the October 8, 2018 closing price. Antero Resources will be entitled to receive a combination of $3.00 in cash and 1.6023 shares of New AM stock for each AM unit owned, resulting in aggregate consideration valued at $30.43 per AM unit, based on the October 8, 2018 closing price. AM public unitholders will be entitled to elect to receive their merger consideration in all cash, all stock, or a combination of cash and stock, and AR will have the ability to elect to take a larger portion of its merger consideration in cash if the AM public unitholders elect to receive more stock than the mixed election consideration, in each case subject to pro ration to ensure that the aggregate amount of cash consideration paid to all AM unitholders equals approximately $598 million. The transaction has been negotiated and recommended by the Conflicts Committees of AMGP and Antero Midstream Partners and the Special Committee of Antero Resources and approved by all three Boards of Directors.
Transaction Highlights:
(1) Based on October 8, 2018 AMGP closing price.
(2) AM price per unit prior to the Special Committee announcement was $26.49 as of February 23, 2018.
Commenting on the simplification transaction, Paul Rady, Chairman and CEO said, "The transaction is a win-win-win for the Antero family and simplifies the midstream structure in an immediately accretive transaction. The traditional C-corp structure for both governance and tax purposes should further enhance New AM's appeal to institutional investors and for inclusion in major indices, and provides valuable shareholder rights to the public. Importantly, the long-term vision and integrated strategy for the Antero family remains unchanged and we continue to be excited about executing on the five year development and infrastructure plans communicated at our analyst day in January."
Glen Warren, President and CFO of Antero Resources and President of New AM added, "Today's announcement also enhances Antero Resources' ability to execute on its liquids focused integrated development program. The combination of cash consideration received in the simplification transaction and free cash flow generation is expected to fully fund Antero Resources' initial $600 million share repurchase program that was announced today. As a result, Antero Resources plans to opportunistically repurchase shares while not exceeding Stand-Alone Net Debt to Stand-Alone Adjusted EBITDAX of 2.25x by year-end 2018 and 2.0x by year-end 2019."
Midstream Simplification Transaction Details
Under the terms of the simplification agreement, AMGP will acquire 100% of Antero Midstream Partners' 188.1 million fully diluted common units outstanding, including 98.9 million common units owned by Antero Resources. AM public unitholders will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM stock per AM unit owned, resulting in aggregate consideration valued at $31.41 per AM unit, based on the October 8, 2018 closing price. The all-in consideration for AM public unitholders represents a premium of 7% based on the closing price as of October 8, 2018 and a premium of 19% based on closing prices as of February 23, 2018 prior to the announcement of the Special Committee formation. Antero Resources will be entitled to receive a combination of $3.00 in cash and 1.6023 shares of New AM stock for each AM unit owned, resulting in aggregate consideration valued at $30.43 per AM unit, based on the October 8, 2018 closing price. AM public unitholders will be entitled to elect to receive their merger consideration in all cash, all stock or a combination of cash and stock. AR will have the ability to elect to take a larger portion of its merger consideration in cash if the AM public unitholders elect to receive more stock consideration than outlined in the mixed election, subject to pro ration, to ensure that the aggregate amount of cash consideration paid to all AM unitholders equals approximately $598 million. Following the AM public unitholders' election of their consideration, Antero Resources' can elect additional cash consideration, if available, in lieu of stock consideration. Following the simplification, New AM will eliminate all IDRs in AM and the Series B units, which represent 10-year profits interests in Antero IDR Holdings ("IDR LLC"), the entity that holds all of the outstanding IDRs in AM.
In connection with the transaction, Series B unitholders agreed to terminate and exchange their Series B units for an aggregate of 17.35 million shares in New AM upon the closing of the simplification transaction. The 17.35 million New AM shares represent approximately 4.4% of the pro forma market capitalization of New AM in excess of $2.0 billion based on closing prices as of October 8, 2018. If the Series B units and the IDRs were not eliminated as part of the transaction, the Series B units would be entitled to receive up to 6% of the IDR cash flow stream above $7.5 million per quarter from Antero Midstream Partners and would be exchangeable, at the option of the holders, into up to 6% of the pro forma market capitalization of New AM in excess of $2.0 billion through the maturity date of December 31, 2026. The New AM shares issued in exchange for outstanding Series B units will be subject to the same vesting conditions to which the Series B units are currently subject, with one-third currently vested, another one-third vesting at December 31, 2018 and the final one-third vesting on December 31, 2019. Accordingly, a portion of the shares in New AM to be issued to the Series B unitholders will continue to be subject to vesting and forfeiture through December 31, 2019, and will not be entitled to receive any dividends from New AM prior to their vesting on December 31, 2019. The exchange of the Series B units in connection with the simplification transaction further aligns management, employees, financial sponsors and pro forma shareholders and lowers the cost of capital for future investment decisions. Following the simplification transaction and exchange of the Series B units, New AM will have approximately 508 million fully diluted shares outstanding.
The transaction will be fully taxable to both Antero Resources and Antero Midstream Partners' public unitholders, which will result in a tax basis step up with respect to the assets of Antero Midstream Partners for the pro forma entity. As a result, New AM does not expect to pay material cash taxes through at least 2024. The PV-10 of tax savings to New AM as a result of this transaction is approximately $800 million. Antero Resources expects to utilize a portion of its $3.0 billion of net operating loss carryforwards to substantially shield its gain from the transaction. Antero Midstream Partners' public unitholders should consult with their tax advisor regarding the tax impact from the transaction, but will have the ability to elect to receive all cash in the transaction, subject to pro ration, and regardless of pro ration will have the ability to receive at least $3.415 per unit in cash. The higher exchange ratio and cash consideration received by the AM public unitholders was designed to help offset potential tax impacts of the transaction.
The AMGP Conflicts Committee, consisting of directors not associated with management or the original financial sponsor groups, evaluated the transaction on behalf of the public shareholders and the AMGP board of directors. The AMGP Conflicts Committee recommended approval of the simplification transaction to the Board of Directors of AMGP. The Antero Midstream Partners Conflicts Committee, consisting of directors not associated with management or the original financial sponsor groups, evaluated the transaction on behalf of the AM board of directors and public unitholders and also recommended approval of the simplification transaction to the AM board of directors. The Antero Resources Special Committee, consisting of directors not associated with management or the financial sponsor groups that originally funded Antero Resources, evaluated the transaction on behalf of the public shareholders and the board of directors of Antero Resources, which currently owns approximately 53% of the Antero Midstream Partners units outstanding. The Antero Resources Special Committee recommended approval of the simplification transaction to the AR board of directors. The transaction was approved by the board of directors of each of AMGP, Antero Midstream Partners and Antero Resources.
The transaction is subject to the approval of holders of a majority of the shares held by AMGP's public shareholders excluding the original private equity sponsors, Series B holders, and affiliates of AMGP's general partner. The transaction is also subject to the approval of holders of a majority of the units held by AM unitholders, excluding Antero Resources, the original private equity sponsors, the Series B holders and affiliates of AM's general partner. The closing of the transaction is expected in the first quarter of 2019, subject to obtaining these approvals and customary regulatory approvals.
Financing & Balance Sheet
The cash consideration will be funded at closing by utilizing borrowings under an amended AM credit facility. AM is in the process of exercising the accordion feature on its credit facility, which would increase capacity from $1.5 billion to $2.0 billion. New AM expects to maintain a strong balance sheet flexing to just over 3.0x net debt to adjusted EBITDA post-closing at the end of the first quarter of 2019 and de-levering into the mid two-times range by 2020. Consistent with AM's previous outlook, New AM does not anticipate a need to access the public equity markets to fund its previously disclosed $2.7 billion in organic growth opportunities from 2018 through 2022.
Michael Kennedy, CFO of Antero Midstream Partners and AMGP commented, "The simplification transaction further reinforces Antero Midstream's position as a premier organic growth Appalachian midstream platform. From a position of strength, the transaction is expected to allow us to deliver DCF per unit accretion to both AM unitholders and AMGP shareholders, in addition to an up-front premium to AM unitholders. This accretion, along with the numerous structural and governance merits, delivers significant value to our unitholders and shareholders."
Mr. Kennedy further added, "The elimination of the IDRs is expected to reduce Antero Midstream's cost of capital which will broaden New AM's growth opportunities beyond the previously disclosed $2.7 billion organic opportunity set with attractive project and corporate level returns. The simplification also creates a unique C-corp security with top-tier dividend growth, low leverage and attractive return on invested capital."
Pro Forma Dividend and Coverage Policy
Assuming the simplification transaction closes in the first quarter of 2019 and subject to board approvals, New AM currently intends to target a dividend of $1.24 per share in 2019 representing the midpoint of our targeted dividend per share range for 2019. New AM intends to target dividend growth of 29% in 2020 and dividend growth of 20% in each of 2021 and 2022. Over the 2019 through 2022 period New AM intends to target an average DCF coverage ratio of 1.2-1.3x. Our targeted dividend growth rates are unchanged from Antero Midstream Partners' previously announced distribution growth targets through 2022. The majority of these pro forma dividends are expected to be treated as non-taxable return of capital with the remaining distributions being taxable dividend income under current U.S. federal tax regulations.
The following table illustrates the pro forma dividend for New AM:
2019 | 2020 | 2021 | 2022 | ||||||||||||
Long-term Targets | Low | High | Low | High | Low | High | Low | High | |||||||
Dividend Per Share | $1.23 | — | $1.25 | $1.57 | — | $1.63 | $1.89 | — | $1.95 | $2.27 | — | $2.34 | |||
Year-over-Year Growth | 128% | — | 131% | 28% | — | 30% | 20% | 20% | |||||||
Note: 2019 year-over-year dividend growth represents growth vs. AMGP's 2018 midpoint distribution of $0.54/share |
The following table illustrates the increase in targeted distributions per share for AMGP shareholders through 2022 comparing the pro forma dividend targets to the previously disclosed status quo distribution targets:
2019 | 2020 | 2021 | 2022 | ||||||||||||
Per Share | Low | High | Low | High | Low | High | Low | High | |||||||
Status Quo Distribution | $0.84 | — | $0.91 | $1.28 | — | $1.40 | $1.65 | — | $1.83 | $2.10 | — | $2.36 | |||
Pro Forma Dividend | $1.23 | — | $1.25 | $1.57 | — | $1.63 | $1.89 | — | $1.95 | $2.27 | — | $2.34 | |||
Accretion - $/Share | $0.39 | — | $0.34 | $0.29 | — | $0.23 | $0.24 | — | $0.12 | $0.17 | — | $(0.02) | |||
Accretion - % | 46% | — | 37% | 23% | — | 16% | 15% | — | 7% | 8% | — | (1%) |
The following table illustrates the increase in targeted distributions per unit for Antero Midstream Partners public unitholders through 2022 comparing the pro forma dividend targets to the previously disclosed status quo distribution targets on a pre-tax basis. The table below is based on a 100% equity consideration of 1.832 AMGP shares for each public AM unit. Public unitholders received a higher exchange ratio to help offset transaction taxes.
2019 | 2020 | 2021 | 2022 | ||||||||||||
Per Share | Low | High | Low | High | Low | High | Low | High | |||||||
Status Quo Distribution | $2.19 | — | $2.22 | $2.80 | — | $2.89 | $3.36 | — | $3.47 | $4.03 | — | $4.16 | |||
Pro Forma Dividend | $1.23 | — | $1.25 | $1.57 | — | $1.63 | $1.89 | — | $1.95 | $2.27 | — | $2.34 | |||
x 1.832 Shares Received | 1.832 | 1.832 | 1.832 | 1.832 | 1.832 | 1.832 | 1.832 | 1.832 | |||||||
Total Dividends | $2.25 | — | $2.29 | $2.88 | — | $2.99 | $3.46 | — | $3.57 | $4.16 | — | $4.29 | |||
Midpoint Variance - | $0.06 | $0.08 | $0.10 | $0.12 |
The following table illustrates the increase in targeted distributions per unit for Antero Midstream Partners units held by AR through 2022 comparing the pro forma dividend targets to the previously disclosed status quo distribution targets on a pre-tax basis. The table below is based on a 100% equity consideration of 1.776 AMGP shares for each AR-held AM unit:
2019 | 2020 | 2021 | 2022 | ||||||||||||
Per Share | Low | High | Low | High | Low | High | Low | High | |||||||
Status Quo Distribution | $2.19 | — | $2.22 | $2.80 | — | $2.89 | $3.36 | — | $3.47 | $4.03 | — | $4.16 | |||
Pro Forma Dividend | $1.23 | — | $1.25 | $1.57 | — | $1.63 | $1.89 | — | $1.95 | $2.27 | — | $2.34 | |||
x 1.776 Shares Received | 1.776 | 1.776 | 1.776 | 1.776 | 1.776 | 1.776 | 1.776 | 1.776 | |||||||
Total Dividends | $2.18 | — | $2.22 | $2.79 | — | $2.89 | $3.36 | — | $3.46 | $4.03 | — | $4.16 | |||
Midpoint Variance - | $0.00 | $0.00 | $0.00 | $0.00 |
Conference Call
A joint conference call for Antero Midstream and AMGP is scheduled on Tuesday, October 9, 2018 at 10 am ET to discuss the transaction. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Midstream". A telephone replay of the call will be available until Tuesday, October 16, 2018 at 10am ET at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10125139.
Presentation
To access the live webcast and view the related transaction call presentation, visit Antero Midstream's website at www.anteromidstream.com or AMGP's website at www.anteromidstreamgp.com. The webcast will be archived for replay on Antero Midstream's website and AMGP's website until Tuesday, October 16, 2018 at 10:00 am MT. Information on Antero Midstream's website and AMGP's website does not constitute a portion of this press release.
Financial and Legal Advisors
Vinson & Elkins acted as legal advisor to AMGP, Antero Midstream Partners and Antero Resources. Goldman Sachs & Co. LLC and Hunton Andrews Kurth and Richards, Layton & Finger acted as financial and legal advisors, respectively, to the Conflicts Committee of AMGP. Morgan Stanley & Co. LLC acted as the financial advisor to Antero Midstream Partners. Tudor, Pickering, Holt & Co. and Gibson, Dunn & Crutcher LLP acted as financial and legal advisors, respectively to the Conflicts Committee of Antero Midstream Partners. Baird and Sidley Austin LLP acted as financial and legal advisors, respectively, to the Special Committee of AR. J.P. Morgan Securities LLC acted as financial advisor to Antero Resources.
Antero Midstream Partners is a limited partnership that owns, operates and develops midstream gathering, compression, processing and fractionation assets as well as integrated water assets that primarily service Antero Resources Corporation's properties located in West Virginia and Ohio. Holders of Antero Midstream Partners common units will receive a Schedule K-1 with respect to distributions received on the common units.
AMGP is a Delaware limited partnership that has elected to be classified as an entity taxable as a corporation for U.S. federal income tax purposes. Holders of AMGP common shares will receive a Form 1099 with respect to distributions received on the common shares. AMGP owns the general partner of Antero Midstream Partners and indirectly owns the incentive distribution rights in Antero Midstream Partners.
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AM and AMGP's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release and are based upon a number of assumptions. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expected consideration to be received in connection with the closing of the transaction, the timing of consummation of the transaction, if at all, statements regarding the transaction, the extent of the accretion, if any, to AMGP shareholders and AM unitholders, the effect that the elimination of the IDRs and Series B Units will have on Antero Midstream's cost of capital, New AM's growth opportunities and increased trading liquidity following the consummation of the transaction, anticipated cost savings, the pro forma dividend and DCF coverage ratio targets for New AM, that the transaction will reduce AMGP's tax payments from 2019 through 2022 and that New AM does not expect to pay material cash taxes through at least 2024, the PV-10 tax savings expected to be realized as a result of the transaction, opportunities and anticipated future performance, and whether the structure resulting from the merger will be more appealing to a wider set of investors. Although AM and AMGP each believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that the assumptions underlying these forward-looking statements will be accurate or the plans, intentions or expectations expressed herein will be achieved. For example, future acquisitions, dispositions or other strategic transactions may materially impact the forecasted or targeted results described in this release. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Resources.
Antero Midstream Partners and AMGP caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the AM's and AMGP's control, incident to the gathering and processing and fresh water and waste water treatment businesses. These risks include, but are not limited to, the expected timing and likelihood of completion of the transaction, including the ability to obtain requisite regulatory, unitholder and shareholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized, the cost savings, tax benefits and any other synergies from the transaction may not be fully realized or may take longer to realize than expected, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute AM's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2017.
No Offer or Solicitation
This communication relates to a proposed business combination transaction between AM and AMGP. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Additional Information And Where To Find It
In connection with the transaction, AMGP will file with the U.S. Securities and Exchange Commission ("SEC") a registration statement on Form S-4, that will include a joint proxy statement of AM and AMGP and a prospectus of AMGP. The transaction will be submitted to AM's unitholders and AMGP's shareholders for their consideration. AM and AMGP may also file other documents with the SEC regarding the transaction. The definitive joint proxy statement/prospectus will be sent to the shareholders of AMGP and unitholders of AM. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that AMGP or AM may file with the SEC or send to shareholders of AMGP or unitholders of AM in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF AM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or AM through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by AM will be made available free of charge on AM's website at http://investors.anteromidstream.com/investor-relations/AM, under the heading "SEC Filings," or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310.
Participants In The Solicitation
AR, AMGP, AM and the directors and executive officers of AMGP and AM's respective general partners and of AR may be deemed to be participants in the solicitation of proxies in respect to the proposed transaction.
Information regarding the directors and executive officers of AM's general partner is contained in AM's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at http://www.sec.gov or by accessing AM's website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AMGP's general partner is contained in AMGP's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing the AMGP's website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AR is contained in AR 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing the AMGP's website at http://www.anteroresources.com.
Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the proposed transaction by reading the joint proxy statement/prospectus regarding the proposed transaction when it becomes available. You may obtain free copies of this document as described above.
For more information, contact Michael Kennedy – CFO of Antero Midstream Partners and AMGP at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream; Antero Midstream GP LP
DENVER, Oct. 9, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero", the "Company" or "AR") today announced a simplified midstream corporate structure in which Antero Midstream GP LP (NYSE: AMGP) ("AMGP") and Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream Partners" or "AM") have entered into a definitive agreement for AMGP to acquire all outstanding AM common units in a stock and cash transaction. In connection with the transaction, AMGP will convert into a corporation and the combined entity will be renamed Antero Midstream Corporation ("New AM"). Additionally, Antero Resources board of directors approved a share repurchase program of up to $600 million.
Highlights Include:
Commenting on today's announcements, Paul Rady, Co-founder, Chairman and CEO said, "This is a "win-win-win" for the Antero family as it simplifies our corporate structure, returns capital to shareholders and better aligns shareholder interest. At the current AR share price, we believe an open market share repurchase program is an attractive way to deliver value to our shareholders. Additionally, by maintaining our integrated structure, we continue to hold a competitive advantage as we develop our core liquids Appalachian Basin assets in a coordinated effort alongside our midstream provider, New AM. We remain focused on executing on our five year development plan announced at the January analyst day as Antero joins an elite group of E&Ps with scale, attractive production growth, low leverage and free cash flow generation."
Midstream Simplification Transaction Details
Under the terms of the simplification agreement, AMGP will acquire 100% of Antero Midstream Partners' 188.1 million fully diluted common units outstanding, including 98.9 million common units owned by Antero Resources. Antero Resources will be entitled to receive a combination of $3.00 in cash and 1.6023 shares of New AM stock for each AM unit owned, resulting in aggregate consideration valued at $30.43 per AM unit, based on the October 8, 2018 closing price. The consideration to AR represents a premium of 3% based on the closing price as of October 8, 2018 and a premium of 15% based on closing prices as of February 23, 2018 prior to the announcement of the Special Committee formation. AM public unitholders will be entitled to receive a combination of $3.415 in cash and 1.635 shares of New AM stock per AM unit owned, resulting in aggregate consideration valued at $31.41 per AM unit, based on the October 8, 2018 closing price. AM public unitholders will be entitled to elect to receive their merger consideration in all cash, all stock or a combination of cash and stock as outlined above. AR will have the ability to elect to take a larger portion of its merger consideration in cash if the AM public unitholders elect to receive more stock consideration, subject to pro ration, to ensure that the aggregate amount of cash consideration paid to all AM unitholders equals $598 million. Following the simplification, New AM will eliminate all incentive distribution rights in AM (the "IDRs") and the Series B units, which represent 10-year profits interests in Antero IDR Holdings ("IDR LLC"), the entity that holds all of the outstanding IDRs in AM.
In connection with the transaction, Series B unitholders agreed to an early termination to exchange their profits interests for an aggregate of 17.35 million shares in New AM upon the closing of the simplification transaction. The 17.35 million New AM shares represent approximately 4.4% of the pro forma market capitalization of New AM in excess of $2.0 billion based on closing prices as of October 8, 2018. If the Series B units and the IDRs were not eliminated as part of the transaction, the Series B units would be entitled to receive up to 6% of the IDR cash flow stream above $7.5 million per quarter from Antero Midstream Partners and would be exchangeable, at the option of the holders, into up to 6% of the pro forma market capitalization of New AM in excess of $2.0 billion through the maturity date of December 31, 2026. The New AM shares issued in exchange for outstanding Series B units will be subject to the same vesting conditions to which the Series B units are currently subject, with one-third currently vested, another one-third vesting at December 31, 2018 and the final one-third vesting on December 31, 2019. Accordingly, a portion of the shares in New AM to be issued to the Series B unitholders will continue to be subject to vesting and forfeiture through December 31, 2019, and will not be entitled to receive any dividends from New AM prior to their vesting on December 31, 2019. The exchange of the Series B units in connection with the simplification transaction further aligns management, employees, financial sponsors and pro forma shareholders and lowers the cost of capital for future investment decisions. Following the simplification transaction and exchange of the Series B units, New AM will have approximately 508 million fully diluted shares outstanding.
The Antero Resources Special Committee, consisting of directors not associated with management or the original financial sponsor groups, evaluated the transaction on behalf of the public shareholders and the board of directors of Antero Resources, which currently owns approximately 53% of the Antero Midstream Partners units outstanding. The Antero Resources Special Committee recommended approval of the simplification transaction to the AR board of directors. The AMGP Conflicts Committee, consisting of directors not associated with management or the original financial sponsor groups, evaluated the transaction on behalf of the public shareholders and the AMGP board of directors. The AMGP Conflicts Committee recommended approval of the simplification transaction to the board of directors of AMGP. The Antero Midstream Partners Conflicts Committee, consisting of directors not associated with management or the original financial sponsor groups, evaluated the transaction on behalf of the public unitholders and the AM board of directors, and also recommended approval of the simplification transaction to the AM board of directors. The transaction was approved by the board of directors of Antero Resources, AMGP and Antero Midstream Partners.
The transaction is subject to the approval of holders of a majority of the shares held by AMGP's public shareholders excluding the original private equity sponsors, Series B holders and affiliates of AMGP's general partner. The transaction is also subject to the approval of holders of a majority of the units held by AM unitholders, excluding Antero Resources, the original private equity sponsors, the Series B holders and affiliates of AM's general partner. The closing of the transaction is expected in the first quarter of 2019, subject to obtaining these approvals and customary regulatory approvals.
$600 Million Share Repurchase Program
The open market share repurchase program is expected to commence during the fourth quarter of 2018 and extend over the next 12 to 18 months, allowing the company to be opportunistic regarding the share repurchase price. However, leverage reduction remains a top priority for AR. Therefore, share repurchases will be executed only when leverage is expected to be at or below the 2.25x Stand-Alone Net Debt to Stand-Alone Adjusted EBITDAX target for year-end 2018 and at or below 2.0x for year-end 2019. This program is expected to be fully funded with cash proceeds from the following:
Cash Proceeds from AMGP Acquisition of AM
In connection with the simplification transaction, AR expects to elect to receive a minimum of approximately $300 million in cash proceeds, or $3.00 per unit for each AM unit held, as well as receive 158.4 million New AM shares. Depending on the cash election of AM unitholders other than AR, the cash consideration could increase up to the total cash pool in the simplification transaction of approximately $598 million and conversely the number of New AM shares could decrease depending on the outcome of the cash election. Upon completion of the transaction and assuming the $3.00 per unit is received in cash, AR will have a 31% ownership in the pro forma midstream entity. While the simplification transaction will be fully taxable to AR and the other AM unitholders, AR is expected to be substantially shielded from paying current tax on its gain with respect to the simplification transaction through the utilization of a portion of its $3.0 billion of NOLs held at December 31, 2017. Even with the utilization of NOLs in connection with the simplification transaction, AR does not expect to pay a material amount of cash taxes through at least 2022 based on the long-term development plan outlined at the 2018 analyst day.
Free Cash Flow
The remainder of the share repurchase program will be funded through free cash flow expected to be generated over the next 12 to 18 months.
Commenting on the share repurchase program, Glen Warren, Co-founder, President, and Chief Financial Officer of Antero Resources said, "Today's announcements provide Antero Resources an exciting opportunity to unlock shareholder value. We will remain disciplined in utilizing the share repurchase program along with our priority to reduce Stand-Alone leverage metrics to at or below 2.25x by year-end 2018 and at or below 2.0x by year-end 2019. If fully utilized at the current share price, this initial $600 million program would result in a reduction of more than 10% of the current shares outstanding. Additionally, we believe the midstream simplification will unlock shareholder value with a best-in-class midstream structure, a more liquid vehicle from a trading perspective and better alignment of interest between Antero entities, while also accelerating the return of capital to our shareholders."
Conference Call
A conference call for Antero Resources is scheduled on Tuesday, October 9th, 2018 at 9 am MT to discuss the details of today's announcement. A brief Q&A session for security analysts will immediately follow the discussion. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until October 16, 2018 at 9 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10125145.
Presentation
An updated presentation will be posted to the Company's website before the October 9, 2018 transaction conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Financial and Legal Advisors
Vinson & Elkins acted as legal advisor to AMGP, Antero Midstream Partners and Antero Resources. J.P. Morgan Securities LLC acted as financial advisor to Antero Resources. Baird and Sidley Austin LLP acted as financial and legal advisors, respectively, to the Special Committee of AR. Goldman Sachs and Hunton Andrews Kurth acted as financial and legal advisors, respectively, to the Conflicts Committee of AMGP. Richards, Layton & Finger acted as Delaware counsel to the Conflicts Committee of AMGP. Morgan Stanley & Co. LLC acted as the financial advisor to Antero Midstream Partners. Tudor, Pickering, Holt & Co. and Gibson, Dunn & Crutcher LLP acted as financial and legal advisors, respectively to the Conflicts Committee of Antero Midstream Partners.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as the expected sources of funding and timing for completion of the share repurchase program if at all, statements regarding the simplification transaction, the expected consideration to be received in connection with the closing of the simplification transaction, pro forma descriptions of the Company and its operations following the simplification transaction, the timing of the consummation of the simplification transaction, if at all, the extent to which AR will be shielded from tax payments associated with the simplification transactions, anticipated cost savings, AR's expected free cash flow generation, AR's targeted leverage metrics and opportunities and anticipated future performance, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, the expected timing and likelihood of completion of the simplification transaction, including the ability to obtain requisite regulatory, unitholder and shareholder approval and the satisfaction of the other conditions to the consummation of the proposed simplification transaction, risks that the proposed simplification transaction may not be consummated or the benefits contemplated therefrom may not be realized, the cost savings, tax benefits and any other synergies from the simplification transaction may not be fully realized or may take longer to realize than expected, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
No Offer or Solicitation
This communication relates to a proposed business combination transaction between AM and AMGP. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Additional Information And Where To Find It
In connection with the transaction, AMGP will file with the U.S. Securities and Exchange Commission ("SEC") a registration statement on Form S-4, that will include a joint proxy statement of AM and AMGP and a prospectus of AMGP. The transaction will be submitted to AM's unitholders and AMGP's shareholders for their consideration. AM and AMGP may also file other documents with the SEC regarding the transaction. The definitive joint proxy statement/prospectus will be sent to the shareholders of AMGP and unitholders of AM. This document is not a substitute for the registration statement and joint proxy statement/prospectus that will be filed with the SEC or any other documents that AMGP or AM may file with the SEC or send to shareholders of AMGP or unitholders of AM in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF AM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION WHEN IT BECOMES AVAILABLE AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.
Investors and security holders will be able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or AM through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by AM will be made available free of charge on AM's website at http://investors.anteromidstream.com/investor-relations/AM, under the heading "SEC Filings," or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 75219, Tel. No. (303) 357-7310.
Participants In The Solicitation
AR, AMGP, AM and the directors and executive officers of AMGP and AM's respective general partners and of AR may be deemed to be participants in the solicitation of proxies in respect to the proposed transaction.
Information regarding the directors and executive officers of AM's general partner is contained in AM's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018, and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at http://www.sec.gov or by accessing AM's website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AMGP's general partner is contained in AMGP's 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing the AMGP's website at http://www.anteromidstream.com. Information regarding the executive officers and directors of AR is contained in AR 2018 Annual Report on Form 10-K filed with the SEC on February 13, 2018 and certain of its Current Reports on Form 8-K. You can obtain a free copy of this document at the SEC's website at www.sec.gov or by accessing the AMGP's website at http:// www.anteroresources.com.
Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the proposed transaction by reading the joint proxy statement/prospectus regarding the proposed transaction when it becomes available. You may obtain free copies of this document as described above.
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SOURCE Antero Resources
DENVER, Aug. 1, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its second quarter 2018 financial and operational results. The relevant consolidated and consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, which has been filed with the Securities and Exchange Commission ("SEC"). The relevant Stand-Alone financial statements are also included in Antero's Form 10-Q within the Parent column of the guarantor footnote (Note 16).
Second Quarter 2018 Highlights:
Commenting on the quarter, Paul Rady, Chairman and CEO said, "We have made significant progress towards achieving our financial and operating objectives during the first half of 2018. Our focus on operations execution resulted in meaningful efficiency gains during the first half of the year. This has positioned us to reduce the number of completion crews that we plan to operate in the field during the remainder of the year, while production growth of 20% and capital spending guidance remain on target. We continue to execute on our long-term 5-year plan in which we expect attractive production growth while generating significant free cash flow."
Recent Developments
2018 Guidance Update
Based on the first half realizations and current strip prices for the second half of the year, Antero is raising its full year realized natural gas price guidance before hedges from a range of $0.00 to $0.05 per Mcf premium to NYMEX Henry Hub to a range of $0.05 to $0.10 per Mcf premium to NYMEX. Importantly, the Rover Phase 2 Sherwood Lateral is expected to allow Antero's Marcellus gas to be transported on Rover to attractively priced Chicago and Gulf Coast markets, highlighting the optionality that the Sherwood Lateral brings to Antero's long-term development plan. The ability to consistently realize natural gas prices above NYMEX reflects the competitive advantage of Antero's diversified firm transportation portfolio and ability to sell gas into favorably priced markets.
Driven primarily by a delay of the in-service date of the Mariner East 2 pipeline, now expected in the fourth quarter of 2018, Antero is lowering its guidance on C3+ NGL realized prices as a percentage of WTI from a range of 62.5% to 67.5% to a range of 57.5% to 62.5%. Additionally, although NGL prices on an absolute dollar per barrel basis have remained in line with prior guidance assumptions, NGL prices have not increased at the same rate as WTI during 2018. The Mariner East 2 pipeline and terminal project is expected to result in a significant reduction in propane and butane differentials to Mont Belvieu, driven by lower transportation costs to the market and sales to international markets at a premium to Mont Belvieu pricing.
In conjunction with the Mariner East 2 pipeline delay, Antero is also lowering its cash cost guidance for 2018 from $2.10 to $2.20 per Mcfe on a Stand-Alone basis to $2.05 to $2.15 per Mcfe, and from $1.65 to $1.75 per Mcfe on a consolidated basis to $1.60 to $1.70 per Mcfe. Cash costs include lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes.
The following table is a comparison of the initial 2018 guidance issued in January 2018 and the revised 2018 guidance. Except as mentioned below, our previously issued 2018 guidance remains unchanged.
Guidance |
2018 – Revised |
2018 – Initial |
Variance | |||||||||||
Low |
High |
Low |
High |
Midpoint | ||||||||||
Price Realizations |
||||||||||||||
Natural Gas Realized Price Premium to NYMEX Henry Hub |
$0.05 |
- |
$0.10 |
$0.00 |
- |
$0.05 |
$0.05 | |||||||
C3+ NGL Realized Price as a Percent of NYMEX WTI |
57.5% |
- |
62.5% |
62.5% |
- |
67.5% |
(5.0%) | |||||||
Benchmark WTI Price ($/Bbl) (1) |
$67.00 |
$60.00 |
$7.00 | |||||||||||
Implied C3+ NGL Pricing Guidance ($/Bbl) |
$38.53 |
- |
$41.88 |
$37.50 |
- |
$40.50 |
$1.20 | |||||||
Cash Production Expense ($/Mcfe) – Stand-Alone |
$2.05 |
- |
$2.15 |
$2.10 |
- |
$2.20 |
($0.05) | |||||||
Cash Production Expense ($/Mcfe) – Consolidated |
$1.60 |
- |
$1.70 |
$1.65 |
- |
$1.75 |
($0.05) | |||||||
(1) |
Revised benchmark WTI price guidance reflects actual year-to-date WTI prices and futures as of 7/31/18. Initial benchmark WTI price guidance based on strip prices as of 12/31/17. |
Financial and operational results are reported and discussed on a consolidated basis, unless otherwise noted. Please read "Non-GAAP Financial Measures" for:
Please read "Second Quarter 2018 Financial Results" for a reconciliation of consolidated and Stand-Alone Adjusted EBITDAX margin to realized price before cash receipts for settled commodity derivatives, the most comparable GAAP measure.
Second Quarter 2018 Financial Results
As of June 30, 2018, Antero Resources owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated within Antero Resources' results.
For the three months ended June 30, 2018, Antero reported a GAAP net loss of $136 million, or $(0.43) per diluted share, compared to a net loss of $5 million, or $(0.02) per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," adjusted net income was $6 million, or $0.02 per diluted share, compared to a $13 million loss, or $(0.04) per diluted share, in the prior year period. Stand-Alone adjusted net loss was $2 million compared to a loss of $17 million in the prior year period. Adjusted EBITDAX was $405 million, a 26% increase compared to $321 million in the prior year period, and Stand-Alone Adjusted EBITDAX was $335 million, a 25% increase compared to $267 million in the prior year period. Second quarter 2018 results include settled marketing derivative losses of $16 million.
The following table details the components of average net production and average realized prices for the three months ended June 30, 2018:
Three Months Ended June 30, 2018 |
||||||||||||||||
Natural Gas |
Oil (Bbl/d) |
C3+ NGLs |
Ethane |
Combined |
||||||||||||
Average Net Production |
1,838 |
6,940 |
70,485 |
36,156 |
2,520 |
|||||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs ($/Bbl) |
Ethane ($/Bbl) |
Combined Gas Equivalent ($/Mcfe) |
|||||||||||
Average realized prices before settled derivatives |
$ |
2.83 |
$ |
61.55 |
$ |
34.81 |
$ |
9.93 |
$ |
3.35 |
||||||
Settled commodity derivatives |
0.67 |
(9.44) |
(1.71) |
— |
0.42 |
|||||||||||
Average realized prices after settled derivatives |
$ |
3.50 |
$ |
52.11 |
$ |
33.10 |
$ |
9.93 |
$ |
3.77 |
||||||
NYMEX average price |
$ |
2.80 |
$ |
68.03 |
$ |
2.80 |
||||||||||
Premium / (Differential) to NYMEX |
$ |
0.70 |
$ |
(15.92) |
$ |
0.97 |
Net daily natural gas equivalent production in the second quarter averaged 2,520 MMcfe/d, including 113,581 Bbl/d of liquids (27% of production), an increase of 15% compared to the prior year period and a 6% increase sequentially. Natural gas production averaged 1,838 MMcf/d, oil production averaged 6,940 Bbl/d, C3+ NGLs production averaged 70,485 Bbl/d, and recovered ethane production averaged 36,156 Bbl/d. Total liquids production grew 11% compared to the prior year period and 10% sequentially. Liquids revenue represented approximately 38% of total product revenue before hedges, an increase from 30% of total product revenue in the prior year period. This increase reflects the substantial increase in liquids pricing year over year.
Antero's average realized natural gas price before hedging was $2.83 per Mcf, a $0.03 per Mcf premium to the average NYMEX Henry Hub price during the period. Including hedges, Antero's average realized natural gas price was $3.50 per Mcf, a $0.70 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $113 million, or $0.67 per Mcf.
Antero's average realized C3+ NGL price before hedging was $34.81 per barrel, or 51% of the average NYMEX WTI oil price, representing a 44% increase versus the prior year period. Including hedges, Antero's average realized C3+ NGL price was $33.10 per barrel, reflecting the realization of a cash settled C3+ hedge loss of $11 million, or $1.71 per barrel.
Antero's average realized oil price before hedging was $61.55 per barrel, a $6.48 negative differential to average NYMEX WTI and a 42% increase versus the prior year period. Including hedges, the average realized oil price was $52.11 per barrel, reflecting the realization of a cash settled WTI crude oil loss of $6 million, or $9.44 per barrel. The average realized ethane price was $0.24 per gallon, or $9.93 per barrel, compared to $0.20 per gallon, or $8.40 per barrel, in the prior year period.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.35 per Mcfe, representing a 3% increase compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.77 per Mcfe, an 11% increase from the prior year period, primarily driven by higher realized liquids prices and hedge gains. Net cash settled hedge gains on all products were $96 million, or $0.42 per Mcfe.
Operating revenues in the second quarter were $989 million, compared to $790 million in the prior year period. Revenue included a $41 million non-cash loss on unsettled commodity derivatives and a $16 million non-cash gain on unsettled marketing derivatives, while the prior year included a $55 million non-cash gain on unsettled commodity derivatives. Revenue excluding gains and losses on unsettled derivatives was $1.0 billion, a 38% increase versus the prior year period. Liquids production contributed 38% of total product revenues before hedges, compared to a 30% contribution in the prior year period. Please see "Non-GAAP Financial Measures" for a description of revenue excluding unrealized derivative (gains) losses.
The following table presents a reconciliation of Stand-Alone and consolidated realized price before cash receipts for settled derivatives to Adjusted EBITDAX margin for the three months ended June 30, 2017 and 2018:
Stand-Alone |
Consolidated |
||||||||||||
Three months ended June 30, |
Three months ended June 30, |
||||||||||||
2017 |
2018 |
2017 |
2018 |
||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
|||||||||||||
Realized price before cash receipts for settled derivatives |
$ |
3.26 |
3.35 |
$ |
3.26 |
3.35 |
|||||||
Gathering, compression, and water handling and treatment revenues |
— |
— |
0.01 |
0.02 |
|||||||||
Distributions from unconsolidated affiliates |
— |
— |
0.03 |
0.05 |
|||||||||
Distributions from Antero Midstream |
0.17 |
0.18 |
— |
— |
|||||||||
Gathering, compression, processing and transportation costs |
(1.76) |
(1.79) |
(1.33) |
(1.34) |
|||||||||
Lease operating expense |
(0.09) |
(0.14) |
(0.08) |
(0.13) |
|||||||||
Marketing, net (1) |
(0.14) |
(0.30) |
(0.14) |
(0.30) |
|||||||||
Production and ad valorem taxes |
(0.11) |
(0.11) |
(0.11) |
(0.11) |
|||||||||
General and administrative (excluding equity-based compensation) |
(0.15) |
(0.15) |
(0.19) |
(0.19) |
|||||||||
Adjusted EBITDAX margin before settled commodity derivatives |
1.18 |
1.04 |
1.45 |
1.35 |
|||||||||
Cash receipts for settled commodity derivatives |
0.15 |
0.42 |
0.15 |
0.42 |
|||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
1.33 |
1.46 |
$ |
1.60 |
1.77 |
(1) |
Includes cash payments for settled marketing derivative losses of $0.07 per Mcfe in 2018. |
Stand-Alone per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) was $2.04 per Mcfe, a 4% increase compared to $1.96 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.79 per Mcfe for gathering, compression, processing and transportation costs, $0.14 per Mcfe for lease operating costs, and $0.11 per Mcfe for production and ad valorem taxes. Lease operating expenses increased in the second quarter due to an increase in produced water from newer wells that were completed with higher water intensity advanced completions.
Stand-Alone per unit net marketing expense was $0.30 per Mcfe compared to $0.14 per Mcfe reported in the prior year period. Net marketing expense increased due to higher unutilized excess capacity related to Rover pipeline capacity that was placed in service in late 2017. Net marketing expense included a $0.07 per Mcfe loss for settled marketing derivatives related to contracts that had resulted in realized gains in the first quarter of 2018. See note 11 to the condensed consolidated financial statements in Antero's Form 10-Q for more information on these contracts.
Stand-Alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.15 per Mcfe, consistent with the prior year period.
Stand-Alone Adjusted EBITDAX was $335 million for the second quarter of 2018, a 25% increase compared to $267 million in the prior year period. The increase was primarily driven by increased production and pricing. Stand-Alone Adjusted EBITDAX margin was $1.46 per Mcfe, a 10% increase from the prior year period. Consolidated Adjusted EBITDAX was $405 million, compared to $321 million in the prior year period, a 26% increase over the prior year period. Consolidated Adjusted EBITDAX margin was $1.77 per Mcfe, compared to $1.60 per Mcfe in the prior year period.
Stand-Alone net cash provided by operating activities was $229 million for the period. Stand-Alone Adjusted Operating Cash Flow was $279 million, a 36% increase over the prior year period. Consolidated net cash provided by operating activities was $297 million for the period. Consolidated Adjusted Operating Cash Flow was $335 million during the second quarter, a 34% increase compared to the prior year period. Stand-Alone Adjusted Operating Cash Flow and Adjusted Operating Cash Flow increased versus the prior year period primarily due to higher production and liquids prices during the quarter.
Operating Update
Second Quarter 2018
Marcellus Shale — Antero placed 25 horizontal Marcellus wells to sales during the second quarter of 2018 with an average lateral length of 9,500 feet and a 30-day gross average rate per well of 16.9 MMcfe/day on choke. The 30-day gross rate included 914 Bbl/d of liquids, representing oil, C3+ NGLs and 25% of the ethane that could be recovered ("25% ethane recovery"). Current average well costs are $0.86 million per 1,000 feet of lateral in the Marcellus assuming the 2018 average lateral length of 10,000 feet and 2,000 pounds of proppant per foot.
During the quarter, Antero drilled 22 wells in the Marcellus with an average lateral length of 9,600 feet in approximately 12 total days from spud to final rig release on average. Antero also set a state of West Virginia record for the longest lateral drilled to date at 15,100 lateral feet during the period. Antero completed 5.0 stages per day on average during the second quarter and achieved a record 5.5 stages per day during the month of April. Completion efficiencies improved from 4.3 stages per day in the prior quarter and exceeded the 4.5 stages per day budgeted for 2018. The trend continues with 6.5 stages per day completed on average in late July 2018. Antero recently completed its first remote completion which involved locating crews and equipment on a separate pad from the well pad, enabling improved logistics for completion operations. These operational efficiencies led to an acceleration of total stages completed during the first half of the year. As a result, Antero expects to place a total of 50 to 60 Marcellus wells to sales during the third quarter of 2018, including the Company's largest pad to date, a 14-well pad that recently commenced production in July. Because of these efficiency gains, Antero expects to release two completion crews in the coming weeks, resulting in an average of four crews operating during the second half of 2018, compared to six crews in the first half of 2018. Antero's operating plan contemplates a reduction in capital spending during the second half of the year, as compared to the first half of 2018.
Two Marcellus pads completed late in the first quarter of 2018 have now been online for more than 90 days with noteworthy gross production rates. One 9-well pad with an average lateral length of 8,300' produced a 90-day gross average rate of 157 MMcfe per day, which is on average 17.5 MMcfe/d day per well with 25% ethane recovery, including 7,715 Bbl/d of liquids. A second 3-well pad representing the most westerly wells completed on Antero's Marcellus acreage to date averaged 9,000 feet in lateral length per well and produced a 90-day gross average rate of 18.5 MMcfe/d per well with 25% ethane recovery, including 1,112 Bbl/d of liquids per well.
During the latter part of the second quarter and into the third quarter, Antero has experienced production curtailments due to tightness in the local crude trucking takeaway market. This is at present a common issue industry-wide. The Company's crude buyers have been challenged to secure an adequate number of licensed trucks and drivers to move Antero's growing crude production. The Company expects these production curtailments to be temporary in nature as Antero has recently executed direct agreements for additional trucking capacity. This additional capacity will enable Antero to lift existing curtailments as well as move the 100,000 barrel-plus crude inventory that has built up over the past couple of months. Currently, approximately 100 MMcfe/d is curtailed, including 4,000 Bbl/d of NGLs and 2,000 Bbl/d of crude oil. With truck capacity expected to match oil production beginning in September, Antero anticipates that the production curtailment will be alleviated by the fourth quarter of 2018.
Ohio Utica Shale — Antero placed five horizontal Ohio Utica wells to sales during the second quarter of 2018 with an average lateral length of approximately 15,900 feet and an average 30-day rate of 12.9 MMcfe/d per well on choke. Current average well costs are $0.95 million per 1,000 feet of lateral in the Ohio Utica assuming the 2018 average lateral length of 12,000 feet and 2,000 pounds of proppant per foot. The Company does not plan to operate any drilling rigs or completion crews in the Ohio Utica Shale during the remainder of 2018 as the second half 2018 development plan shifts to liquids-rich locations in the Marcellus due to the continued strength in liquids pricing. The Company's current five year plan does include the resumption of drilling and completion activity in the Ohio Utica Shale in 2019.
During the period, Antero drilled six wells in the Utica dry gas regime with an average lateral length of 12,900 feet in 20 total days from spud to final rig release. This represents a 4% decrease in drilling days and a 22% increase in lateral length in the Utica dry gas regime compared to 2017. In addition, Antero drilled nearly 5,200 lateral feet in a 24-hour period, which is a company record for drilled lateral footage in 24 hours in the Utica. During the second quarter, the Company completed 5.4 stages per day on average, above the 5.1 stages per day achieved during the first quarter.
During the third quarter of 2018, the Company expects to place a total of 15 wells to sales in the Utica with an average lateral length of 10,200 feet per well.
President and CFO, Glen Warren, commented, "Earlier this year, we set our sights on delivering an attractive plan of living within cash flow and reducing leverage while maintaining disciplined production growth over our five year plan. Our continued focus on strong execution has propelled us to reach drilling and completion efficiencies faster than anticipated. As a result, our full year capital spending targets remain the same, but capital is weighted toward the first half of the year and production growth is weighted toward the back half of the year. Notably, we expect to place 65 to 75 wells to sales in the third quarter, a sizeable increase from the 51 wells placed to sales in the first six months of the year. Our operational momentum gives us confidence in the execution of our operating plan for 2018 and in future years."
Second Quarter 2018 Capital Investment
Antero invested $393 million on drilling and completion capital expenditures for the three months ended June 30, 2018. In addition, the Company invested $38 million for land, $113 million for gathering and compression systems and $18 million for water infrastructure projects, including $8 million for the Antero Clearwater Treatment Facility. Antero's Stand-Alone drilling and completion capital expenditures for the three months ended June 30, 2018, were $467 million.
Balance Sheet and Liquidity
As of June 30, 2018, Antero's Stand-Alone Net Debt was $3.8 billion, of which $455 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility were $2.5 billion and the borrowing base is $4.5 billion. After deducting letters of credit outstanding, the Company had $1.4 billion in available Stand-Alone liquidity as of June 30, 2018. As of June 30, 2018, Antero's Stand-Alone Net Debt to trailing twelve months Stand-Alone Adjusted EBITDAX ratio was 2.6x.
Commodity Derivative Positions
Antero's estimated natural gas production for the second half of 2018 at the midpoint of guidance is fully hedged at an average index price of $3.49 per MMBtu. The Company's target natural gas production for 2019 is fully hedged at an average index price of $3.50 per MMBtu. In total, Antero has hedged 2.3 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from July 1, 2018, through December 31, 2023, at an average index price of $3.35 per MMBtu. As of June 30, 2018, the Company's estimated fair value of commodity derivative instruments was $1.2 billion. The following table summarizes Antero's hedge position as of June 30, 2018:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
3Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.45 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
26,000 |
$0.76 | ||
NYMEX WTI ($/Bbl) |
— |
— |
6,000 |
$56.99 | ||
4Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.53 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
26,000 |
$0.77 | ||
NYMEX WTI ($/Bbl) |
— |
— |
6,000 |
$56.99 | ||
2H 2018 Total |
2,002,500 |
$3.49 |
32,000 |
N/A (1) | ||
2019: |
||||||
NYMEX Henry Hub |
2,330,000 |
$3.50 |
— |
— | ||
2020: |
||||||
NYMEX Henry Hub |
1,417,500 |
$3.25 |
— |
— | ||
2021: |
||||||
NYMEX Henry Hub |
710,000 |
$3.00 |
— |
— | ||
2022: |
||||||
NYMEX Henry Hub |
850,000 |
$3.00 |
— |
— | ||
2023: |
||||||
NYMEX Henry Hub |
90,000 |
$2.91 |
— |
— |
(1) |
Average index price is not applicable as 2018 liquids hedges include propane and oil hedges. |
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com. A summary of the results are provided below:
Three Months Ended |
||||||
June 30, |
||||||
Average Daily Volumes: |
2017 |
2018 |
% Change | |||
Low Pressure Gathering (MMcf/d) |
1,683 |
1,981 |
18% | |||
Compression (MMcf/d) |
1,192 |
1,558 |
31% | |||
High Pressure Gathering (MMcf/d) |
1,734 |
1,932 |
11% | |||
Fresh Water Delivery (MBbl/d) |
173 |
228 |
32% | |||
Wastewater Treatment (MBbl/d) |
— |
8 |
* | |||
Gross Joint Venture Processing (MMcf/d) |
216 |
571 |
164% | |||
Gross Joint Venture Fractionation (MBbl/d) |
4,039 |
10,046 |
148% |
Net income for the second quarter of 2018 was $76 million, a 6% increase compared to the prior year quarter. Net income per limited partner unit was $0.41 per unit, a 5% increase compared to the prior year quarter. Adjusted EBITDA was $176 million, a 26% increase compared to the prior year quarter. Distributable Cash Flow was $142 million, a 30% increase over the prior year quarter, resulting in a DCF coverage ratio of 1.3x. For a description of Antero Midstream's Adjusted EBITDA and Distributable Cash Flow, and reconciliations to their nearest GAAP measures, please read "Non-GAAP Financial Measures."
Antero Midstream declared a distribution of $0.39 per limited partner unit attributable to the first quarter of 2018, resulting in $39 million of distributions received by Antero Resources from Antero Midstream during the second quarter of 2018. On July 18, 2018, Antero Midstream declared a distribution of $0.415 per limited partner unit attributable to the second quarter of 2018.
Conference Call
A conference call is scheduled on Thursday, August 2, 2018 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, August 9, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10120010.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, August 9, 2018 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the August 2, 2018 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue excluding unrealized derivative (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that revenue excluding unrealized derivative (gains) losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized derivative (gains) losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized derivative (gains) losses:
Three months ended |
|||||||
June 30, |
|||||||
2017 |
2018 |
||||||
Total operating revenue |
$ |
790,389 |
$ |
989,344 |
|||
Commodity derivative fair value gains |
(85,641) |
(55,336) |
|||||
Marketing derivative fair value losses |
— |
110 |
|||||
Gains on settled commodity derivatives |
31,064 |
95,884 |
|||||
Losses on settled marketing derivatives |
— |
(15,884) |
|||||
Revenue excluding unrealized derivative (gains) losses |
$ |
735,812 |
$ |
1,014,118 |
Adjusted Net Income (Loss) & Stand-Alone Adjusted Net Income (Loss)
Adjusted net income (loss) as set forth in this release represents net income, adjusted for certain items. Stand-Alone adjusted net income (loss) as presented in this release represents net income that will be reported in the Parent column of Antero's guarantor footnote to its financial statements, adjusted for certain items. Antero believes that adjusted net income (loss) is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income (loss) and Stand-Alone adjusted net income (loss) are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance. The following table reconciles net (loss) to adjusted net income (loss) and Stand-Alone net (loss) to Stand-Alone adjusted net (loss) (in thousands):
Stand-Alone |
Consolidated |
|||||||||||
Three months ended |
Three months ended |
|||||||||||
June 30, |
June 30, |
|||||||||||
2017 |
2018 |
2017 |
2018 |
|||||||||
Net (loss) |
$ |
(5,132) |
$ |
(136,385) |
$ |
(5,132) |
$ |
(136,385) |
||||
Commodity derivative fair value gains |
(85,641) |
(55,336) |
(85,641) |
(55,336) |
||||||||
Gains on settled commodity derivatives |
31,064 |
95,884 |
31,064 |
95,884 |
||||||||
Marketing derivative fair value losses |
— |
110 |
— |
110 |
||||||||
Losses on settled marketing derivatives |
— |
(15,884) |
— |
(15,884) |
||||||||
Impairment of unproved properties |
15,199 |
134,437 |
15,199 |
134,437 |
||||||||
Impairment of gathering systems and facilities |
— |
4,470 |
— |
8,501 |
||||||||
Equity-based compensation |
20,024 |
13,204 |
26,975 |
19,071 |
||||||||
Income tax effect of reconciling items |
7,323 |
(42,214) |
4,693 |
(44,577) |
||||||||
Adjusted net income (loss) |
$ |
(17,163) |
$ |
(1,714) |
$ |
(12,842) |
$ |
5,821 |
Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow
Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items. Stand-Alone Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Management believes that Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-Alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.
There are significant limitations to using Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Operating Cash Flow is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to Adjusted Operating Cash Flow as used in this release (in thousands):
Stand-Alone |
Consolidated |
||||||||||||
Three months ended |
Three months ended |
||||||||||||
June 30, |
June 30, |
||||||||||||
2017 |
2018 |
2017 |
2018 |
||||||||||
Net cash provided by operating activities |
$ |
202,460 |
228,503 |
$ |
253,647 |
297,391 |
|||||||
Net change in working capital |
2,420 |
50,513 |
(2,853) |
37,803 |
|||||||||
Adjusted Operating Cash Flow |
$ |
204,880 |
279,016 |
$ |
250,794 |
335,194 |
Total Debt and Net Debt
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, |
June 30, |
||||||
2017 |
2018 |
||||||
AR bank credit facility |
$ |
185,000 |
455,000 |
||||
AM bank credit facility |
555,000 |
770,000 |
|||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 |
|||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 |
|||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 |
|||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 |
|||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 |
|||||
Net unamortized premium |
1,520 |
1,382 |
|||||
Net unamortized debt issuance costs |
(41,430) |
(38,038) |
|||||
Consolidated total debt |
$ |
4,800,090 |
5,288,344 |
||||
Less: AR cash and cash equivalents |
20,078 |
31,083 |
|||||
Less: AM cash and cash equivalents |
8,363 |
19,525 |
|||||
Consolidated Net Debt |
$ |
4,771,649 |
5,237,736 |
||||
Stand-Alone Net Debt |
$ |
3,584,012 |
3,845,695 |
Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-Alone Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. The GAAP financial measure nearest to Stand-Alone Adjusted EBITDAX is Stand-Alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Stand-Alone |
Consolidated |
||||||||||||
Three months ended June 30, |
Three months ended June 30, |
||||||||||||
(in thousands) |
2017 |
2018 |
2017 |
2018 |
|||||||||
Net income (loss) including noncontrolling interest |
$ |
(5,132) |
(136,385) |
$ |
39,965 |
(67,275) |
|||||||
Commodity derivative fair value gains |
(85,641) |
(55,336) |
(85,641) |
(55,336) |
|||||||||
Gains on settled commodity derivatives |
31,064 |
95,884 |
31,064 |
95,884 |
|||||||||
Marketing derivative fair value losses |
— |
110 |
— |
110 |
|||||||||
Losses on settled marketing derivatives |
— |
(15,884) |
— |
(15,884) |
|||||||||
Interest expense |
59,735 |
54,388 |
68,582 |
69,349 |
|||||||||
Income tax expense (benefit) |
18,819 |
(25,573) |
18,819 |
(25,573) |
|||||||||
Depletion, depreciation, amortization, and accretion |
171,319 |
202,283 |
201,831 |
238,750 |
|||||||||
Impairment of unproved properties |
15,199 |
134,437 |
15,199 |
134,437 |
|||||||||
Impairment of gathering systems and facilities |
— |
4,470 |
— |
8,501 |
|||||||||
Exploration expense |
1,804 |
1,471 |
1,804 |
1,471 |
|||||||||
Gain on change in fair value of contingent acquisition consideration |
(3,590) |
(3,947) |
— |
— |
|||||||||
Equity-based compensation expense |
20,024 |
13,204 |
26,975 |
19,071 |
|||||||||
Equity in earnings of unconsolidated affiliates |
— |
— |
(3,623) |
(9,264) |
|||||||||
Distributions from unconsolidated affiliates |
— |
— |
5,820 |
10,810 |
|||||||||
Equity in (earnings) loss of Antero Midstream Partners LP |
10,408 |
26,926 |
— |
— |
|||||||||
Distributions from Antero Midstream Partners LP |
32,661 |
38,559 |
— |
— |
|||||||||
Adjusted EBITDAX |
266,670 |
334,607 |
320,795 |
405,051 |
|||||||||
Interest expense |
(59,735) |
(54,388) |
(68,582) |
(69,349) |
|||||||||
Exploration expense |
(1,804) |
(1,471) |
(1,804) |
(1,471) |
|||||||||
Changes in current assets and liabilities |
(2,420) |
(50,513) |
2,853 |
(37,803) |
|||||||||
Other non-cash items |
(251) |
268 |
385 |
963 |
|||||||||
Net cash provided by operating activities |
$ |
202,460 |
228,503 |
$ |
253,647 |
297,391 |
The following table reconciles Antero's Stand-Alone net income to Adjusted EBITDAX for the twelve months ending June 30, 2018, as used in this release (in thousands):
Stand-Alone |
|||||
Twelve months ended June 30, |
|||||
(in thousands) |
2018 |
||||
Net income including noncontrolling interest |
$ |
230,254 |
|||
Commodity derivative fair value gains |
(211,640) |
||||
Gains on settled commodity derivatives |
335,252 |
||||
Marketing derivative fair value gains |
(72,730) |
||||
Gains on settled marketing derivatives |
94,158 |
||||
Interest expense |
222,479 |
||||
Loss on early extinguishment of debt |
1,205 |
||||
Income tax benefit |
(461,669) |
||||
Depletion, depreciation, amortization, and accretion |
759,260 |
||||
Impairment of unproved properties |
302,473 |
||||
Impairment of gathering systems and facilities |
4,470 |
||||
Exploration expense |
7,983 |
||||
Gain on change in fair value of contingent acquisition consideration |
(14,181) |
||||
Equity-based compensation expense |
65,070 |
||||
Equity in (earnings) loss of Antero Midstream |
74,056 |
||||
Distributions from Antero Midstream |
143,100 |
||||
Adjusted EBITDAX |
$ 1,479,540 |
Antero Midstream Adjusted EBITDA & Distributable Cash Flow
Antero Midstream views Adjusted EBITDA as an important indicator of its performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, gain on sale of assets, depreciation expense, impairment expense, accretion, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Three Months Ended June 30, |
|||||||||
2017 |
2018 |
||||||||
Net income |
$ |
87,175 |
109,466 |
||||||
Interest expense |
9,015 |
14,628 |
|||||||
Impairment of property and equipment expense |
— |
4,614 |
|||||||
Depreciation expense |
30,512 |
36,433 |
|||||||
Gain on sale of assets |
— |
(583) |
|||||||
Accretion of contingent acquisition consideration |
3,590 |
3,947 |
|||||||
Accretion of asset retirement obligations |
— |
34 |
|||||||
Equity-based compensation |
6,951 |
5,867 |
|||||||
Equity in earnings of unconsolidated affiliates |
(3,623) |
(9,264) |
|||||||
Distributions from unconsolidated affiliates |
5,820 |
10,810 |
|||||||
Adjusted EBITDA |
139,440 |
175,952 |
|||||||
Interest paid |
(2,308) |
(6,270) |
|||||||
Decrease in cash reserved for bond interest (1) |
(8,734) |
(8,734) |
|||||||
Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards (2) |
(2,431) |
(1,500) |
|||||||
Maintenance capital expenditures (3) |
(16,422) |
(17,289) |
|||||||
Distributable Cash Flow |
$ |
109,545 |
142,159 |
||||||
Distributions Declared to Antero Midstream Holders |
|||||||||
Limited Partners |
$ |
59,695 |
77,624 |
||||||
Incentive distribution rights |
15,328 |
33,137 |
|||||||
Total Aggregate Distributions |
$ |
75,023 |
110,762 |
||||||
DCF coverage ratio |
1.46x |
1.28x |
|||||||
(1) |
Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. |
(2) |
Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter. |
(3) |
Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Stand-Alone Adjusted EBITDAX, Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Balance Sheets | |||||||
December 31, 2017 and June 30, 2018 | |||||||
(unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
December 31, 2017 |
June 30, 2018 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
28,441 |
50,608 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,320 at December 31, 2017 and $1,195 at June 30, 2018, respectively |
34,896 |
35,676 |
|||||
Accrued revenue |
300,122 |
321,214 |
|||||
Derivative instruments |
460,685 |
420,842 |
|||||
Other current assets |
8,943 |
6,590 |
|||||
Total current assets |
833,087 |
834,930 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
2,266,673 |
2,108,109 |
|||||
Proved properties |
11,096,462 |
11,924,864 |
|||||
Water handling and treatment systems |
946,670 |
979,937 |
|||||
Gathering systems and facilities |
2,050,490 |
2,255,385 |
|||||
Other property and equipment |
57,429 |
60,766 |
|||||
16,417,724 |
17,329,061 |
||||||
Less accumulated depletion, depreciation, and amortization |
(3,182,171) |
(3,647,910) |
|||||
Property and equipment, net |
13,235,553 |
13,681,151 |
|||||
Derivative instruments |
841,257 |
763,592 |
|||||
Investments in unconsolidated affiliates |
303,302 |
358,830 |
|||||
Other assets |
48,291 |
52,104 |
|||||
Total assets |
$ |
15,261,490 |
15,690,607 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
62,982 |
96,477 |
||||
Accrued liabilities |
443,225 |
438,829 |
|||||
Revenue distributions payable |
209,617 |
211,234 |
|||||
Derivative instruments |
28,476 |
30,661 |
|||||
Other current liabilities |
17,796 |
11,532 |
|||||
Total current liabilities |
762,096 |
788,733 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,800,090 |
5,288,344 |
|||||
Deferred income tax liability |
779,645 |
763,192 |
|||||
Derivative instruments |
207 |
— |
|||||
Other liabilities |
43,316 |
47,427 |
|||||
Total liabilities |
6,385,354 |
6,887,696 |
|||||
Commitments and contingencies (notes 12 and 13) |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 317,052 shares issued and outstanding at December 31, 2017 and June 30, 2018, respectively |
3,164 |
3,171 |
|||||
Additional paid-in capital |
6,570,952 |
6,597,537 |
|||||
Accumulated earnings |
1,575,065 |
1,453,513 |
|||||
Total stockholders' equity |
8,149,181 |
8,054,221 |
|||||
Noncontrolling interests in consolidated subsidiary |
726,955 |
748,690 |
|||||
Total equity |
8,876,136 |
8,802,911 |
|||||
Total liabilities and equity |
$ |
15,261,490 |
15,690,607 |
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Statements of Operations and Comprehensive Loss | |||||||
Three Months Ended June 30, 2017 and 2018 | |||||||
(unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
Three Months Ended June 30, |
|||||||
2017 |
2018 |
||||||
Revenue: |
|||||||
Natural gas sales |
$ |
454,257 |
473,540 |
||||
Natural gas liquids sales |
170,819 |
255,985 |
|||||
Oil sales |
26,512 |
38,873 |
|||||
Commodity derivative fair value gains |
85,641 |
55,336 |
|||||
Gathering, compression, water handling and treatment |
3,192 |
5,518 |
|||||
Marketing |
49,968 |
160,202 |
|||||
Marketing derivative fair value losses |
— |
(110) |
|||||
Total revenue |
790,389 |
989,344 |
|||||
Operating expenses: |
|||||||
Lease operating |
16,992 |
30,164 |
|||||
Gathering, compression, processing, and transportation |
266,747 |
307,786 |
|||||
Production and ad valorem taxes |
22,553 |
25,891 |
|||||
Marketing |
77,421 |
213,420 |
|||||
Exploration |
1,804 |
1,471 |
|||||
Impairment of unproved properties |
15,199 |
134,437 |
|||||
Impairment of gathering systems and facilities |
— |
8,501 |
|||||
Depletion, depreciation, and amortization |
201,182 |
238,050 |
|||||
Accretion of asset retirement obligations |
649 |
700 |
|||||
General and administrative (including equity-based compensation expense of $26,975 and $19,071 in 2017 and 2018, respectively) |
64,099 |
61,687 |
|||||
Total operating expenses |
666,646 |
1,022,107 |
|||||
Operating income (loss) |
123,743 |
(32,763) |
|||||
Other income (expenses): |
|||||||
Equity in earnings of unconsolidated affiliates |
3,623 |
9,264 |
|||||
Interest |
(68,582) |
(69,349) |
|||||
Total other expenses |
(64,959) |
(60,085) |
|||||
Income (loss) before income taxes |
58,784 |
(92,848) |
|||||
Provision for income tax (expense) benefit |
(18,819) |
25,573 |
|||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
39,965 |
(67,275) |
|||||
Net income and comprehensive income attributable to noncontrolling interests |
45,097 |
69,110 |
|||||
Net loss and comprehensive loss attributable to Antero Resources Corporation |
$ |
(5,132) |
(136,385) |
||||
Loss per common share—basic |
$ |
(0.02) |
(0.43) |
||||
Loss per common share—assuming dilution |
$ |
(0.02) |
(0.43) |
||||
Weighted average number of shares outstanding: |
|||||||
Basic |
315,401 |
316,992 |
|||||
Diluted |
315,401 |
316,992 |
ANTERO RESOURCES CORPORATION | |||||||||||
Condensed Consolidated Statements of Cash Flows | |||||||||||
Six Months Ended June 30, 2017 and 2018 | |||||||||||
(unaudited) | |||||||||||
(In thousands) | |||||||||||
Six Months Ended June 30, |
|||||||||||
2017 |
2018 |
||||||||||
Cash flows provided by (used in) operating activities: |
|||||||||||
Net income including noncontrolling interests |
$ |
345,523 |
13,535 |
||||||||
Adjustments to reconcile net income to net cash provided by operating activities: |
|||||||||||
Depletion, depreciation, amortization, and accretion |
405,197 |
467,684 |
|||||||||
Impairment of unproved properties |
42,098 |
184,973 |
|||||||||
Impairment of gathering systems and facilities |
— |
8,501 |
|||||||||
Commodity derivative fair value gains |
(524,416) |
(77,773) |
|||||||||
Gains on settled commodity derivatives |
75,913 |
197,225 |
|||||||||
Marketing derivative fair value gains |
— |
(94,124) |
|||||||||
Gains on settled marketing derivatives |
— |
94,158 |
|||||||||
Deferred income tax expense (benefit) |
150,165 |
(16,453) |
|||||||||
Equity-based compensation expense |
52,478 |
40,227 |
|||||||||
Equity in earnings of unconsolidated affiliates |
(5,854) |
(17,126) |
|||||||||
Distributions of earnings from unconsolidated affiliates |
5,820 |
17,895 |
|||||||||
Other |
472 |
1,932 |
|||||||||
Changes in current assets and liabilities: |
|||||||||||
Accounts receivable |
13,188 |
10,237 |
|||||||||
Accrued revenue |
43,339 |
(21,092) |
|||||||||
Other current assets |
(2,385) |
2,353 |
|||||||||
Accounts payable |
2,072 |
2,948 |
|||||||||
Accrued liabilities |
4,204 |
24,065 |
|||||||||
Revenue distributions payable |
39,162 |
1,617 |
|||||||||
Other current liabilities |
610 |
(1,842) |
|||||||||
Net cash provided by operating activities |
647,586 |
838,940 |
|||||||||
Cash flows used in investing activities: |
|||||||||||
Additions to proved properties |
(179,318) |
— |
|||||||||
Additions to unproved properties |
(129,876) |
(87,861) |
|||||||||
Drilling and completion costs |
(629,308) |
(752,781) |
|||||||||
Additions to water handling and treatment systems |
(95,451) |
(58,127) |
|||||||||
Additions to gathering systems and facilities |
(155,365) |
(206,753) |
|||||||||
Additions to other property and equipment |
(6,564) |
(3,502) |
|||||||||
Investments in unconsolidated affiliates |
(191,364) |
(56,297) |
|||||||||
Change in other assets |
(12,452) |
(7,026) |
|||||||||
Other |
2,156 |
— |
|||||||||
Net cash used in investing activities |
(1,397,542) |
(1,172,347) |
|||||||||
Cash flows provided by (used in) financing activities: |
|||||||||||
Issuance of common units by Antero Midstream Partners LP |
246,585 |
— |
|||||||||
Borrowings on bank credit facilities, net |
585,000 |
485,000 |
|||||||||
Distributions to noncontrolling interests in consolidated subsidiary |
(61,869) |
(119,023) |
|||||||||
Employee tax withholding for settlement of equity compensation awards |
(8,433) |
(7,967) |
|||||||||
Other |
(2,747) |
(2,436) |
|||||||||
Net cash provided by financing activities |
758,536 |
355,574 |
|||||||||
Net increase in cash and cash equivalents |
8,580 |
22,167 |
|||||||||
Cash and cash equivalents, beginning of period |
31,610 |
28,441 |
|||||||||
Cash and cash equivalents, end of period |
$ |
40,190 |
50,608 |
||||||||
Supplemental disclosure of cash flow information: |
|||||||||||
Cash paid during the period for interest |
$ |
125,284 |
130,231 |
||||||||
Increase in accounts payable and accrued liabilities for additions to property and equipment |
$ |
31,182 |
2,089 |
||||||||
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended June 30, 2017 and 2018:
Three Months Ended June 30, |
Amount of Increase |
Percent |
||||||||||
(in thousands) |
2017 |
2018 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
454,257 |
$ |
473,540 |
$ |
19,283 |
4 |
% | ||||
NGLs sales |
170,819 |
255,985 |
85,166 |
50 |
% | |||||||
Oil sales |
26,512 |
38,873 |
12,361 |
47 |
% | |||||||
Commodity derivative gains |
85,641 |
55,336 |
(30,305) |
(35) |
% | |||||||
Gathering, compression, water handling and treatment |
3,192 |
5,518 |
2,326 |
73 |
% | |||||||
Marketing |
49,968 |
160,202 |
110,234 |
221 |
% | |||||||
Marketing derivative loss |
— |
(110) |
(110) |
* |
||||||||
Total operating revenues and other |
790,389 |
989,344 |
198,955 |
25 |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
16,992 |
30,164 |
13,172 |
78 |
% | |||||||
Gathering, compression, processing, and transportation |
266,747 |
307,786 |
41,039 |
15 |
% | |||||||
Production and ad valorem taxes |
22,553 |
25,891 |
3,338 |
15 |
% | |||||||
Marketing |
77,421 |
213,420 |
135,999 |
176 |
% | |||||||
Exploration |
1,804 |
1,471 |
(333) |
(18) |
% | |||||||
Impairment of unproved properties |
15,199 |
134,437 |
119,238 |
785 |
% | |||||||
Impairment of gathering systems and facilities |
— |
8,501 |
8,501 |
* |
||||||||
Depletion, depreciation, and amortization |
201,182 |
238,050 |
36,868 |
18 |
% | |||||||
Accretion of asset retirement obligations |
649 |
700 |
51 |
8 |
% | |||||||
General and administrative (before equity-based compensation) |
37,124 |
42,616 |
5,492 |
15 |
% | |||||||
Equity-based compensation |
26,975 |
19,071 |
(7,904) |
(29) |
% | |||||||
Total operating expenses |
666,646 |
1,022,107 |
355,461 |
53 |
% | |||||||
Operating income (loss) |
123,743 |
(32,763) |
(156,506) |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
3,623 |
9,264 |
5,641 |
156 |
% | |||||||
Interest expense |
(68,582) |
(69,349) |
(767) |
1 |
% | |||||||
Total other expenses |
(64,959) |
(60,085) |
4,874 |
(8) |
% | |||||||
Income (loss) before income taxes |
58,784 |
(92,848) |
(151,632) |
* |
||||||||
Income tax (expense) benefit |
(18,819) |
25,573 |
44,392 |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
39,965 |
(67,275) |
(107,240) |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
45,097 |
69,110 |
24,013 |
53 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(5,132) |
$ |
(136,385) |
$ |
(131,253) |
2,558 |
% | ||||
Adjusted EBITDAX |
$ |
320,795 |
$ |
405,051 |
$ |
84,256 |
26 |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
144 |
167 |
23 |
16 |
% | |||||||
C2 Ethane (MBbl) |
2,548 |
3,290 |
742 |
29 |
% | |||||||
C3+ NGLs (MBbl) |
6,190 |
6,414 |
224 |
4 |
% | |||||||
Oil (MBbl) |
613 |
632 |
19 |
3 |
% | |||||||
Combined (Bcfe) |
200 |
229 |
29 |
15 |
% | |||||||
Daily combined production (MMcfe/d) |
2,200 |
2,520 |
320 |
15 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
3.15 |
$ |
2.83 |
$ |
(0.32) |
(10) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.40 |
$ |
9.93 |
$ |
1.53 |
18 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
24.14 |
$ |
34.81 |
$ |
10.67 |
44 |
% | ||||
Oil (per Bbl) |
$ |
43.24 |
$ |
61.55 |
$ |
18.31 |
42 |
% | ||||
Weighted Average Combined (per Mcfe) |
$ |
3.26 |
$ |
3.35 |
$ |
0.09 |
3 |
% | ||||
Average realized prices after effects of derivative settlements(2): |
||||||||||||
Natural gas (per Mcf) |
$ |
3.53 |
$ |
3.50 |
$ |
(0.03) |
(1) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.61 |
$ |
9.93 |
$ |
1.32 |
15 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
19.92 |
$ |
33.10 |
$ |
13.18 |
66 |
% | ||||
Oil (per Bbl) |
$ |
46.12 |
$ |
52.11 |
$ |
5.99 |
13 |
% | ||||
Weighted Average Combined (per Mcfe) |
$ |
3.41 |
$ |
3.77 |
$ |
0.36 |
11 |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.13 |
$ |
0.05 |
63 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.33 |
$ |
1.34 |
$ |
0.01 |
1 |
% | ||||
Production and ad valorem taxes |
$ |
0.11 |
$ |
0.11 |
$ |
— |
— |
% | ||||
Marketing expense (gain), net |
$ |
0.14 |
$ |
0.23 |
$ |
0.09 |
64 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.01 |
$ |
1.04 |
$ |
0.03 |
3 |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.19 |
$ |
0.19 |
$ |
— |
— |
% |
*Not meaningful or applicable |
View original content with multimedia:http://www.prnewswire.com/news-releases/antero-resources-reports-second-quarter-2018-financial-and-operational-results-300690560.html
SOURCE Antero Resources Corporation
DENVER, April 25, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its first quarter 2018 financial and operating results. The relevant consolidated and consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, which has been filed with the Securities and Exchange Commission ("SEC"). The relevant Stand-Alone financial statements are also included in Antero's Form 10-Q within the Parent column of the guarantor footnote (Note 16).
First Quarter 2018 Highlights:
Commenting on the quarter, Paul Rady, Chairman and CEO said, "We are off to a strong start in 2018 with record first quarter results that delivered strong cash flow growth during the quarter. This included a net marketing gain, and reduced leverage from year-end levels. We continued to achieve strong operational execution with fewer drilling days per well and higher completion stages per day during the quarter than forecast. Furthermore, the ongoing liquids focus in the Marcellus and strong production performance in the Utica Shale during the quarter boosted results. We continue to execute on the plan we laid out at the beginning of the year targeting strong cash flow generation and debt reduction over the next several years."
Financial and operational results are reported and discussed on a consolidated basis, unless otherwise noted. Please read "Non-GAAP Financial Measures" for:
Please read "First Quarter 2018 Financial Results" for a reconciliation of consolidated and Stand-Alone adjusted EBITDAX margin to realized price before cash receipts for settled hedges, the most comparable GAAP measure.
First Quarter 2018 Financial Results
As of March 31, 2018, Antero owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated within Antero's results.
Antero reported first quarter net income of $15 million, or $0.05 per diluted share, compared to net income of $268 million, or $0.85 per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," first quarter adjusted net income was $141 million, or $0.44 per diluted share, compared to $56 million, or $0.18 per diluted share, in the prior year period. First quarter Stand-Alone adjusted net income was $136 million compared to $52 million in the prior year period. Adjusted EBITDAX was $551 million, compared to $365 million in the prior year period, and Stand-Alone adjusted EBITDAX was $488 million, compared to $321 million in the prior year period. First quarter 2018 results include settled marketing derivatives of $110 million, resulting in an overall gain of $94 million, net of unrealized losses.
The following table details the components of average net production and average realized prices for the three months ended March 31, 2018:
Three Months Ended March 31, 2018 |
||||||||||||||||
Natural Gas |
Oil (Bbl/d) |
C3+ NGLs |
Ethane |
Combined |
||||||||||||
Average Net Production |
1,759 |
5,887 |
63,252 |
33,659 |
2,376 |
|||||||||||
Average Realized Prices |
Natural Gas |
Oil ($/Bbl) |
C3+ NGLs |
Ethane |
Combined |
|||||||||||
Average realized prices before settled derivatives |
$ |
3.14 |
$ |
57.14 |
$ |
36.38 |
$ |
8.94 |
$ |
3.56 |
||||||
Settled commodity derivatives |
0.71 |
(6.02) |
(1.21) |
— |
0.48 |
|||||||||||
Average realized prices after settled derivatives |
$ |
3.85 |
$ |
51.12 |
$ |
35.17 |
$ |
8.94 |
$ |
4.04 |
||||||
NYMEX average price |
$ |
3.00 |
$ |
62.88 |
$ |
3.00 |
||||||||||
Premium / (Differential) to NYMEX |
$ |
0.85 |
$ |
(11.76) |
$ |
1.04 |
Net daily natural gas equivalent production in the first quarter averaged 2,376 MMcfe/d, including 102,798 Bbl/d of liquids (26% liquids), representing an organic growth rate of 11% versus the prior year period and a 1% increase sequentially. Natural gas production averaged 1,759 MMcf/d (average BTU of 1094), C3+ NGLs production averaged 63,252 Bbl/d, oil production averaged 5,887 Bbl/d, and recovered ethane production averaged 33,659 Bbl/d. Total liquids production grew 4% versus the prior year period and declined 4% sequentially. The sequential decline in liquids production from the fourth quarter of 2017 was a result of the impact of winter weather and downtime associated with processing plants. Liquids revenue represented approximately 35% of total product revenue before hedges, an increase from 32% of total product revenue in the prior year period.
Antero's average realized natural gas price before hedging was $3.14 per Mcf, a $0.14 per Mcf premium to the average NYMEX price during the period. Including hedges, Antero's average realized natural gas price was $3.85 per Mcf, an $0.85 premium to the NYMEX average price, reflecting the realization of a cash settled natural gas hedge gain of $111 million or $0.71 per Mcf. Based on current strip prices, Antero's full year realized natural gas prices are trending toward the high end of its guidance range of a $0.00 to $0.05 per Mcf premium to NYMEX before hedges.
Antero's average realized C3+ NGL price before hedging was $36.38 per barrel, or 58% of the average NYMEX WTI oil price, representing a 23% increase versus the prior year period. Including hedges, Antero's average realized C3+ NGL price was $35.17 per barrel, a 46% increase versus the prior year period, reflecting the realization of a cash settled C3+ hedge loss of $7 million or $1.21 per barrel. Based on current strip prices, Antero is trending toward the low end of its 62.5% to 67.5% guidance range for C3+ NGL realized prices as a percentage of WTI, as oil prices have risen but C3+ NGL strip prices have remained consistent relative to year-end 2017 levels.
Antero's average realized oil price before hedging was $57.14 per barrel, a $5.74 negative differential to average NYMEX WTI and a 36% increase versus the prior year period. Including hedges, the average realized oil price was $51.12 per barrel, an $11.76 differential to average NYMEX WTI. The average realized ethane price was $0.21 per gallon, or $8.94 per barrel.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.56 per Mcfe, in line with the prior year period. Including hedges, the Company's average natural gas equivalent price was $4.04 per Mcfe, a 6% increase from the prior year period, primarily driven by higher realized natural gas hedge gains and lower C3+ hedge losses compared to the prior year period. Net cash settled hedge gains on all products were $101 million, or $0.48 per Mcfe.
Operating revenues in the first quarter were $1.028 billion compared to $1.196 billion in the prior year period. Revenue included a $79 million non-cash loss on unsettled hedges and a $16 million non-cash loss on unsettled marketing derivatives, while the prior year included a $394 million non-cash gain on unsettled hedges. Revenue excluding unrealized derivative losses was $1.123 billion, a 40% increase versus the prior year period. Liquids production contributed 35% of total product revenues before hedges, compared to a 32% contribution in the prior year period. Please see "Non-GAAP Financial Measures" for a description of revenue excluding the unrealized hedge gain and unrealized marketing derivative loss.
The following table presents a reconciliation of realized price before cash receipts for settled hedges to Stand-Alone and consolidated adjusted EBITDAX margin for the three months ended March 31, 2017 and 2018:
Stand-Alone |
Consolidated | ||||||||||
Three months ended March 31, |
Three months ended March 31, | ||||||||||
2017 |
2018 |
2017 |
2018 | ||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
|||||||||||
Realized price before cash receipts for settled derivatives |
$ |
3.57 |
3.56 |
$ |
3.57 |
3.56 | |||||
Gathering, compression, and water handling and treatment revenues |
N/A |
N/A |
— |
0.03 | |||||||
Distributions from unconsolidated affiliates |
N/A |
N/A |
— |
0.03 | |||||||
Distributions from Antero Midstream |
0.14 |
0.19 |
N/A |
N/A | |||||||
Gathering, compression, processing and transportation costs |
(1.80) |
(1.80) |
(1.38) |
(1.37) | |||||||
Lease operating expense |
(0.08) |
(0.15) |
(0.08) |
(0.12) | |||||||
Marketing, net (1) |
(0.12) |
0.27 |
(0.12) |
0.27 | |||||||
Production and ad valorem taxes |
(0.12) |
(0.12) |
(0.13) |
(0.12) | |||||||
General and administrative (excluding equity-based compensation) |
(0.16) |
(0.15) |
(0.20) |
(0.18) | |||||||
Adjusted EBITDAX margin before settled hedges |
1.43 |
1.80 |
1.66 |
2.10 | |||||||
Cash receipts for settled hedges |
0.23 |
0.48 |
0.23 |
0.48 | |||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
1.66 |
2.28 |
$ |
1.89 |
2.58 |
(1) |
Includes cash receipts for settled marketing derivative gains. |
Stand-Alone per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) was $2.07 per Mcfe, a 4% increase compared to $2.00 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $0.15 per Mcfe for lease operating costs, $1.80 per Mcfe for gathering, compression, processing and transportation costs and $0.12 per Mcfe for production and ad valorem taxes. The increase in lease operating expenses to $0.15 per Mcfe in the first quarter is due to an increase in produced water on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions throughout the year.
Stand-Alone per unit net marketing gains were $0.27 per Mcfe compared to a net marketing expense of $0.12 per Mcfe reported in the prior year period. As a result of severe cold weather in January that drove wide basis premiums at the index for certain contracts, the Company was able to sell previously purchased gas at a large premium resulting in a realized gain on settled marketing derivatives of $110 million during the three months ended March 31, 2018. For the period of April through October, 2018, Antero expects to realize a loss on settled marketing derivatives of $37 million related to these contracts. See note 11 to the condensed consolidated financial statements in Antero's Form 10-Q for more information on these contracts.
Stand-Alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.15 per Mcfe, a 6% decrease from the prior year period.
Stand-Alone Adjusted EBITDAX was $488 million for the first quarter of 2018, compared to $321 million in the prior year period. Stand-Alone adjusted EBITDAX margin was $1.80 per Mcfe before settled hedges, a 26% increase from the prior year period. Stand-Alone adjusted EBITDAX margin including hedges was $2.28 per Mcfe, a 37% increase from the prior year period. Adjusted EBITDAX was $551 million, compared to $365 million in the prior year period. Adjusted EBITDAX margin was $2.10 per Mcfe before settled hedges and $2.58 per Mcfe including settled hedges, compared to $1.66 per Mcfe and $1.89 per Mcfe, respectively, in the prior year period.
Stand-Alone net cash provided by operating activities was $498 million for the period. Stand-Alone Adjusted Operating Cash Flow was $433 million, a 66% increase over the prior year period. Net cash provided by operating activities was $542 million for the period. Adjusted Operating Cash Flow was $485 million during the first quarter, a 64% increase compared to the prior year period. Stand-Alone Adjusted Operating Cash Flow and Adjusted Operating Cash Flow increased versus the prior year period primarily due to higher production, liquids pricing after hedges, and net marketing gains realized during the quarter.
President and CFO Glen Warren commented, "Due to our comprehensive focus on capital efficiency and deleveraging including our hedge and asset monetization program last fall, our Stand-Alone financial leverage declined to 2.5x at quarter end. We are focused on executing our 2018 operational and financial plan, and are on track to deliver attractive debt-adjusted production per share growth, while living within cash flow and further reducing leverage."
Operating Update
First Quarter 2018
Marcellus Shale — Antero completed and placed on line 16 horizontal Marcellus wells during the first quarter of 2018 with an average lateral length of 9,100' and a 30-day rate of 19.8 MMcfe/d (with 25% ethane recovery) on choke. Current average well costs are $0.85 million per 1,000' of lateral in the Marcellus assuming the 2018 average lateral length of 10,000' and 2,000 pounds of proppant per foot completion. Antero plans to operate five drilling rigs and four completion crews in the Marcellus Shale play during 2018.
Notable drilling and completion efficiency gains were achieved during the quarter, despite severe winter weather disruptions at times. During the period, Antero drilled an average of over 4,700 feet per day when drilling in the lateral section of the well, which represents a 4% increase compared to full year 2017. In addition, in one well Antero drilled 8,206 lateral feet in a 24 hour period, the Company record lateral footage for a 24-hour period. Average drilling days from spud to final rig release were 11.5 days in the first quarter of 2018, a 6% reduction from the full year 2017. The Company completed 4.3 stages per day on average during the first quarter, improving to 5.1 in the month of March as weather factors abated, levels which exceeded the 4.1 stages per day average from the fourth quarter of 2017 and the 4.5 stages per day budgeted for 2018. Antero also completed its longest Marcellus lateral to date at nearly 14,400' during the period.
The Company is preparing to commence production on its two largest Marcellus pads to date. One 12-well pad has a planned combined total of 120,000 lateral feet and the other 12-well pad has 106,000 lateral feet. Antero expects to place these 24 wells to sales within the month, with expected production at a combined 90-day gross rate of 350 to 400 MMcfe per day, on choke, including over 20,000 barrels per day of liquids.
Ohio Utica Shale — Antero placed five horizontal Ohio Utica wells to sales during the first quarter of 2018 with an average lateral length of approximately 11,000 feet. During the period, Antero drilled four wells with an average lateral length of 9,200 feet in 15.5 total days from spud to final rig release, which represents a 7% decrease in drilling days compared to 2016 where wells were drilled at a similar lateral length.
Current average well costs are $0.91 million per 1,000 feet of lateral in the Ohio Utica assuming the 2018 average lateral length of 12,000' and a 2,000 pound proppant per foot completion. Antero plans to operate one drilling rig and one completion crew in the Ohio Utica Shale during 2018.
During the quarter, Antero commenced completion operations on five wells in Ohio, including four wells each at 17,400' in lateral length. These wells represent Antero's longest wells drilled and completed to date, and are expected to be placed to sales next month. In addition, average stages per day were 5.1 during the quarter, significantly above the 3.7 stages per day achieved during the fourth quarter of 2017.
Antero turned 10 wells to sales in December 2017 with an average lateral length of 10,200' each that represented its first wells completed in the Ohio Utica dry gas regime. These wells have produced over 24 Bcf of dry gas to date (20 MMcf/d average per well) and have not yet begun to decline after approximately 130 days on line.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com. A summary of the results are provided below:
Three Months Ended |
|||||
Average Daily Volumes: |
2017 |
2018 |
% | ||
Low Pressure Gathering (MMcf/d) |
1,659 |
1,835 |
11% | ||
Compression (MMcf/d) |
1,028 |
1,413 |
37% | ||
High Pressure Gathering (MMcf/d) |
1,581 |
1,765 |
12% | ||
Fresh Water Delivery (MBbl/d) |
148 |
221 |
49% | ||
Gross Joint Venture Processing (MMcf/d) |
52 |
519 |
905% | ||
Gross Joint Venture Fractionation (Bbl/d) |
722 |
6,189 |
754% |
Net income for the first quarter of 2018 was $108 million, a 44% increase compared to the prior year quarter. The increase in net income was driven by growth in throughput and fresh water delivery volumes. Net income per limited partner unit was $0.43 per unit, a 23% increase compared to the prior year quarter. Adjusted EBITDA was $161 million, a 35% increase compared to the prior year quarter. The increase in Adjusted EBITDA was primarily driven by increased throughput and fresh water volumes. Distributable Cash Flow was $130 million, a 43% increase over the prior year quarter, resulting in a DCF coverage ratio of 1.3x. For a description of Distributable Cash Flow and reconciliation to its nearest GAAP measure, please read "Non-GAAP Financial Measures."
Antero Midstream declared a distribution of $0.365 per limited partner unit attributable to the fourth quarter of 2017, resulting in $36 million of distributions received by Antero Resources from Antero Midstream during the first quarter of 2018. On April 18, 2018, Antero Midstream declared a distribution of $0.39 per limited partner unit attributable to the first quarter of 2018.
First Quarter 2018 Capital Investment
Antero had $360 million of drilling and completion capital expenditures for the three months ended March 31, 2018. For 2018, the Company's drilling and completion capital budget is $1.3 billion. In addition, the Company invested $50 million for land, $94 million for gathering and compression systems and $40 million for water infrastructure projects, including $25 million for the Antero Clearwater Treatment Facility. Antero's Stand-Alone drilling and completion capital expenditures for the three months ended March 31, 2018, were $421 million.
Balance Sheet and Liquidity
As of March 31, 2018, Antero's Stand-Alone net debt was $3.6 billion, of which $155 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility are $2.5 billion and the borrowing base is $4.5 billion. After deducting $692 million in letters of credit outstanding to support pipeline commitments, the Company had $1.7 billion in available Stand-Alone liquidity. As of March 31, 2018, Antero's Stand-Alone net debt to trailing twelve months adjusted EBITDAX ratio was 2.5x, compared to 2.9x at December 31, 2017.
Commodity Hedge Positions
Antero's estimated natural gas production for the last nine months of 2018 at the midpoint of guidance is fully hedged at an average index price of $3.47 per MMBtu. The Company's target natural gas production for 2019 is also fully hedged at an average index price of $3.50 per MMBtu. In total, Antero has hedged 2.6 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from April 1, 2018, through December 31, 2023, at an average index price of $3.38 per MMBtu. As of March 31, 2018, the Company's estimated fair value of commodity derivative instruments was $1.2 billion. The following table summarizes Antero's hedge position as of March 31, 2018:
Period |
Natural Gas |
Average |
Liquids |
Average | ||
2Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.42 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
26,000 |
$0.76 | ||
NYMEX WTI ($/Bbl) |
— |
— |
6,000 |
$56.99 | ||
3Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.45 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
26,000 |
$0.76 | ||
NYMEX WTI ($/Bbl) |
— |
— |
6,000 |
$56.99 | ||
4Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.53 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
26,000 |
$0.77 | ||
NYMEX WTI ($/Bbl) |
— |
— |
6,000 |
$56.99 | ||
2018 Total |
2,002,500 |
$3.50 |
32,000 |
N/A (1) | ||
2019: |
||||||
NYMEX Henry Hub |
2,330,000 |
$3.50 |
— |
— | ||
2020: |
||||||
NYMEX Henry Hub |
1,417,500 |
$3.25 |
— |
— | ||
2021: |
||||||
NYMEX Henry Hub |
710,000 |
$3.00 |
— |
— | ||
2022: |
||||||
NYMEX Henry Hub |
850,000 |
$3.00 |
— |
— | ||
2023: |
||||||
NYMEX Henry Hub |
90,000 |
$2.91 |
— |
— |
(1) |
Average index price is not applicable as 2018 liquids hedges include propane and oil hedges. |
Conference Call
A conference call is scheduled on Thursday, April 26, 2018 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, May 3, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10117424.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, May 3, 2018 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the April 26, 2018 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative Losses
Revenue excluding unrealized hedge gains as set forth in this release represents total operating revenue adjusted for non-cash gains on unsettled hedges and marketing derivatives. Antero believes that revenue excluding unrealized hedge gains and marketing derivative gains is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains and marketing derivative gains is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains and marketing derivative gains:
Three months ended | |||||
March 31, | |||||
2017 |
2018 | ||||
Total operating revenue |
$ |
1,195,579 |
$ |
1,028,101 | |
Commodity derivative (gains) |
(438,775) |
(22,437) | |||
Marketing derivative (gains) |
— |
(94,234) | |||
Cash receipts for settled commodity derivatives |
44,849 |
101,341 | |||
Cash receipts for settled marketing derivatives |
— |
110,042 | |||
Revenue excluding unrealized derivative losses |
$ |
801,653 |
$ |
1,122,813 |
Adjusted Net Income & Stand-Alone Adjusted Net Income
Adjusted net income as set forth in this release represents net income, adjusted for certain items. Stand-Alone adjusted net income as presented in this release represents net income that will be reported in the Parent column of Antero's guarantor footnote to its financial statements, adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income and Stand-Alone adjusted net income are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income as an indicator of financial performance.
The following table reconciles net income (loss) to adjusted net income (in thousands) and Stand-Alone net income (loss) to Stand-Alone adjusted net income (in thousands):
Stand-Alone |
Consolidated | ||||||||||
Three months ended |
Three months ended | ||||||||||
March 31, |
March 31, | ||||||||||
2017 |
2018 |
2017 |
2018 | ||||||||
Net income |
$ |
268,396 |
$ |
14,833 |
$ |
268,396 |
$ |
14,833 | |||
Commodity derivative (gains) |
(438,775) |
(22,437) |
(438,775) |
(22,437) | |||||||
Gains on settled commodity derivatives |
44,849 |
101,341 |
44,849 |
101,341 | |||||||
Marketing derivative (gains) |
— |
(94,234) |
— |
(94,234) | |||||||
Gains on settled marketing derivatives |
— |
110,042 |
— |
110,042 | |||||||
Impairment of unproved properties |
26,899 |
50,536 |
26,899 |
50,536 | |||||||
Equity-based compensation |
19,217 |
14,945 |
25,503 |
21,156 | |||||||
Income tax effect of reconciling items |
131,604 |
(38,751) |
129,225 |
(40,254) | |||||||
Adjusted net income |
$ |
52,190 |
$ |
136,275 |
$ |
56,097 |
$ |
140,983 |
Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow
Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items. Stand-Alone Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions.
Management believes that Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-Alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.
There are significant limitations to using Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.
Adjusted Operating Cash Flow is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to Adjusted Operating Cash Flow as used in this release (in thousands):
Stand-Alone |
Consolidated | ||||||||||
Three months ended |
Three months ended | ||||||||||
March 31, |
March 31, | ||||||||||
2017 |
2018 |
2017 |
2018 | ||||||||
Net cash provided by operating activities |
$ |
369,693 |
498,258 |
$ |
393,939 |
541,549 | |||||
Net change in working capital |
(109,217) |
(65,023) |
(97,337) |
(56,089) | |||||||
Adjusted Operating Cash Flow |
$ |
260,476 |
433,235 |
$ |
296,602 |
485,460 |
Total Debt and Net Debt
The following table reconciles consolidated total debt to net debt as used in this release (in thousands):
December 31, |
March 31, | ||||
2017 |
2018 | ||||
AR Bank credit facility |
$ |
185,000 |
155,000 | ||
AM Bank credit facility |
555,000 |
660,000 | |||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | |||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | |||
Net unamortized premium |
1,520 |
1,452 | |||
Net unamortized debt issuance costs |
(41,430) |
(39,746) | |||
Consolidated total debt |
$ |
4,800,090 |
4,876,706 | ||
Less: AR cash and cash equivalents |
20,078 |
14,439 | |||
Less: AM cash and cash equivalents |
8,363 |
8,714 | |||
Consolidated net debt |
$ |
4,771,649 |
4,853,553 | ||
Stand-alone net debt |
$ |
3,584,012 |
3,560,987 |
Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-Alone adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's condensed consolidated financial statements. The GAAP financial measure nearest to Stand-Alone Adjusted EBITDAX is Stand-Alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Stand-Alone |
Consolidated | |||||||||||
Three months ended March 31, |
Three months ended March 31, | |||||||||||
(in thousands) |
2017 |
2018 |
2017 |
2018 | ||||||||
Net income including noncontrolling interest |
$ |
268,396 |
14,833 |
$ |
305,558 |
80,810 | ||||||
Commodity derivative gains |
(438,775) |
(22,437) |
(438,775) |
(22,437) | ||||||||
Gains on settled commodity derivatives |
44,849 |
101,341 |
44,849 |
101,341 | ||||||||
Marketing derivative gains |
— |
(94,234) |
— |
(94,234) | ||||||||
Gains on settled marketing derivatives |
— |
110,042 |
— |
110,042 | ||||||||
Interest expense |
58,003 |
53,498 |
66,670 |
64,426 | ||||||||
Income tax expense |
131,346 |
9,120 |
131,346 |
9,120 | ||||||||
Depletion, depreciation, amortization, and accretion |
175,830 |
196,468 |
203,366 |
228,934 | ||||||||
Impairment of unproved properties |
26,899 |
50,536 |
26,899 |
50,536 | ||||||||
Exploration expense |
2,107 |
1,885 |
2,107 |
1,885 | ||||||||
Gain on change in fair value of contingent acquisition consideration |
(3,526) |
(3,874) |
— |
— | ||||||||
Equity-based compensation expense |
19,217 |
14,945 |
25,503 |
21,156 | ||||||||
Equity in earnings of unconsolidated affiliates |
— |
— |
(2,231) |
(7,862) | ||||||||
Distributions from unconsolidated affiliates |
— |
— |
— |
7,085 | ||||||||
Equity in (earnings) loss of Antero Midstream |
6,300 |
20,128 |
— |
— | ||||||||
Distributions from Antero Midstream |
30,484 |
36,088 |
— |
— | ||||||||
Adjusted EBITDAX |
321,130 |
488,339 |
365,292 |
550,802 | ||||||||
Interest expense |
(58,003) |
(53,498) |
(66,670) |
(64,426) | ||||||||
Exploration expense |
(2,107) |
(1,885) |
(2,107) |
(1,885) | ||||||||
Changes in current assets and liabilities |
109,217 |
65,023 |
97,337 |
56,089 | ||||||||
Other non-cash items |
(544) |
279 |
87 |
969 | ||||||||
Net cash provided by operating activities |
$ |
369,693 |
498,258 |
$ |
393,939 |
541,549 |
The following table reconciles Antero's Stand-Alone net income to adjusted EBITDAX for the twelve months ending March 31, 2018, as used in this release (in thousands):
Stand-Alone | |||
Twelve months ended | |||
(in thousands) |
2018 | ||
Net income including noncontrolling interest |
$ |
361,507 | |
Commodity derivative gains |
(241,945) | ||
Gains on settled commodity derivatives |
270,432 | ||
Marketing derivative gains |
(72,840) | ||
Gains on settled marketing derivatives |
110,042 | ||
Interest expense |
227,826 | ||
Loss on early extinguishment of debt |
1,205 | ||
Income tax expense |
(417,277) | ||
Depletion, depreciation, amortization, and accretion |
728,296 | ||
Impairment of unproved properties |
183,235 | ||
Exploration expense |
8,316 | ||
Gain on change in fair value of contingent acquisition consideration |
(13,824) | ||
Equity-based compensation expense |
71,890 | ||
Equity in (earnings) loss of Antero Midstream |
57,538 | ||
Distributions from Antero Midstream |
137,202 | ||
Adjusted EBITDAX |
$ |
1,411,603 |
Antero Midstream Adjusted EBITDA & Distributable Cash Flow
Antero Midstream views Adjusted EBITDA as an important indicator of its performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Three months ended | |||||
March 31, | |||||
2017 |
2018 | ||||
Net income |
$ |
75,091 |
$ |
108,105 | |
Interest expense |
8,836 |
11,297 | |||
Depreciation expense |
27,536 |
32,432 | |||
Accretion of contingent acquisition consideration |
3,526 |
3,874 | |||
Accretion of asset retirement obligations |
— |
34 | |||
Equity-based compensation |
6,286 |
6,211 | |||
Equity in earnings of unconsolidated affiliates |
(2,231) |
(7,862) | |||
Distributions from unconsolidated affiliates |
— |
7,085 | |||
Adjusted EBITDA |
$ |
119,044 |
$ |
161,176 | |
Interest paid |
(19,668) |
(22,348) | |||
Decrease (increase) in cash reserved for bond interest (1) |
8,929 |
8,734 | |||
Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards (2) |
(1,500) |
(1,500) | |||
Maintenance capital expenditures (3) |
(15,903) |
(16,488) | |||
Distributable Cash Flow |
$ |
90,902 |
$ |
129,574 | |
Distributions Declared to Antero Midstream Holders |
|||||
Limited Partners |
55,753 |
72,923 | |||
Incentive distribution rights |
11,553 |
28,453 | |||
Total Aggregate Distributions |
$ |
67,306 |
$ |
101,376 | |
DCF coverage ratio |
1.35x |
1.28x |
(1) |
Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. |
(2) |
Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter. |
(3) |
Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Balance Sheets | |||||
December 31, 2017 and March 31, 2018 | |||||
(Unaudited) | |||||
(In thousands, except per share amounts) | |||||
December 31, 2017 |
March 31, 2018 | ||||
Assets | |||||
Current assets: |
|||||
Cash and cash equivalents |
$ |
28,441 |
23,153 | ||
Accounts receivable, net of allowance for doubtful accounts of $1,320 at December 31, 2017 and $1,195 at March 31, 2018, respectively |
34,896 |
26,692 | |||
Accrued revenue |
300,122 |
279,923 | |||
Derivative instruments |
460,685 |
459,892 | |||
Other current assets |
8,943 |
10,374 | |||
Total current assets |
833,087 |
800,034 | |||
Property and equipment: |
|||||
Natural gas properties, at cost (successful efforts method): |
|||||
Unproved properties |
2,266,673 |
2,265,727 | |||
Proved properties |
11,096,462 |
11,471,428 | |||
Water handling and treatment systems |
946,670 |
974,389 | |||
Gathering systems and facilities |
2,050,490 |
2,132,803 | |||
Other property and equipment |
57,429 |
59,499 | |||
16,417,724 |
16,903,846 | ||||
Less accumulated depletion, depreciation, and amortization |
(3,182,171) |
(3,410,098) | |||
Property and equipment, net |
13,235,553 |
13,493,748 | |||
Derivative instruments |
841,257 |
760,562 | |||
Investments in unconsolidated affiliates |
303,302 |
321,468 | |||
Other assets |
48,291 |
47,037 | |||
Total assets |
$ |
15,261,490 |
15,422,849 | ||
Liabilities and Equity | |||||
Current liabilities: |
|||||
Accounts payable |
$ |
62,982 |
73,221 | ||
Accrued liabilities |
443,225 |
422,617 | |||
Revenue distributions payable |
209,617 |
237,907 | |||
Derivative instruments |
28,476 |
41,907 | |||
Other current liabilities |
17,796 |
14,201 | |||
Total current liabilities |
762,096 |
789,853 | |||
Long-term liabilities: |
|||||
Long-term debt |
4,800,090 |
4,876,706 | |||
Deferred income tax liability |
779,645 |
788,765 | |||
Derivative instruments |
207 |
— | |||
Other liabilities |
43,316 |
46,427 | |||
Total liabilities |
6,385,354 |
6,501,751 | |||
Commitments and contingencies (notes 12 and 13) |
|||||
Equity: |
|||||
Stockholders' equity: |
|||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— | |||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 316,524 shares issued and outstanding at December 31, 2017 and March 31, 2018, respectively |
3,164 |
3,165 | |||
Additional paid-in capital |
6,570,952 |
6,588,082 | |||
Accumulated earnings |
1,575,065 |
1,589,898 | |||
Total stockholders' equity |
8,149,181 |
8,181,145 | |||
Noncontrolling interests in consolidated subsidiary |
726,955 |
739,953 | |||
Total equity |
8,876,136 |
8,921,098 | |||
Total liabilities and equity |
$ |
15,261,490 |
15,422,849 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Operations and Comprehensive Income | |||||
Three Months Ended March 31, 2017 and 2018 | |||||
(Unaudited) | |||||
(In thousands, except per share amounts) | |||||
Three Months Ended March 31, | |||||
2017 |
2018 | ||||
Revenue and other: |
|||||
Natural gas sales |
$ |
466,664 |
497,663 | ||
Natural gas liquids sales |
194,652 |
234,170 | |||
Oil sales |
26,960 |
30,273 | |||
Commodity derivative gains |
438,775 |
22,437 | |||
Gathering, compression, water handling and treatment |
2,604 |
4,935 | |||
Marketing |
65,924 |
144,389 | |||
Marketing derivative gains |
— |
94,234 | |||
Total revenue and other |
1,195,579 |
1,028,101 | |||
Operating expenses: |
|||||
Lease operating |
15,551 |
26,722 | |||
Gathering, compression, processing, and transportation |
266,829 |
291,938 | |||
Production and ad valorem taxes |
24,793 |
25,823 | |||
Marketing |
89,993 |
195,739 | |||
Exploration |
2,107 |
1,885 | |||
Impairment of unproved properties |
26,899 |
50,536 | |||
Depletion, depreciation, and amortization |
202,729 |
228,244 | |||
Accretion of asset retirement obligations |
637 |
690 | |||
General and administrative (including equity-based compensation expense of $25,503 and $21,156 in 2017 and 2018, respectively) |
64,698 |
60,030 | |||
Total operating expenses |
694,236 |
881,607 | |||
Operating income |
501,343 |
146,494 | |||
Other income (expenses): |
|||||
Equity in earnings of unconsolidated affiliates |
2,231 |
7,862 | |||
Interest |
(66,670) |
(64,426) | |||
Total other expenses |
(64,439) |
(56,564) | |||
Income before income taxes |
436,904 |
89,930 | |||
Provision for income tax expense |
(131,346) |
(9,120) | |||
Net income and comprehensive income including noncontrolling interests |
305,558 |
80,810 | |||
Net income and comprehensive income attributable to noncontrolling interests |
37,162 |
65,977 | |||
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
268,396 |
14,833 | ||
Earnings per common share—basic |
$ |
0.85 |
0.05 | ||
Earnings per common share—assuming dilution |
$ |
0.85 |
0.05 | ||
Weighted average number of shares outstanding: |
|||||
Basic |
314,954 |
316,471 | |||
Diluted |
315,769 |
316,911 |
ANTERO RESOURCES CORPORATION | |||||
Condensed Consolidated Statements of Cash Flows | |||||
Three Months Ended March 31, 2017 and 2018 | |||||
(Unaudited) | |||||
(In thousands) | |||||
Three Months Ended March 31, | |||||
2017 |
2018 | ||||
Cash flows provided by (used in) operating activities: |
|||||
Net income including noncontrolling interests |
$ |
305,558 |
80,810 | ||
Adjustment to reconcile net income to net cash provided by operating activities: |
|||||
Depletion, depreciation, amortization, and accretion |
203,366 |
228,934 | |||
Impairment of unproved properties |
26,899 |
50,536 | |||
Commodity derivative gains |
(438,775) |
(22,437) | |||
Gains on settled commodity derivatives |
44,849 |
101,341 | |||
Marketing derivative gains |
— |
(94,234) | |||
Gains on settled marketing derivatives |
— |
110,042 | |||
Deferred income tax expense |
131,346 |
9,120 | |||
Equity-based compensation expense |
25,503 |
21,156 | |||
Equity in earnings of unconsolidated affiliates |
(2,231) |
(7,862) | |||
Distributions of earnings from unconsolidated affiliates |
— |
7,085 | |||
Other |
87 |
969 | |||
Changes in current assets and liabilities: |
|||||
Accounts receivable |
(7,192) |
8,204 | |||
Accrued revenue |
41,901 |
20,199 | |||
Other current assets |
(3,366) |
(1,431) | |||
Accounts payable |
12,545 |
(8,042) | |||
Accrued liabilities |
19,339 |
10,359 | |||
Revenue distributions payable |
34,786 |
28,290 | |||
Other current liabilities |
(676) |
(1,490) | |||
Net cash provided by operating activities |
393,939 |
541,549 | |||
Cash flows used in investing activities: |
|||||
Additions to proved properties |
(49,664) |
— | |||
Additions to unproved properties |
(55,542) |
(49,569) | |||
Drilling and completion costs |
(306,925) |
(359,868) | |||
Additions to water handling and treatment systems |
(36,954) |
(40,285) | |||
Additions to gathering systems and facilities |
(66,559) |
(93,670) | |||
Additions to other property and equipment |
(590) |
(2,571) | |||
Investments in unconsolidated affiliates |
(159,889) |
(17,389) | |||
Change in other assets |
(12,350) |
(217) | |||
Net cash used in investing activities |
(688,473) |
(563,569) | |||
Cash flows provided by (used in) financing activities: |
|||||
Issuance of common units by Antero Midstream Partners LP |
223,119 |
— | |||
Borrowings on bank credit facilities, net |
70,000 |
75,000 | |||
Distributions to noncontrolling interests in consolidated subsidiary |
(27,149) |
(55,915) | |||
Employee tax withholding for settlement of equity compensation awards |
(1,657) |
(1,084) | |||
Other |
(1,389) |
(1,269) | |||
Net cash provided by financing activities |
262,924 |
16,732 | |||
Net decrease in cash and cash equivalents |
(31,610) |
(5,288) | |||
Cash and cash equivalents, beginning of period |
31,610 |
28,441 | |||
Cash and cash equivalents, end of period |
$ |
— |
23,153 | ||
Supplemental disclosure of cash flow information: |
|||||
Cash paid during the period for interest |
$ |
35,770 |
42,010 | ||
Supplemental disclosure of noncash investing activities: |
|||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
$ |
10,020 |
12,691 |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended March 31, 2017 and 2018:
Three Months Ended March 31, |
Amount of |
Percent |
|||||||||||
(in thousands) |
2017 |
2018 |
(Decrease) |
Change |
|||||||||
Operating revenues and other: |
|||||||||||||
Natural gas sales |
$ |
466,664 |
$ |
497,663 |
$ |
30,999 |
7 |
% | |||||
NGLs sales |
194,652 |
234,170 |
39,518 |
20 |
% | ||||||||
Oil sales |
26,960 |
30,273 |
3,313 |
12 |
% | ||||||||
Commodity derivative gains |
438,775 |
22,437 |
(416,338) |
(95) |
% | ||||||||
Gathering, compression, water handling and treatment |
2,604 |
4,935 |
2,331 |
90 |
% | ||||||||
Marketing |
65,924 |
144,389 |
78,465 |
119 |
% | ||||||||
Marketing derivative gains |
— |
94,234 |
110,042 |
* |
|||||||||
Total operating revenues and other |
1,195,579 |
1,028,101 |
(151,670) |
(14) |
% | ||||||||
Operating expenses: |
|||||||||||||
Lease operating |
15,551 |
26,722 |
11,171 |
72 |
% | ||||||||
Gathering, compression, processing, and transportation |
266,829 |
291,938 |
25,109 |
9 |
% | ||||||||
Production and ad valorem taxes |
24,793 |
25,823 |
1,030 |
4 |
% | ||||||||
Marketing |
89,993 |
195,739 |
105,746 |
118 |
% | ||||||||
Exploration |
2,107 |
1,885 |
(222) |
(11) |
% | ||||||||
Impairment of unproved properties |
26,899 |
50,536 |
23,637 |
88 |
% | ||||||||
Depletion, depreciation, and amortization |
202,729 |
228,244 |
25,515 |
13 |
% | ||||||||
Accretion of asset retirement obligations |
637 |
690 |
53 |
8 |
% | ||||||||
General and administrative (before equity-based compensation) |
39,195 |
38,874 |
(321) |
(1) |
% | ||||||||
Equity-based compensation |
25,503 |
21,156 |
(4,347) |
(17) |
% | ||||||||
Total operating expenses |
694,236 |
881,607 |
187,371 |
27 |
% | ||||||||
Operating income (loss) |
501,343 |
146,494 |
(339,041) |
(68) |
% | ||||||||
Other earnings (expenses): |
|||||||||||||
Equity in earnings of unconsolidated affiliate |
2,231 |
7,862 |
5,631 |
252 |
% | ||||||||
Interest expense |
(66,670) |
(64,426) |
2,244 |
(3) |
% | ||||||||
Total other expenses |
(64,439) |
(56,564) |
7,875 |
(12) |
% | ||||||||
Income (loss) before income taxes |
436,904 |
89,930 |
(331,166) |
(76) |
% | ||||||||
Income tax (expense) benefit |
(131,346) |
(9,120) |
122,226 |
(93) |
% | ||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
305,558 |
80,810 |
(208,940) |
(68) |
% | ||||||||
Net income and comprehensive income attributable to noncontrolling interest |
37,162 |
65,977 |
28,815 |
78 |
% | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
268,396 |
$ |
14,833 |
$ |
(237,755) |
(89) |
% | |||||
Adjusted EBITDAX (1) |
$ |
365,292 |
$ |
550,802 |
$ |
185,510 |
51 |
% | |||||
Production data: |
|||||||||||||
Natural gas (Bcf) |
139 |
158 |
19 |
14 |
% | ||||||||
C2 Ethane (MBbl) |
2,310 |
3,029 |
719 |
31 |
% | ||||||||
C3+ NGLs (MBbl) |
5,968 |
5,693 |
(275) |
(5) |
% | ||||||||
Oil (MBbl) |
643 |
530 |
(113) |
(18) |
% | ||||||||
Combined (Bcfe) |
193 |
214 |
21 |
11 |
% | ||||||||
Daily combined production (MMcfe/d) |
2,144 |
2,376 |
232 |
11 |
% | ||||||||
Average prices before effects of derivative settlements: |
|||||||||||||
Natural gas (per Mcf) |
$ |
3.35 |
$ |
3.14 |
$ |
(0.21) |
(6) |
% | |||||
C2 Ethane (per Bbl) |
$ |
8.00 |
$ |
8.94 |
$ |
0.94 |
12 |
% | |||||
C3+ NGLs (per Bbl) |
$ |
29.52 |
$ |
36.38 |
$ |
6.86 |
23 |
% | |||||
Oil (per Bbl) |
$ |
41.96 |
$ |
57.14 |
$ |
15.18 |
36 |
% | |||||
Combined (per Mcfe) |
$ |
3.57 |
$ |
3.56 |
$ |
(0.01) |
— |
% | |||||
Average realized prices after effects of derivative settlements: |
|||||||||||||
Natural gas (per Mcf) |
$ |
3.89 |
$ |
3.85 |
$ |
(0.04) |
(1) |
% | |||||
C2 Ethane (per Bbl) |
$ |
8.73 |
$ |
8.94 |
$ |
0.21 |
2 |
% | |||||
C3+ NGLs (per Bbl) |
$ |
24.01 |
$ |
35.17 |
$ |
11.16 |
46 |
% | |||||
Oil (per Bbl) |
$ |
43.17 |
$ |
51.12 |
$ |
7.95 |
18 |
% | |||||
Combined (per Mcfe) |
$ |
3.80 |
$ |
4.04 |
$ |
0.24 |
6 |
% | |||||
Average Costs (per Mcfe): |
|||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.12 |
$ |
0.04 |
50 |
% | |||||
Gathering, compression, processing, and transportation |
$ |
1.38 |
$ |
1.37 |
$ |
(0.01) |
(1) |
% | |||||
Production and ad valorem taxes |
$ |
0.13 |
$ |
0.12 |
$ |
(0.01) |
(8) |
% | |||||
Marketing expense (gain), net |
$ |
0.12 |
$ |
(0.27) |
$ |
(0.39) |
* |
||||||
Depletion, depreciation, amortization, and accretion |
$ |
1.05 |
$ |
1.07 |
$ |
0.02 |
2 |
% | |||||
General and administrative (before equity-based compensation) |
$ |
0.20 |
$ |
0.18 |
$ |
(0.02) |
(10) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
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SOURCE Antero Resources Corporation
DENVER, Feb. 26, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that, as part of its ongoing evaluation process disclosed in the Company's January 29, 2018 press release, the Board of Directors has formed a Special Committee comprised solely of independent directors (the "AR Special Committee") to explore, review and evaluate potential measures to address the discount in trading value. The AR Special Committee is in the process of hiring financial and legal advisors to assist in its evaluation.
Commenting on the announcement, Paul Rady, Chairman and CEO, said, "As part of our ongoing review over the past several weeks, which has included discussions with a number of our shareholders, our Board and our financial and legal advisors, our Board established a Special Committee of independent directors charged with exploring and analyzing the merits of any possible measures to enhance Antero's valuation."
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in AR's Annual Report on Form 10-K for the year ended December 31, 2017.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
View original content with multimedia:http://www.prnewswire.com/news-releases/antero-resources-announces-formation-of-special-committee-300603861.html
SOURCE Antero Resources
DENVER, Feb. 13, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced estimated reserves as of December 31, 2017.
Highlights:
Antero's estimated proved reserves at December 31, 2017 were 17.3 Tcfe, a 12% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible ("3P") reserves at year-end 2017 totaled 54.6 Tcfe, which represents an 18% increase compared to the previous year. For further discussion of 3P reserves, please read "Non-GAAP Disclosure."
Proved developed finding and development ("F&D") cost for estimated proved developed reserve additions was $0.54 per Mcfe for 2017. All-in F&D cost for estimated proved reserve additions, including acquisitions, was $0.59 per Mcfe for 2017. Future development costs for proved undeveloped locations are estimated to be $0.37 per Mcfe. The reserve life of the Company's estimated proved reserves is approximately 21 years based on 2017 production. For further discussion of all-in F&D cost and proved developed F&D cost, please read "Non-GAAP Disclosure." Antero's estimated proved and 3P reserves at December 31, 2017 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton ("D&M"). D&M's reserve audit covered properties representing 100% of Antero's total 3P reserves at December 31, 2017.
Estimated Proved Reserves
As of December 31, 2017, the Company's 17.3 Tcfe of estimated proved reserves were comprised of 64% natural gas, 35% NGLs and 1% oil. The Marcellus Shale accounted for 90% of estimated proved reserves and the Ohio Utica Shale accounted for 10%. For 2017, Antero added 1.7 Tcfe of estimated proved reserves organically, excluding acquisitions, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.
All 381 proved undeveloped locations in the Marcellus at year-end 2017 were booked at an approximate 2 Bcf/1,000' type curve. This compares to year-end 2016 at which time 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, were booked at the approximate 2 Bcf/1,000' type curve. The primary driver behind the increase in the number of proved undeveloped locations booked at the higher approximate 2 Bcf/1,000' type curve type curve is the increased production history observed from the implementation of advanced completions techniques.
Estimated proved developed reserves increased by 23% from year-end 2016 to 8.5 Tcfe at December 31, 2017. The percentage of estimated proved reserves classified as proved developed increased to 49% at December 31, 2017 from 45% at year-end 2016. The average heating content of Antero's proved undeveloped locations is 1237 BTU, and the average lateral length is approximately 10,500 feet.
Under the Securities and Exchange Commission ("SEC") reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2,778 Bcfe of formerly non-proved reserves to proved undeveloped due to their addition to Antero's five-year development plan. Included in this reclassification was the revision of 286 Bcfe related to an improvement in performance from advanced completions and a 291 Bcfe revision related to a lateral extension of previously booked locations. Additionally, the Company reclassified 2,280 Bcfe of generally lower BTU proved undeveloped reserves to the probable category in 2017 to comply with the SEC five-year development rule. Antero's 8.8 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.37 per Mcfe.
Antero incurred estimated capital costs of approximately $1.7 billion during 2017, including drilling and completion costs of $1.282 billion, proved property acquisitions of $176 million and leasehold additions of $204 million. Based on the $1.7 billion of capital costs, 2017 all-in F&D cost for proved reserve additions from all sources, including acquisitions and revisions, was $0.59 per Mcfe.
Summary of Changes in Estimated Proved Reserves (in Bcfe) |
||
Balance at December 31, 2016 |
15,386 | |
Extensions, discoveries and additions |
1,711 | |
Purchases of estimated proved reserves |
373 | |
Revisions to prior estimates |
726 | |
Ethane recovery revision |
(113) | |
Production |
(822) | |
Balance at December 31, 2017 |
17,261 | |
The table below summarizes both SEC and strip pricing as of December 31, 2017 and the associated PV-10 for estimated proved reserves and hedge values:
2017 Year-End |
|||||||
Benchmark Pricing: |
SEC |
Strip |
Variance |
% | |||
WTI Oil Price ($/Bbl) |
$51.03 |
$53.44 |
$2.41 |
5% | |||
Appalachian Oil Price ($/Bbl)(2) |
$45.35 |
$47.70 |
$2.35 |
5% | |||
Nymex Natural Gas Price ($/MMBtu) |
$3.11 |
$2.93 |
$(0.18) |
(6)% | |||
Appalachian Natural Gas Price ($/MMBtu)(2) |
$2.91 |
$2.63 |
$(0.28) |
(10)% | |||
C3+ Natural Gas Liquids ($/Bbl) (3) |
$32.37 |
$32.23 |
$(0.14) |
0% | |||
C2+ Natural Gas Liquids ($/Bbl)(3) |
$20.40 |
$20.62 |
$0.22 |
1% | |||
Pre-Tax PV-10 Values ($Bn): |
|||||||
Estimated proved reserves PV-10 |
$10.2 |
$9.1 |
$(1.1) |
(11)% | |||
Hedge PV-10 (4) |
0.6 |
1.2 |
0.6 |
100% | |||
Total PV-10 |
$10.8 |
$10.3 |
$(0.5) |
(5)% |
1) |
Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter. |
2) |
Represents SEC and strip prices as of December 31, 2017 on a weighted average Appalachian index basis related to company-specific sales points. |
3) |
Represents realized NGL price including regional market differentials. |
4) |
Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate. |
Proved, Probable and Possible Reserves
Antero estimates that it had year-end 2017 3P reserves of 54.6 Tcfe, an 18% increase from year-end 2016. The 18% increase in 3P reserves was driven by a combination of increased type curves in certain areas driven by continued productivity gains from advanced completions, as well as 2017 leasehold acquisitions. As of December 31, 2017, the Company's 54.6 Tcfe of 3P reserves were comprised of 75% natural gas, 23% NGLs and 2% oil. The Marcellus and Ohio Utica Shale comprised 48.3 Tcfe and 6.4 Tcfe of the 3P reserves, respectively. Virtually no Upper Devonian or West Virginia Utica reserves were included in 3P reserves.
Importantly, 46.2 Tcfe of Antero's 48.3 Tcfe, or 96% of estimated Marcellus 3P reserves were classified as proved and probable reserves ("2P"), reflecting the low risk and statistically repeatable nature of Antero's resource base. The 46.2 Tcfe of Marcellus 2P reserves includes 381 proved undeveloped and 460 probable locations, or 26% of the total undeveloped 2P reserve locations in the Marcellus that were booked at the approximate 2 Bcf/1,000' type curve. This compares to year-end 2016 where 81 proved undeveloped and 7 probable locations, or just 3% of the total undeveloped 2P reserve locations in the Marcellus were booked at the approximate 2 Bcf/1,000' type curve. The increase in upgraded 2P locations is primarily driven by continued productivity gains from implementing advanced completions techniques across a larger subset of Antero's acreage position. Further, 6.2 Tcfe of Antero's 6.4 Tcfe, or 97% of estimated 3P reserves in the Ohio Utica were classified as 2P.
The tables below summarize Antero's estimated 3P reserve volumes as of December 31, 2017 using SEC pricing, categorized by operating area as well as PV-10 values of Antero's 3P reserve volumes using both SEC and strip pricing. For further discussion of 3P reserves, please read "Non-GAAP Disclosure."
Marcellus Shale |
Ohio Utica Shale |
|||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total |
Gross |
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
|||||||||||||||
Proved |
9,726 |
971 |
15,553 |
1,054 |
1,372 |
56 |
1,708 |
243 |
||||||||||||||
Probable |
24,174 |
1,079 |
30,645 |
2,864 |
3,978 |
85 |
4,489 |
524 |
||||||||||||||
Possible |
1,688 |
67 |
2,089 |
267 |
142 |
4 |
164 |
51 |
||||||||||||||
Total 3P |
35,588 |
2,117 |
48,287 |
4,185 |
5,492 |
145 |
6,361 |
818 |
||||||||||||||
% Liquids(1) |
26% |
14% |
||||||||||||||||||||
Combined 3P Reserves |
||||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross |
|||||||||||||||||||
Proved(2) |
11,098 |
1,027 |
17,261 |
1,297 |
||||||||||||||||||
Probable |
28,152 |
1,164 |
35,134 |
3,388 |
||||||||||||||||||
Possible |
1,830 |
70 |
2,253 |
318 |
||||||||||||||||||
Total 3P |
41,080 |
2,261 |
54,648 |
5,003 |
||||||||||||||||||
% Liquids(1) |
25% |
1) Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 812 million barrels of ethane, 1.3 billion barrels of C3+ NGLs and 131 million barrels of oil | |||||||||||||||||||||||
2) 427 of the 1,297 proved locations were undeveloped locations |
Pre-Tax 3P PV-10 Values ($ Billions): | |||||||||
SEC |
Strip |
Variance |
% |
||||||
3P Reserves PV-10 |
$17.8 |
$15.5 |
$(2.3) |
(13)% |
|||||
Hedge PV-10 (2) |
0.6 |
1.2 |
0.6 |
100% |
|||||
Total PV-10 |
$18.4 |
$16.7 |
$1.7 |
(9)% |
1) Strip pricing as of December 31, 2017 for each of the first ten years and flat thereafter 2) Hedge PV-10 at strip pricing differs from year-end 2017 mark-to-market value of $1.3 billion due to the application of a higher discount rate | |||||||||||||||||||||||
Non-GAAP Disclosure
Certain selected financial information in this release is unaudited. Additional unaudited financial information will be provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2017, which the Company filed with the SEC on February 13, 2018. In this release, Antero has provided a number of unaudited metrics, which include all-in F&D cost per unit and proved developed F&D cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The F&D costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for all-in F&D cost per unit and proved developed F&D cost per unit, and therefore a reconciliation to GAAP is not practicable.
Calculations for all-in and proved developed F&D cost per unit are based on costs incurred in 2017. The calculations for both all-in and proved developed F&D cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Pre-tax PV-10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV-10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV-10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV-10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2017:
(In millions, except per Mcf data) |
|||
At December 31, 2017 |
|||
Future net cash flows |
$ |
26,137 |
|
Present value of future net cash flows: |
|||
Before income tax (PV-10) |
$ |
10,175 |
|
Income taxes |
$ |
(1,548) |
|
After income tax (Standardized measure) |
$ |
8,627 |
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.
Antero has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this press release. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future development costs, future capital spending plans, expected drilling and development plans, plans with respect to the rejection of ethane and the prices we will receive for future production as well as future production volumes are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have not been audited by its third party reserve engineer in this release. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
This release provides a summary of Antero's reserves as of December 31, 2017, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
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SOURCE Antero Resources
DENVER, Feb. 13, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its fourth quarter and full year 2017 financial and operational results. The relevant consolidated and consolidating financial statements are included in Antero's Annual Report on Form 10-K for the year ended December 31, 2017, which has been filed with the Securities and Exchange Commission ("SEC"). The relevant Stand-Alone E&P financial statements are also included in Antero's Form 10-K within the Parent column of the guarantor footnote (Note 18).
Fourth Quarter 2017 Highlights and Updated 2018 Guidance:
Full Year 2017 Highlights:
2018 Guidance Update
The Company's first quarter 2018 net production is estimated to be flat with the fourth quarter 2017 net production due primarily to the timing of completions throughout 2018, the impact from severe winter weather on the Sherwood processing plant operations in the West Virginia Marcellus in the early part of January, and a shutdown for several days at the Seneca plant in the Ohio Utica due to a third-party downstream pipeline rupture. Both of these processing plant issues have since been rectified. The Company continues to expect to meet its full year 2018 net production guidance of approximately 2.7 Bcfe/d. Additionally, the extreme cold weather in January resulted in attractive pricing on natural gas sales and the ability to generate significant marketing revenues during the first quarter of 2018 that more than offset the reduced production. Antero is now forecasting a net marketing gain for the first quarter of 2018 and is reducing its net marketing expense guidance for the full year of 2018 to a range of $0.10/Mcfe to $0.125/Mcfe.
"During 2017, Antero reached an inflection point by executing on its long-term strategic plan," commented Paul Rady, Chairman and CEO. "We are now positioned to generate free cash flow and reduce financial leverage, while maintaining a 20%-plus debt-adjusted production growth profile. We were pleased to host our first Analyst Day last month, where we highlighted a clear, measurable plan to achieve these goals. Our proven operational track record coupled with our high-quality liquids-rich asset portfolio gives us confidence in delivering on this plan."
Financial and operational results are reported and discussed on a consolidated basis, unless otherwise noted. Please read "Non-GAAP Financial Measures" for:
Please read "Fourth Quarter 2017 Financial Results" and "2017 Financial Results" for reconciliations of consolidated and Stand-Alone E&P adjusted EBITDAX margin to realized price before cash receipts for settled hedges, the most comparable GAAP measure.
Tax Reform
As a result of the new tax legislation that was enacted in late December, the following items affecting Antero have occurred:
Other significant provisions that are not yet effective, but may impact income taxes in future years, are included in Antero's Form 10-K under the 2017 Recent Developments and Highlights (Part I, Items 1 and 2).
Fourth Quarter 2017 Financial Results
As of December 31, 2017, Antero owned a 53% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated within Antero's results.
Antero reported fourth quarter net income of $487 million, or $1.54 per diluted share, compared to a net loss of $486 million, or $1.55 per diluted share, in the prior year period. Excluding the items detailed in our "Non-GAAP Financial Measures," fourth quarter adjusted net income was $74 million, or $0.23 per diluted share, and adjusted EBITDAX was $437 million.
The following table details the components of average net production and average realized prices for the three months ended December 31, 2017:
Three Months Ended December 31, 2017 | ||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane (Bbl/d) |
Combined | ||||||||||
Average Net Production |
1,702 |
6,207 |
69,801 |
31,425 |
2,347 | |||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs |
Ethane ($/Bbl) |
Combined | |||||||||
Average realized price before settled derivatives |
$ |
2.80 |
$ |
49.37 |
$ |
39.16 |
$ 10.02 |
$ |
3.46 | |||||
Settled derivatives |
0.87 |
(0.31) |
(9.24) |
0.15 |
0.36 | |||||||||
Average realized price after settled derivatives |
$ |
3.67 |
$ |
49.06 |
$ |
29.92 |
$ 10.17 |
$ |
3.82 | |||||
NYMEX average price |
$ |
2.93 |
$ |
55.37 |
$ |
2.93 | ||||||||
Premium / (Differential) to NYMEX |
$ |
0.74 |
$ |
(6.31) |
$ |
0.89 | ||||||||
Net daily production in the fourth quarter averaged 2,347 MMcfe/d, including 107,433 Bbl/d of liquids (27% liquids), representing an organic growth rate of 18% versus the prior year period and a 1% increase sequentially. Production was negatively impacted by the delayed in-service date of the Rover Pipeline, resulting in an approximate 45 day delay in placing 10 newly completed Utica wells to sales until the end of 2017. C3+ NGLs, oil, and recovered ethane production averaged 69,801 Bbl/d, 6,207 Bbl/d, and 31,425 Bbl/d, respectively. Total liquids production represents an organic growth rate of 24% versus the prior year period and a 4% decrease sequentially. The sequential decline in liquids production was a result of higher NGL allocations to royalty owners due to the improvement in liquids pricing. Liquids revenue represented approximately 41% of total product revenues, increasing from 30% of total product revenues in the prior year period.
Antero's average realized natural gas price before hedging decreased 8% from the prior year period to $2.80 per Mcf, a $0.13 per Mcf differential to the average NYMEX price. Excluding the $0.20 negative impact from the Company's previously disclosed natural gas contract disputes with South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, "SJGC") and Washington Gas Light Company and WGL Midstream, Inc. (collectively, "WGL"), the average natural gas price before hedging would have been $3.00 per Mcf, a $0.07 premium to the average NYMEX natural gas price. In 2018, Antero does not expect a material impact to its realized price and cash flow from these contractual disputes due to both additional takeaway capacity that is expected to be placed in service throughout the year and narrower regional basis differentials based on current strip pricing. Additionally, Antero recently amended its natural gas sales contract with WGL Midstream, Inc. As a result, effective February 1, 2018 the total aggregate volumes to be delivered to WGL at the delivery point in Braxton County, West Virginia were reduced from 500,000 MMBtu/d to 200,000 MMBtu/d. Upon both (1) the in service of the Dominion Cove Point LNG facility and (2) the earlier of in service of the WB East expansion and January 1, 2019, the aggregate contract volumes to be delivered to WGL will increase by 330,000 MMBtu/day. This increase will be in effect for the remaining term of our gas sales contract with WGL Midstream, which expires in 2038, and these increased volumes will be subject to NYMEX-based pricing. Following the increase of 330,000 MMBtu/d, the aggregate contract volumes to be delivered to WGL will total 530,000 MMBtu/d. Antero will continue to vigorously seek recovery from SJGC and WGL of all unpaid amounts, including interest, as part of its pending claims against these counterparties. Through December 31, 2017, damages net to Antero have totaled approximately $86 million for WGL and $51 million for SJGC. Substantially all of these amounts have not been accrued in the Company's financial statements.
Including hedges, Antero's average realized natural gas price was $3.67 per Mcf, a $0.74 premium to the NYMEX average price and consistent with the prior year period, reflecting the realization of a cash settled natural gas hedge gain of $136 million, or $0.87 per Mcf.
Antero's average realized C3+ NGL price before hedging was $39.16 per barrel, or 71% of the average NYMEX WTI oil price, representing a 55% increase versus the prior year period. Including hedges, Antero's average realized C3+ NGL price was $29.92 per barrel, a 17% increase versus the prior year period, reflecting the realization of a cash settled C3+ hedge loss of $59 million, or $9.24 per barrel. The average realized ethane price before hedging was $0.24 per gallon, or $10.02 per barrel, and the average realized oil price before hedging was $49.37 per barrel, a $6.00 negative differential to average NYMEX WTI and a 26% increase versus the prior year period.
Antero's average natural gas equivalent price including C2+ NGLs and oil, but excluding hedge settlements, was $3.46 per Mcfe, an increase of 7% versus the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.82 per Mcfe, a 10% decrease from the prior year period, driven by lower realized hedge gains compared to the prior year period. The net cash settled hedge gain on all products was $77 million, or $0.35 per Mcfe, primarily reflecting the impact of gains on natural gas hedges partially offset by losses from C3+ hedges.
Operating revenues were $1.022 billion, compared to $156 million in the prior year period. Revenue included a $123 million non-cash gain on unsettled hedges and a $21 million loss on unsettled marketing derivatives, while the prior year included an $829 million non-cash loss on unsettled hedges and a $98 million gain on the sale of assets. Revenue excluding the unrealized hedge gain and unrealized marketing derivative loss was $920 million, a 4% increase versus the prior year period. Liquids production contributed 41% of total product revenues before hedges, compared to a 30% contribution in the prior year period. Please see "Non-GAAP Financial Measures" for a description of revenue excluding the unrealized hedge gain and unrealized marketing derivative loss.
The following table presents a reconciliation of realized price before cash receipts for settled hedges to consolidated and Stand-Alone adjusted EBITDAX margin for the three months ended December 31, 2016 and 2017:
Stand-Alone E&P Three Months Ended |
Consolidated Three Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2016 |
2017 |
2016 |
2017 | |||||||
Realized price before cash receipts for settled hedges |
$ |
3.22 |
$ |
3.46 |
$ |
3.22 |
$ |
3.46 | |||
Gathering, compression, and water handling and treatment revenues |
N/A |
N/A |
0.01 |
0.02 | |||||||
Distributions from unconsolidated affiliate |
N/A |
N/A |
0.04 |
0.05 | |||||||
Distributions from Antero Midstream |
0.16 |
0.16 |
N/A |
N/A | |||||||
Gathering, compression, processing and transportation costs |
(1.68) |
(1.71) |
(1.27) |
(1.30) | |||||||
Lease operating expense |
(0.07) |
(0.17) |
(0.07) |
(0.15) | |||||||
Marketing, net |
(0.08) |
(0.13) |
(0.08) |
(0.13) | |||||||
Production and ad valorem taxes |
(0.10) |
(0.11) |
(0.08) |
(0.11) | |||||||
General and administrative(1) |
(0.17) |
(0.13) |
(0.21) |
(0.17) | |||||||
Adjusted EBITDAX margin before settled hedges |
1.28 |
1.37 |
1.56 |
1.67 | |||||||
Cash receipts for settled hedges |
1.04 |
0.35 |
1.04 |
0.35 | |||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.32 |
1.72 |
$ |
2.60 |
$ |
2.02 |
(1) |
Excludes non-cash equity-based compensation |
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) was $1.56 per Mcfe, a 10% increase compared to $1.42 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $0.15 per Mcfe for lease operating costs, $1.30 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes. The increase in lease operating expenses to $0.15 per Mcfe in the fourth quarter is due to an increase in produced water on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions throughout the year, and a one-time impact from well pad slip repairs. In 2018, Antero expects lease operating expenses to decline due to lower costs to truck produced water to Antero's Clearwater facility as compared to trucking to water disposal sites.
Per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.17 per Mcfe, a 19% decrease from the prior year period. Per unit depreciation, depletion and amortization expense declined by 19% from the prior year to $0.99 per Mcfe, primarily due to an increase in estimated recoverable reserves, improved well performance, and a decrease in per-unit development costs.
Adjusted EBITDAX was $437 million, at the high end of the Company's previously announced guidance range of $410 million to $440 million. Adjusted EBITDAX margin before settled hedges for the quarter was $1.67, a 6% increase from the prior year period. Adjusted EBITDAX margin including hedges, was $2.02 per Mcfe, a 22% decrease from the prior year period due to lower realized hedge gains. Stand-Alone E&P Adjusted EBITDAX was $372 million for the fourth quarter of 2017. Stand-Alone E&P adjusted EBITDAX margin was $1.37 per Mcfe before settled hedges and $1.72 per Mcfe including settled hedges for the quarter.
Adjusted Operating Cash Flow was $368 million during the fourth quarter, compared to $404 million in the prior year period. Stand-Alone E&P Adjusted Operating Cash Flow was $312 million, compared to $361 million in the prior year period. Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow declined versus the prior year period due to lower realized hedge gains.
Operating Update
Fourth Quarter 2017
Marcellus Shale — Antero completed and placed on line 28 horizontal Marcellus wells during the fourth quarter of 2017. Current average well costs are $0.87 million per 1,000' of lateral in the Marcellus assuming a 9,000' lateral and 2,000 pounds of proppant per foot completion, representing a 2% reduction from the third quarter of 2017. Antero is operating five drilling rigs and five completion crews in the Marcellus Shale play.
Antero drilled 27 horizontal Marcellus wells during the fourth quarter, including nine wells that had laterals greater than 12,000'. Antero recently drilled its two longest Marcellus laterals, both over 14,000', on a 12 well pad. This is the Company's largest pad to date, with approximately 120,000' of drilled lateral planned and approximately 300 Bcfe in anticipated pad reserves assuming 25% ethane recovery. Antero is in the process of drilling a nine well pad with average lateral lengths of 13,200' which the Company expects to place to sales in the first quarter of 2019.
Ohio Utica Shale — Antero placed 10 horizontal Utica wells to sales at the end of the fourth quarter of 2017. The 10 wells are currently flowing at a combined (facility) constrained rate of over 200 MMcf/d with wellhead pressures in excess of 3,000 psi. These are the first wells completed by Antero in the Ohio Utica dry gas regime. Despite running only one rig since 2016, Antero recently achieved record gross production in the Utica of 632 MMcf/d with only 22 wells completed during 2017. Current average well costs are $0.98 million per 1,000 feet of lateral in the Utica, representing a 2% reduction from the third quarter of 2017. Antero is operating one drilling rig and one completion crew in the Utica Shale play.
2017 Performance Highlights
Antero achieved a number of operational successes during the year including:
Marcellus Shale
Ohio Utica Shale
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com. A summary of the results are provided below:
Three Months Ended December 31, |
||||||
Average Daily Volumes: |
2016 |
2017 |
% Change | |||
Low Pressure Gathering (MMcf/d) |
1,522 |
1,711 |
12% | |||
Compression (MMcf/d) |
920 |
1,355 |
47% | |||
High Pressure Gathering (MMcf/d) |
1,437 |
1,842 |
28% | |||
Fresh Water Delivery (MBbl/d) |
150 |
149 |
(1)% | |||
Gross Joint Venture Processing (MMcf/d) |
— |
425 |
* | |||
Gross Joint Venture Fractionation (Bbl/d) |
— |
9,096 |
* |
* |
Not applicable. Antero Midstream has a 50% interest in a processing and fractionation Joint Venture with MarkWest, a wholly-owned subsidiary of MPLX, which was formed in February 2017. |
Net income for the fourth quarter of 2017 was $64 million, a 13% decrease compared to the prior year quarter. The decrease in net income was driven by a $23 million non-cash impairment expense of the condensate pipelines in the Utica not expected to be utilized in Antero Midstream's high-graded infrastructure plan. Net income per limited partner unit was $0.22, a 41% decrease compared to the prior year quarter. Adjusted EBITDA was $142 million, a 13% increase compared to the prior year quarter. The increase in Adjusted EBITDA is primarily driven by increased throughput volumes and contribution from the Joint Venture. Distributable Cash Flow for the fourth quarter of 2017 was $117 million, resulting in a DCF coverage ratio of 1.3x. Distributable Cash Flow is a non-GAAP financial measure. For a description of Distributable Cash Flow and reconciliation to its nearest GAAP measure, please read "Non-GAAP Financial Measures."
Antero Midstream declared a distribution of $0.34 per limited partner unit attributable to the third quarter of 2017, resulting in $34 million of distributions received from Antero Midstream during the fourth quarter of 2017. On January 16, 2018 Antero Midstream declared a distribution of $0.365 per limited partner unit attributable to the fourth quarter of 2017.
Fourth Quarter 2017 Capital Investment
Antero's drilling and completion capital expenditures for the three months ended December 31, 2017, were $335 million. In addition, the Company invested $22 million for land, $92 million for gathering and compression systems and $51 million for water infrastructure projects, including $25 million for the Antero Clearwater Treatment Facility.
2017 Full Year Financial Results
For the year ending December 31, 2017, Antero's net daily production averaged 2,253 MMcfe/d, including 105,470 Bbl/d of liquids (28%). Reported net income was $615 million, or $1.94 per diluted share. Excluding the items detailed in the Company's "Non-GAAP Financial Measures," adjusted net income was $103 million, or $0.33 per diluted share, and adjusted EBITDAX was $1.46 billion. Adjusted EBITDAX margin before settled hedges for the year was $1.52, 92% above the prior year period. Adjusted EBITDAX margin including settled hedges for 2017 was $1.78 per Mcfe, 22% below prior year levels due to lower realized hedge gains. Stand-Alone E&P adjusted EBITDAX for 2017 was $1.24 billion, or $1.51 per Mcfe, 10% below prior year levels due to lower realized hedge gains.
The following table presents a reconciliation of realized price before cash receipts for settled hedges to consolidated and Stand-Alone adjusted EBITDAX margin for the year ended December 31, 2016 and 2017:
Stand-Alone E&P Years Ended |
Consolidated Years Ended | ||||||||||
December 31, |
December 31, | ||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2016 |
2017 |
2016 |
2017 | |||||||
Realized price before cash receipts for settled hedges |
$ |
2.60 |
3.34 |
$ |
2.60 |
$ |
3.34 | ||||
Gathering, compression, and water handling and treatment revenues |
N/A |
N/A |
0.02 |
0.02 | |||||||
Distributions from unconsolidated affiliate |
N/A |
N/A |
0.01 |
0.02 | |||||||
Distributions from Antero Midstream |
0.16 |
0.16 |
N/A |
N/A | |||||||
Gathering, compression, processing and transportation costs |
(1.70) |
(1.75) |
(1.31) |
(1.33) | |||||||
Lease operating expense |
(0.07) |
(0.11) |
(0.07) |
(0.11) | |||||||
Marketing, net |
(0.16) |
(0.13) |
(0.16) |
(0.13) | |||||||
Production and ad valorem taxes |
(0.10) |
(0.11) |
(0.10) |
(0.11) | |||||||
General and administrative(1) |
(0.16) |
(0.15) |
(0.20) |
(0.18) | |||||||
Adjusted EBITDAX margin before settled hedges |
0.57 |
1.25 |
0.79 |
1.52 | |||||||
Cash receipts for settled hedges |
1.48 |
0.26 |
1.48 |
0.26 | |||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.05 |
1.51 |
$ |
2.27 |
$ |
1.78 |
(1) |
Excludes non-cash equity-based compensation |
2017 Capital Investment
In 2017, Antero's drilling and completion capital expenditures were $1.282 billion, 1% below guidance and a 3% decrease compared to the prior year. In addition, the Company invested $204 million for land, excluding $176 million for proved property acquisitions, $346 million for gathering and compression systems, and $195 million for water infrastructure projects, including $123 million for the Antero Clearwater Treatment Facility.
Balance Sheet and Liquidity
As of December 31, 2017, Antero's Stand-Alone E&P net debt was $3.6 billion, of which $185 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility are $2.5 billion. After deducting $705 million in letters of credit outstanding to support pipeline commitments, the Company had $1.6 billion in available Stand-Alone E&P liquidity. As of December 31, 2017, Antero's Stand-Alone E&P net debt to trailing twelve months adjusted EBITDAX ratio was 2.9x.
President and CFO, Glen Warren, commented, "We expect to see a declining leverage profile over the next year as a result of spending within growing cash flow, reduced unutilized marketing expense and fully hedged gas production at $3.50 per MMBtu. The recent decision by S&P to upgrade Antero's corporate debt to BB+ and the initiation by Fitch of a BBB- rating is recognition of Antero's ability to deliver on these strategic and financial goals."
Commodity Hedge Positions
The Company's estimated natural gas production for 2018 at the midpoint of guidance is fully hedged at an average index price of $3.50 per MMBtu. Antero's target natural gas production for 2019 is also fully hedged at an average index price of $3.50 per MMBtu. Antero has hedged 2.8 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from January 1, 2018, through December 31, 2023, at an average index price of $3.39 per MMBtu. As of December 31, 2017, the Company's estimated fair value of commodity derivative instruments was $1.3 billion.
The following table summarizes Antero's hedge position as of December 31, 2017:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
1Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.60 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
19,000 |
$0.75 | ||
NYMEX WTI ($/Bbl) |
— |
— |
4,000 |
$55.97 | ||
2Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.42 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
19,000 |
$0.75 | ||
NYMEX WTI ($/Bbl) |
— |
— |
4,000 |
$55.97 | ||
3Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.45 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
19,000 |
$0.75 | ||
NYMEX WTI ($/Bbl) |
— |
— |
4,000 |
$55.97 | ||
4Q 2018: |
||||||
NYMEX Henry Hub |
2,002,500 |
$3.53 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
19,000 |
$0.75 | ||
NYMEX WTI ($/Bbl) |
— |
— |
4,000 |
$55.97 | ||
2018 Total(1) |
2,002,500 |
$3.50 |
23,000 |
N/A (2) | ||
2019: |
||||||
NYMEX Henry Hub |
2,330,000 |
$3.50 |
— |
— | ||
2020: |
||||||
NYMEX Henry Hub |
1,417,500 |
$3.25 |
— |
— | ||
2021: |
||||||
NYMEX Henry Hub |
710,000 |
$3.00 |
— |
— | ||
2022: |
||||||
NYMEX Henry Hub |
850,000 |
$3.00 |
— |
— | ||
2023: |
||||||
NYMEX Henry Hub |
90,000 |
$2.91 |
— |
— |
(1) |
Since December 31, 2017, Antero has added an incremental 7,000 Bbl/d of Propane MB hedges at $0.80/Gal and 2,000 Bbl/d of NYMEX WTI hedges at $59.03/Bbl |
(2) |
Average index price is not applicable as 2018 liquids hedges include propane and oil hedges. |
Conference Call
A conference call is scheduled on Wednesday, February 14, 2018 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter and full year. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Wednesday, February 21, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10114470.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, February 21, 2018 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the February 14, 2018 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Hedge Gains (Losses) and Gain on Sale of Assets
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets as set forth in this release represents total operating revenue adjusted for non-cash gains (losses) on unsettled hedges and gain on sale of assets. Antero believes that revenue excluding unrealized hedge gains (losses) and gain on sale of assets is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains (losses) and gain on sale of assets is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (losses) and gain on sale of assets (in thousands):
Three Months Ended December 31, |
Years Ended December 31, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Total operating revenue |
$ |
156,216 |
$ |
1,021,726 |
$ |
1,744,525 |
$ |
3,655,574 | ||||
Commodity derivative fair value (gains) losses |
639,805 |
(178,430) |
514,181 |
(636,889) | ||||||||
Cash receipts for settled hedges |
189,524 |
76,548 |
1,003,083 |
213,940 | ||||||||
Gain on sale of assets |
(97,635) |
— |
(97,635) |
— | ||||||||
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets |
$ |
887,910 |
$ |
919,844 |
$ |
3,164,154 |
$ |
3,232,625 |
Adjusted Net Income & Stand-Alone E&P Adjusted Net Income
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Stand-Alone E&P adjusted net income as presented in this release represents net income (loss) that will be reported in the Parent column of Antero's guarantor footnote to its financial statements, adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income and Stand-Alone E&P adjusted net income are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance.
The following table reconciles net income (loss) to adjusted net income (in thousands) and Stand-Alone E&P net income (loss) to Stand-Alone E&P adjusted net income (in thousands):
Stand-Alone E&P |
Consolidated | |||||||||||
Three Months Ended |
Three Months Ended | |||||||||||
December 31, |
December 31, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net income (loss) |
$ |
(485,772) |
486,869 |
$ |
(485,772) |
486,869 | ||||||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
639,805 |
(178,430) |
639,805 |
(178,430) | ||||||||
Cash receipts for settled hedges |
189,524 |
76,548 |
189,524 |
76,548 | ||||||||
Impairment of unproved properties |
115,712 |
76,500 |
115,712 |
76,500 | ||||||||
Impairment of gathering systems and facilities |
N/A |
N/A |
— |
23,431 | ||||||||
Equity-based compensation |
20,071 |
17,673 |
26,754 |
24,520 | ||||||||
Loss on early extinguishment of debt |
16,956 |
1,205 |
16,956 |
1,500 | ||||||||
Gain on sale of assets |
(93,776) |
— |
(97,635) |
— | ||||||||
Income tax effect of reconciling items |
(336,110) |
2,447 |
(337,179) |
(9,056) | ||||||||
Impact of tax reform legislation |
— |
(427,962) |
— |
(427,962) | ||||||||
Adjusted net income |
$ |
66,410 |
54,850 |
$ |
68,165 |
73,920 | ||||||
Stand-Alone E&P |
Consolidated | |||||||||||
Years Ended |
Years Ended | |||||||||||
December 31, |
December 31, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net income (loss) |
$ |
(848,816) |
615,070 |
$ |
(848,816) |
615,070 | ||||||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
514,181 |
(636,889) |
514,181 |
(636,889) | ||||||||
Cash receipts for settled hedges |
1,003,083 |
213,940 |
1,003,083 |
213,940 | ||||||||
Impairment of unproved properties |
162,935 |
159,598 |
162,935 |
159,598 | ||||||||
Impairment of gathering systems and facilities |
N/A |
N/A |
— |
23,431 | ||||||||
Equity-based compensation |
76,372 |
76,162 |
102,421 |
103,445 | ||||||||
Loss on early extinguishment of debt |
16,956 |
1,205 |
16,956 |
1,500 | ||||||||
Gain on sale of assets |
(93,776) |
— |
(97,635) |
— | ||||||||
Income tax effect of reconciling items |
(635,581) |
69,976 |
(643,977) |
50,784 | ||||||||
Impact of tax reform legislation |
— |
(427,962) |
— |
(427,962) | ||||||||
Adjusted net income |
$ |
195,354 |
71,100 |
$ |
209,148 |
102,917 |
Adjusted Operating Cash Flow, Stand-Alone E&P Adjusted Operating Cash Flow and Free Cash Flow
Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items. Stand-Alone E&P Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in working capital items. Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Free cash flow as defined by the Company represents Stand-Alone E&P Adjusted operating cash flow, less Stand-Alone E&P Drilling and Completion capital, less Land Maintenance Capital.
Management believes that Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-Alone E&P basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations. Management believes that Free Cash Flow is a useful measure for assessing the company's financial performance and measuring its ability to generate excess cash from its operations.
There are significant limitations to using Adjusted Operating Cash Flow, Stand-Alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.
Adjusted Operating Cash Flow is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to adjusted cash flow from operations as used in this release (in thousands):
Stand-Alone E&P |
Consolidated | ||||||||||||||
Three Months Ended December 31, |
Three Months Ended December 31, | ||||||||||||||
2016 |
2017 |
2016 |
2017 | ||||||||||||
Net cash provided by operating activities |
$ |
285,637 |
254,078 |
$ |
335,559 |
$ |
313,483 | ||||||||
Net change in working capital |
75,253 |
57,666 |
68,859 |
54,054 | |||||||||||
Adjusted operating cash flow |
360,890 |
311,744 |
404,418 |
367,537 | |||||||||||
Stand-Alone E&P |
Consolidated | ||||||||||||||
Years Ended December 31, |
Years Ended December 31, | ||||||||||||||
2016 |
2017 |
2016 |
2017 | ||||||||||||
Net cash provided by operating activities |
$ |
1,105,238 |
1,836,322 |
$ |
1,241,256 |
$ |
2,006,291 | ||||||||
Net change in working capital |
36,519 |
(87,466) |
32,920 |
(76,035) | |||||||||||
Adjusted cash flow from operations |
1,141,757 |
1,748,856 |
1,274,176 |
1,930,256 | |||||||||||
Total Debt and Net Debt
The following table reconciles consolidated total debt to net debt as used in this release (in thousands):
December 31, |
December 31, | ||||||
2016 |
2017 | ||||||
Bank credit facilities |
$ |
650,000 |
$ |
740,000 | |||
6.00% AR senior notes due 2020 |
— |
— | |||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | |||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | |||||
Net unamortized premium |
1,749 |
1,520 | |||||
Net unamortized debt issuance costs |
(47,776) |
(41,430) | |||||
Consolidated total debt |
$ |
4,703,973 |
$ |
4,800,090 | |||
Less: Cash and cash equivalents |
31,610 |
28,441 | |||||
Consolidated net debt |
$ |
4,672,363 |
$ |
4,771,649 | |||
Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-Alone E&P Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's consolidated financial statements. The GAAP financial measure nearest to Stand-Alone E&P Adjusted EBITDAX is Stand-Alone E&P net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-Alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Stand-Alone E&P |
Consolidated | ||||||||||
Three Months Ended |
Three Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2017 |
2016 |
2017 | ||||||||
Net income (loss) including noncontrolling interest |
$ |
(485,772) |
486,869 |
$ |
(452,804) |
$ |
529,614 | ||||
Commodity derivative fair value (gains) |
639,805 |
(178,430) |
639,805 |
(178,430) | |||||||
Gains on settled derivative instruments |
189,524 |
76,548 |
189,524 |
76,548 | |||||||
Gain on sale of assets |
(93,776) |
— |
(97,635) |
— | |||||||
Interest expense |
59,091 |
53,687 |
67,918 |
63,390 | |||||||
Loss on early extinguishment of debt |
16,956 |
1,205 |
16,956 |
1,500 | |||||||
Income tax expense (benefit) |
(265,621) |
(400,138) |
(265,621) |
(400,138) | |||||||
Depreciation, depletion, amortization, and accretion |
196,682 |
183,439 |
222,443 |
214,397 | |||||||
Impairment of unproved properties |
115,712 |
76,500 |
115,712 |
76,500 | |||||||
Impairment of gathering systems and facilities |
N/A |
N/A |
— |
23,431 | |||||||
Exploration expense |
3,573 |
3,028 |
3,573 |
3,028 | |||||||
Gain on change in fair value of contingent acquisition consideration |
(6,105) |
(3,804) |
N/A |
N/A | |||||||
Equity-based compensation expense |
20,071 |
17,673 |
26,754 |
24,520 | |||||||
Equity in loss (earnings) of unconsolidated affiliate |
N/A |
N/A |
1,542 |
(7,307) | |||||||
Distributions from unconsolidated affiliates |
N/A |
N/A |
7,702 |
10,075 | |||||||
Distributions from Antero Midstream |
28,850 |
33,614 |
N/A |
N/A | |||||||
Equity in net income of Antero Midstream |
5,153 |
22,128 |
N/A |
N/A | |||||||
State franchise taxes |
11 |
— |
11 |
— | |||||||
Total Adjusted EBITDAX |
424,154 |
372,319 |
475,880 |
437,128 | |||||||
Interest expense |
(59,091) |
(53,687) |
(67,918) |
(63,390) | |||||||
Exploration expense |
(3,573) |
(3,028) |
(3,573) |
(3,028) | |||||||
Changes in current assets and liabilities |
(75,253) |
(57,666) |
(68,859) |
(54,054) | |||||||
State franchise taxes |
(11) |
— |
(11) |
— | |||||||
Other non-cash items |
(589) |
(3,860) |
40 |
(3,173) | |||||||
Net cash provided by operating activities |
$ |
285,637 |
254,078 |
$ |
335,559 |
$ |
313,483 |
Stand-Alone E&P |
Consolidated | ||||||||||
Years Ended |
Years Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2017 |
2016 |
2017 | ||||||||
Net income (loss) including noncontrolling interest |
$ |
(848,816) |
$ |
615,070 |
$ |
(749,448) |
$ |
785,137 | |||
Commodity derivative fair value (gains) |
514,181 |
(636,889) |
514,181 |
(636,889) | |||||||
Gains on settled derivative instruments |
1,003,083 |
213,940 |
1,003,083 |
213,940 | |||||||
Gain on sale of assets |
(93,776) |
— |
(97,635) |
— | |||||||
Interest expense |
232,455 |
232,331 |
253,552 |
268,701 | |||||||
Loss on early extinguishment of debt |
16,956 |
1,205 |
16,956 |
1,500 | |||||||
Income tax expense (benefit) |
(496,376) |
(295,051) |
(496,376) |
(295,051) | |||||||
Depreciation, depletion, amortization, and accretion |
712,485 |
707,658 |
812,346 |
827,220 | |||||||
Impairment of unproved properties |
162,935 |
159,598 |
162,935 |
159,598 | |||||||
Impairment of gathering systems and facilities |
N/A |
N/A |
— |
23,431 | |||||||
Exploration expense |
6,862 |
8,538 |
6,862 |
8,538 | |||||||
Gain on change in fair value of contingent acquisition consideration |
(16,489) |
(13,476) |
N/A |
N/A | |||||||
Equity-based compensation expense |
76,372 |
76,162 |
102,421 |
103,445 | |||||||
Equity in loss (earnings) of unconsolidated affiliate |
N/A |
N/A |
(485) |
(20,194) | |||||||
Distributions from unconsolidated affiliate |
N/A |
N/A |
7,702 |
20,195 | |||||||
Distributions from Antero Midstream |
107,364 |
131,598 |
N/A |
N/A | |||||||
Equity in net income of Antero Midstream |
7,156 |
43,710 |
N/A |
N/A | |||||||
State franchise taxes |
50 |
— |
50 |
— | |||||||
Total Adjusted EBITDAX |
1,384,442 |
1,244,394 |
1,536,144 |
1,459,571 | |||||||
Interest expense |
(232,455) |
(232,331) |
(253,552) |
(268,701) | |||||||
Exploration expense |
(6,862) |
(8,538) |
(6,862) |
(8,538) | |||||||
Changes in current assets and liabilities |
(36,519) |
87,466 |
(32,920) |
76,035 | |||||||
State franchise taxes |
(50) |
— |
(50) |
— | |||||||
Proceeds from derivative monetizations |
— |
749,906 |
— |
749,906 | |||||||
Other non-cash items |
(3,318) |
(4,575) |
(1,504) |
(1,982) | |||||||
Net cash provided by operating activities |
$ |
1,105,238 |
1,836,322 |
$ |
1,241,256 |
$ |
2,006,291 |
Antero Midstream Adjusted EBITDA & Distributable Cash Flow
Antero Midstream views Adjusted EBITDA as an important indicator of its performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Three months ended |
Years ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2017 |
2016 |
2017 | ||||||||
Net income |
$ |
73,351 |
64,155 |
$ |
236,703 |
$ |
307,315 | ||||
Interest expense |
9,008 |
10,395 |
21,893 |
37,557 | |||||||
Depreciation expense |
25,761 |
30,958 |
99,861 |
119,562 | |||||||
Impairment of property and equipment expense |
— |
23,431 |
— |
23,431 | |||||||
Accretion of contingent acquisition consideration |
6,105 |
3,804 |
16,489 |
13,476 | |||||||
Equity-based compensation |
6,683 |
6,847 |
26,049 |
27,283 | |||||||
Equity in earnings of unconsolidated affiliates |
1,542 |
(7,307) |
(485) |
(20,194) | |||||||
Distributions from unconsolidated affiliates |
7,702 |
10,075 |
7,702 |
20,195 | |||||||
Gain on asset sale |
(3,859) |
— |
(3,859) |
— | |||||||
Adjusted EBITDA |
$ |
126,293 |
$ |
142,358 |
$ |
404,353 |
$ |
528,625 | |||
Interest paid |
6,115 |
(4,136) |
(13,494) |
(46,666) | |||||||
Decrease in cash reserved for bond interest (1) |
(1,743) |
(8,734) |
(10,481) |
291 | |||||||
Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2) |
(10,481) |
(514) |
(5,636) |
(5,945) | |||||||
Cash distribution to be received from unconsolidated affiliate |
(2,636) |
— |
— |
— | |||||||
Maintenance capital expenditures(3) |
(5,466) |
(12,063) |
(21,622) |
(55,159) | |||||||
Distributable cash flow |
$ |
102,928 |
$ |
116,911 |
$ |
353,120 |
$ |
421,146 | |||
Distributions Declared to Antero Midstream Holders |
|||||||||||
Limited Partners |
50,090 |
68,231 |
182,559 |
247,132 | |||||||
Incentive distribution rights |
7,543 |
23,772 |
16,945 |
69,720 | |||||||
Total Aggregate Distributions |
$ |
57,633 |
$ |
92,003 |
$ |
199,504 |
$ |
316,852 | |||
DCF coverage ratio |
1.79x |
1.27x |
1.78x |
1.33x |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2017.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
ANTERO RESOURCES CORPORATION | |||||||
Consolidated Balance Sheets | |||||||
December 31, 2016 and 2017 | |||||||
(In thousands, except per share amounts) | |||||||
2016 |
2017 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
31,610 |
28,441 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and December 31, 2017, respectively |
29,682 |
34,896 |
|||||
Accrued revenue |
261,960 |
300,122 |
|||||
Derivative instruments |
73,022 |
460,685 |
|||||
Other current assets |
6,313 |
8,943 |
|||||
Total current assets |
402,587 |
833,087 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
2,331,173 |
2,266,673 |
|||||
Proved properties |
9,549,671 |
11,096,462 |
|||||
Water handling and treatment systems |
744,682 |
946,670 |
|||||
Gathering systems and facilities |
1,723,768 |
2,050,490 |
|||||
Other property and equipment |
41,231 |
57,429 |
|||||
14,390,525 |
16,417,724 |
||||||
Less accumulated depletion, depreciation, and amortization |
(2,363,778) |
(3,182,171) |
|||||
Property and equipment, net |
12,026,747 |
13,235,553 |
|||||
Derivative instruments |
1,731,063 |
841,257 |
|||||
Investments in unconsolidated affiliates |
68,299 |
303,302 |
|||||
Other assets |
26,854 |
48,291 |
|||||
Total assets |
$ |
14,255,550 |
15,261,490 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
38,627 |
62,982 |
||||
Accrued liabilities |
393,803 |
443,225 |
|||||
Revenue distributions payable |
163,989 |
209,617 |
|||||
Derivative instruments |
203,635 |
28,476 |
|||||
Other current liabilities |
17,334 |
17,796 |
|||||
Total current liabilities |
817,388 |
762,096 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,703,973 |
4,800,090 |
|||||
Deferred income tax liability |
950,217 |
779,645 |
|||||
Derivative instruments |
234 |
207 |
|||||
Other liabilities |
55,160 |
43,316 |
|||||
Total liabilities |
6,526,972 |
6,385,354 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 314,877 shares and 316,379 shares issued and outstanding at December 31, 2016 and 2017, respectively |
3,149 |
3,164 |
|||||
Additional paid-in capital |
5,299,481 |
6,570,952 |
|||||
Accumulated earnings |
959,995 |
1,575,065 |
|||||
Total stockholders' equity |
6,262,625 |
8,149,181 |
|||||
Noncontrolling interests in consolidated subsidiary |
1,465,953 |
726,955 |
|||||
Total equity |
7,728,578 |
8,876,136 |
|||||
Total liabilities and equity |
$ |
14,255,550 |
15,261,490 |
ANTERO RESOURCES CORPORATION | |||||||
Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||||
Years Ended December 31, 2016 and 2017 | |||||||
(In thousands, except per share amounts) | |||||||
2016 |
2017 |
||||||
Revenue and other: |
|||||||
Natural gas sales |
1,260,750 |
1,769,284 |
|||||
Natural gas liquids sales |
432,992 |
870,441 |
|||||
Oil sales |
61,319 |
108,195 |
|||||
Gathering, compression, water handling and treatment |
12,961 |
12,720 |
|||||
Marketing |
393,049 |
258,045 |
|||||
Commodity derivative fair value gains (losses) |
(514,181) |
636,889 |
|||||
Gain on sale of assets |
97,635 |
— |
|||||
Total revenue and other |
1,744,525 |
3,655,574 |
|||||
Operating expenses: |
|||||||
Lease operating |
50,090 |
89,057 |
|||||
Gathering, compression, processing, and transportation |
882,838 |
1,095,639 |
|||||
Production and ad valorem taxes |
66,588 |
94,521 |
|||||
Marketing |
499,343 |
366,281 |
|||||
Exploration |
6,862 |
8,538 |
|||||
Impairment of unproved properties |
162,935 |
159,598 |
|||||
Impairment of gathering systems and facilities |
— |
23,431 |
|||||
Depletion, depreciation, and amortization |
809,873 |
824,610 |
|||||
Accretion of asset retirement obligations |
2,473 |
2,610 |
|||||
General and administrative (including equity-based compensation expense of $102,421 and $103,445 in 2016 and 2017, respectively) |
239,324 |
251,196 |
|||||
Total operating expenses |
2,720,326 |
2,915,481 |
|||||
Operating income (loss) |
(975,801) |
740,093 |
|||||
Other income (expenses): |
|||||||
Equity in earnings of unconsolidated affiliates |
485 |
20,194 |
|||||
Interest |
(253,552) |
(268,701) |
|||||
Loss on early extinguishment of debt |
(16,956) |
(1,500) |
|||||
Total other expenses |
(270,023) |
(250,007) |
|||||
Income (loss) before income taxes |
(1,245,824) |
490,086 |
|||||
Provision for income tax (expense) benefit |
496,376 |
295,051 |
|||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
(749,448) |
785,137 |
|||||
Net income and comprehensive income attributable to noncontrolling interests |
99,368 |
170,067 |
|||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
(848,816) |
615,070 |
|||||
Earnings (loss) per common share—basic |
(2.88) |
1.95 |
|||||
Earnings (loss) per common share—assuming dilution |
(2.88) |
1.94 |
|||||
Weighted average number of shares outstanding: |
|||||||
Basic |
294,945 |
315,426 |
|||||
Diluted |
294,945 |
316,283 |
ANTERO RESOURCES CORPORATION | |||||||
Consolidated Statements of Cash Flows | |||||||
Years Ended December 31, 2016 and 2017 | |||||||
(In thousands) | |||||||
2016 |
2017 |
||||||
Cash flows provided by operating activities: |
|||||||
Net income (loss) including noncontrolling interests |
(749,448) |
785,137 |
|||||
Adjustment to reconcile net income (loss) to net cash provided by operating activities: |
|||||||
Depletion, depreciation, amortization, and accretion |
812,346 |
827,220 |
|||||
Impairment of unproved properties |
162,935 |
159,598 |
|||||
Impairment of gathering systems and facilities |
— |
23,431 |
|||||
Derivative fair value (gains) losses |
514,181 |
(636,889) |
|||||
Gains on settled derivatives |
1,003,083 |
213,940 |
|||||
Proceeds from derivative monetizations |
— |
749,906 |
|||||
Deferred income tax expense (benefit) |
(485,392) |
(295,126) |
|||||
Gain on sale of assets |
(97,635) |
— |
|||||
Equity-based compensation expense |
102,421 |
103,445 |
|||||
Loss on early extinguishment of debt |
16,956 |
1,500 |
|||||
Equity in earnings of unconsolidated affiliates |
(485) |
(20,194) |
|||||
Distributions of earnings from unconsolidated affiliates |
7,702 |
20,195 |
|||||
Other |
(12,488) |
(1,907) |
|||||
Changes in current assets and liabilities: |
|||||||
Accounts receivable |
39,857 |
(5,214) |
|||||
Accrued revenue |
(133,718) |
(38,162) |
|||||
Other current assets |
1,774 |
(2,755) |
|||||
Accounts payable |
7,365 |
9,462 |
|||||
Accrued liabilities |
18,853 |
64,862 |
|||||
Revenue distributions payable |
34,040 |
45,628 |
|||||
Other current liabilities |
(1,091) |
2,214 |
|||||
Net cash provided by operating activities |
1,241,256 |
2,006,291 |
|||||
Cash flows used in investing activities: |
|||||||
Additions to proved properties |
(134,113) |
(175,650) |
|||||
Additions to unproved properties |
(611,631) |
(204,272) |
|||||
Drilling and completion costs |
(1,327,759) |
(1,281,985) |
|||||
Additions to water handling and treatment systems |
(188,188) |
(194,502) |
|||||
Additions to gathering systems and facilities |
(231,044) |
(346,217) |
|||||
Additions to other property and equipment |
(2,694) |
(14,127) |
|||||
Investments in unconsolidated affiliates |
(75,516) |
(235,004) |
|||||
Change in other assets |
3,977 |
(12,029) |
|||||
Proceeds from asset sales |
171,830 |
2,156 |
|||||
Net cash used in investing activities |
(2,395,138) |
(2,461,630) |
|||||
Cash flows provided by financing activities: |
|||||||
Issuance of common stock |
1,012,431 |
— |
|||||
Issuance of common units by Antero Midstream Partners LP |
65,395 |
248,956 |
|||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
178,000 |
311,100 |
|||||
Issuance of senior notes |
1,250,000 |
— |
|||||
Repayment of senior notes |
(525,000) |
— |
|||||
Borrowings (repayments) on bank credit facilities, net |
(677,000) |
90,000 |
|||||
Make-whole premium on debt extinguished |
(15,750) |
— |
|||||
Payments of deferred financing costs |
(18,759) |
(16,377) |
|||||
Distributions to noncontrolling interests in consolidated subsidiary |
(75,082) |
(152,352) |
|||||
Employee tax withholding for settlement of equity compensation awards |
(26,895) |
(24,174) |
|||||
Other |
(5,321) |
(4,983) |
|||||
Net cash provided by financing activities |
1,162,019 |
452,170 |
|||||
Net increase (decrease) in cash and cash equivalents |
8,137 |
(3,169) |
|||||
Cash and cash equivalents, beginning of period |
23,473 |
31,610 |
|||||
Cash and cash equivalents, end of period |
31,610 |
28,441 |
|||||
Supplemental disclosure of cash flow information: |
|||||||
Cash paid during the period for interest |
239,369 |
263,919 |
|||||
Supplemental disclosure of noncash investing activities: |
|||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
(152,093) |
(547) |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the three months ended December 31, 2016, and December 31, 2017: | ||||||||||||
Three Months Ended December 31, |
Amount of Increase |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
411,814 |
$ |
439,222 |
$ |
27,408 |
7 |
% | ||||
NGLs sales |
158,256 |
280,437 |
122,181 |
77 |
% | |||||||
Oil sales |
19,607 |
28,196 |
8,589 |
44 |
% | |||||||
Gathering, compression, and water handling and treatment |
2,854 |
4,055 |
1,201 |
42 |
% | |||||||
Marketing |
105,855 |
91,386 |
(14,469) |
(14) |
% | |||||||
Commodity derivative fair value gains (losses) |
(639,805) |
178,430 |
818,235 |
* |
||||||||
Gain on sale of assets |
97,635 |
— |
(97,635) |
* |
||||||||
Total operating revenues and other |
156,216 |
1,021,726 |
865,510 |
554 |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
12,900 |
33,023 |
20,123 |
156 |
% | |||||||
Gathering, compression, processing, and transportation |
233,125 |
279,929 |
46,804 |
20 |
% | |||||||
Production and ad valorem taxes |
14,292 |
24,180 |
9,888 |
69 |
% | |||||||
Marketing |
120,822 |
119,983 |
(839) |
(1) |
% | |||||||
Exploration |
3,573 |
3,028 |
(545) |
(15) |
% | |||||||
Impairment of unproved properties |
115,712 |
76,500 |
(39,212) |
(34) |
% | |||||||
Impairment of gathering systems and facilities |
— |
23,431 |
23,431 |
* |
||||||||
Depletion, depreciation, and amortization |
221,816 |
213,731 |
(8,085) |
(4) |
% | |||||||
Accretion of asset retirement obligations |
627 |
666 |
39 |
6 |
% | |||||||
General and administrative (before equity-based compensation) |
38,604 |
35,676 |
(2,928) |
(8) |
% | |||||||
Equity-based compensation |
26,754 |
24,520 |
(2,234) |
(8) |
% | |||||||
Total operating expenses |
788,225 |
834,667 |
46,442 |
6 |
% | |||||||
Operating income (loss) |
(632,009) |
187,059 |
819,068 |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliates |
(1,542) |
7,307 |
8,849 |
* |
||||||||
Interest expense |
(67,918) |
(63,390) |
4,528 |
(7) |
% | |||||||
Loss on early extinguishment of debt |
(16,956) |
(1,500) |
15,456 |
(91) |
% | |||||||
Total other expenses |
(86,416) |
(57,583) |
28,833 |
(33) |
% | |||||||
Income (loss) before income taxes |
(718,425) |
129,476 |
847,901 |
* |
||||||||
Income tax benefit |
265,621 |
400,138 |
134,517 |
51 |
% | |||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
(452,804) |
529,614 |
982,418 |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
32,968 |
42,745 |
9,777 |
30 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(485,772) |
$ |
486,869 |
$ |
972,854 |
* |
|||||
Adjusted EBITDAX (1) |
$ |
475,880 |
$ |
437,128 |
$ |
(38,752) |
(8) |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
135 |
157 |
22 |
16 |
% | |||||||
C2 Ethane (MBbl) |
1,933 |
2,891 |
958 |
50 |
% | |||||||
C3+ NGLs (MBbl) |
5,557 |
6,422 |
865 |
16 |
% | |||||||
Oil (MBbl) |
500 |
571 |
71 |
14 |
% | |||||||
Combined (Bcfe) |
183 |
216 |
33 |
18 |
% | |||||||
Daily combined production (MMcfe/d) |
1,990 |
2,347 |
357 |
18 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
3.05 |
$ |
2.80 |
$ |
(0.25) |
(8) |
% | ||||
C2 Ethane (per Bbl) |
$ |
9.36 |
$ |
10.02 |
$ |
0.66 |
7 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
25.22 |
$ |
39.16 |
$ |
13.94 |
55 |
% | ||||
Oil (per Bbl) |
$ |
39.18 |
$ |
49.37 |
$ |
10.19 |
26 |
% | ||||
Combined (per Mcfe) |
$ |
3.22 |
$ |
3.46 |
$ |
0.24 |
7 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.43 |
$ |
3.67 |
$ |
(0.76) |
(17) |
% | ||||
C2 Ethane (per Bbl) |
$ |
9.36 |
$ |
10.17 |
$ |
0.81 |
9 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
25.60 |
$ |
29.92 |
$ |
4.32 |
17 |
% | ||||
Oil (per Bbl) |
$ |
39.18 |
$ |
49.06 |
$ |
9.88 |
25 |
% | ||||
Combined (per Mcfe) |
$ |
4.26 |
$ |
3.82 |
$ |
(0.44) |
(10) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.07 |
$ |
0.15 |
$ |
0.08 |
114 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.27 |
$ |
1.30 |
$ |
0.03 |
2 |
% | ||||
Production and ad valorem taxes |
$ |
0.08 |
$ |
0.11 |
$ |
0.03 |
38 |
% | ||||
Marketing, net |
$ |
0.08 |
$ |
0.13 |
$ |
0.05 |
63 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.22 |
$ |
0.99 |
$ |
(0.23) |
(19) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.21 |
$ |
0.17 |
$ |
(0.04) |
(19) |
% |
(1) Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the year ended December 31, 2016 compared to the year ended December 31, 2017: | ||||||||||||
Year Ended December 31, |
Amount of Increase |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
1,260,750 |
$ |
1,769,284 |
$ |
508,534 |
40 |
% | ||||
NGLs sales |
432,992 |
870,441 |
437,449 |
101 |
% | |||||||
Oil sales |
61,319 |
108,195 |
46,876 |
76 |
% | |||||||
Gathering, compression, and water handling and treatment |
12,961 |
12,720 |
(241) |
(2) |
% | |||||||
Marketing |
393,049 |
258,045 |
(135,004) |
(34) |
% | |||||||
Commodity derivative fair value gains (losses) |
(514,181) |
636,889 |
1,151,070 |
* |
||||||||
Gain on sale of assets |
97,635 |
— |
(97,635) |
* |
||||||||
Total operating revenues and other |
1,744,525 |
3,655,574 |
1,911,049 |
110 |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
50,090 |
89,057 |
38,967 |
78 |
% | |||||||
Gathering, compression, processing, and transportation |
882,838 |
1,095,639 |
212,801 |
24 |
% | |||||||
Production and ad valorem taxes |
66,588 |
94,521 |
27,933 |
42 |
% | |||||||
Marketing |
499,343 |
366,281 |
(133,062) |
(27) |
% | |||||||
Exploration |
6,862 |
8,538 |
1,676 |
24 |
% | |||||||
Impairment of unproved properties |
162,935 |
159,598 |
(3,337) |
(2) |
% | |||||||
Impairment of property and equipment |
— |
23,431 |
23,431 |
* |
||||||||
Depletion, depreciation, and amortization |
809,873 |
824,610 |
14,737 |
2 |
% | |||||||
Accretion of asset retirement obligations |
2,473 |
2,610 |
137 |
6 |
% | |||||||
General and administrative (before equity-based compensation) |
136,903 |
147,751 |
10,848 |
8 |
% | |||||||
Equity-based compensation |
102,421 |
103,445 |
1,024 |
1 |
% | |||||||
Total operating expenses |
2,720,326 |
2,915,481 |
195,155 |
7 |
% | |||||||
Operating income (loss) |
(975,801) |
740,093 |
1,737,288 |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliates |
485 |
20,194 |
19,709 |
* |
||||||||
Interest expense |
(253,552) |
(268,701) |
(15,149) |
6 |
% | |||||||
Loss on early extinguishment of debt |
(16,956) |
(1,500) |
15,456 |
(91) |
% | |||||||
Total other expenses |
(270,023) |
(250,007) |
20,016 |
(7) |
% | |||||||
Income (loss) before income taxes |
(1,245,824) |
490,086 |
1,735,910 |
* |
||||||||
Income tax benefit |
496,376 |
295,051 |
(201,325) |
(41) |
% | |||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
(749,448) |
785,137 |
1,534,585 |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
99,368 |
170,067 |
70,699 |
71 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(848,816) |
$ |
615,070 |
$ |
1,463,886 |
* |
|||||
Adjusted EBITDAX (1) |
$ |
1,536,144 |
$ |
1,459,571 |
$ |
(76,573) |
26 |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
505 |
591 |
86 |
17 |
% | |||||||
C2 Ethane (MBbl) |
6,396 |
10,539 |
4,143 |
65 |
% | |||||||
C3+ NGLs (MBbl) |
20,279 |
25,507 |
5,228 |
26 |
% | |||||||
Oil (MBbl) |
1,873 |
2,451 |
578 |
31 |
% | |||||||
Combined (Bcfe) |
676 |
822 |
146 |
22 |
% | |||||||
Daily combined production (MMcfe/d) |
1,847 |
2,253 |
406 |
22 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.50 |
$ |
2.99 |
$ |
0.49 |
20 |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.28 |
$ |
8.83 |
$ |
0.55 |
7 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
18.74 |
$ |
30.48 |
$ |
11.74 |
63 |
% | ||||
Oil (per Bbl) |
$ |
32.73 |
$ |
44.14 |
$ |
11.41 |
35 |
% | ||||
Combined (per Mcfe) |
$ |
2.60 |
$ |
3.34 |
$ |
0.74 |
28 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.39 |
$ |
3.61 |
$ |
(0.78) |
(18) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.28 |
$ |
9.04 |
$ |
0.76 |
9 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
21.03 |
$ |
24.27 |
$ |
3.24 |
15 |
% | ||||
Oil (per Bbl) |
$ |
32.73 |
$ |
45.85 |
$ |
13.12 |
40 |
% | ||||
Combined (per Mcfe) |
$ |
4.08 |
$ |
3.60 |
$ |
(0.48) |
(12) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.07 |
$ |
0.11 |
$ |
0.04 |
57 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.31 |
$ |
1.33 |
$ |
0.02 |
2 |
% | ||||
Production and ad valorem taxes |
$ |
0.10 |
$ |
0.11 |
$ |
0.01 |
10 |
% | ||||
Marketing, net |
$ |
0.16 |
$ |
0.13 |
$ |
(0.03) |
(19) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.20 |
$ |
1.01 |
$ |
(0.19) |
(16) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.20 |
$ |
0.18 |
$ |
(0.02) |
(10) |
% |
(1) Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
* Not Meaningful Or Applicable. |
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SOURCE Antero Resources Corporation
DENVER, Jan. 29, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company and its Board of Directors are working with its financial and legal advisors to evaluate various potential measures to address the discount in trading value of Antero's stock relative to some of the premier U.S. large capitalization upstream independents that have a similar profile in terms of leverage, capital efficiency, production growth and free cash flow generation. The potential measures to be evaluated include the return of capital to shareholders.
Over the past several months, Antero conducted a shareholder outreach program in order to solicit feedback from its largest shareholders as to how the Company can improve its corporate governance and compensation practices. At Antero's recent Analyst Day in New York, the Company announced its intent to redesign the 2018 compensation plan based on the feedback received in its shareholder outreach program. Additionally, at the Analyst Day Antero presented a five year outlook based on strip pricing that featured highly efficient capital spending, strong corporate level returns, low leverage, free cash flow generation and scale. This outlook highlighted the valuation discount relative to some of the premier U.S. large capitalization upstream independents. Antero's management team and its Board of Directors are charged with analyzing the merits of potential actions to increase shareholder value.
Commenting on the announcement, Paul Rady, Chairman and CEO, said, "Antero is unique among its Appalachian peers and much of the large capitalization upstream sector with regard to shareholder alignment, in that Antero is run by co-founders who own a significant stake in the Company. This evaluation of potential measures to address our valuation discount is a high priority within our organization and we intend to pursue it with rigor. We have received constructive input from some of our largest shareholders and we will continue to welcome input from our shareholders as part of the evaluation announced today. Management and the Board are committed to evaluating any prudent ideas for increasing long-term shareholder value."
The Company has not set a definitive timetable for completion of this evaluation and there can be no assurances that any initiatives or actions will be announced or completed in the future.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as Antero's ability to identify and execute a plan to increase shareholder value, deliver on its long-term outlook and adopt a compensation plan, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in AR's Annual Report on Form 10-K for the year ended December 31, 2016.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources
DENVER, Jan. 24, 2018 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its fourth quarter and full year 2017 earnings release on Tuesday, February 13, 2018 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Wednesday, February 14, 2018 at 9:00 am MT to discuss the financial and operational results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Wednesday, February 21, 2018 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10114470.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, February 21, 2018 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
For more information, contact Michael Kennedy – SVP – Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
View original content with multimedia:http://www.prnewswire.com/news-releases/antero-resources-announces-fourth-quarter-and-full-year-2017-earnings-release-date-and-conference-call-300587723.html
SOURCE Antero Resources Corporation
DENVER, Jan. 17, 2018 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") and Antero Midstream GP LP (NYSE: AMGP) ("AMGP") today announced their 2018 guidance and extended their long-term targets through 2022. In addition, Antero Midstream provided a fourth quarter 2017 update and its 2018 capital budget. Antero Midstream and AGMP will also host an analyst day tomorrow, January 18, 2018 in New York City. The event will be webcast live beginning at 9:00 am ET and interested parties may access the live audio webcast and related presentation materials on the investor relations website at www.anteromidstream.com or www.anteromidstreamgp.com.
Antero Midstream Highlights Include:
AMGP Highlights Include:
For a discussion of the non-GAAP financial measures Adjusted EBITDA, Distributable Cash Flow, and Free Cash Flow please see "Non-GAAP Financial Measures."
Commenting on the Antero Midstream and AMGP's long-term outlook, Michael Kennedy, Antero Midstream's CFO, said, "Due to our significant visibility into Antero Resources Corporation's (NYSE: AR) ("Antero Resources") long-term development plan, Antero Midstream and AMGP have the ability to extend our top-tier distribution growth targets through 2022. These distribution growth targets are supported by a high-graded organic project backlog of $2.7 billion servicing Antero Resources' internally funded development program over the next five years. The significant opportunity set, along with Antero Midstream's just-in-time capital investment philosophy, allows Antero Midstream to internally fund its organic infrastructure plan with cash flow from operations and revolving credit facility borrowings while generating attractive Partnership wide Return on Invested Capital in the 15% to 20% range."
Antero Midstream and AMGP Long Term Targets
Antero Midstream continues to target annual distribution growth of 28% to 30% through 2020 while maintaining a Distributable Cash Flow ("DCF") coverage ratio averaging 1.25x. In addition, Antero Midstream is initiating targets for 20% distribution growth in 2021 and 2022 while maintaining a DCF coverage ratio of 1.1x to 1.2x. Coinciding with Antero Midstream's distribution targets, following a previously announced 20% across the board increase in targets as a result of corporate tax reform, AMGP continues to target distribution growth of 154% to 172% in 2018, 63% to 65% in 2019 and 51% to 53% in 2020 while maintaining its DCF coverage ratio of 1.0x. In addition, AMGP initiated distribution growth targets of 29% to 31% in 2021 and 27% to 29% in 2022. Antero Midstream and AMGP distribution targets are supported by Antero Midstream's organic growth strategy supporting Antero Resources' development program. Antero Midstream and AMGP's long-term targets exclude the potential impact of third party revenues, acquisitions or divestitures and common equity issuances, consistent with historical practice.
Antero Midstream 2018 Capital Budget
During 2018, Antero Midstream plans to expand its existing Marcellus and Ohio Utica Shale gathering, compression, fresh water delivery systems, and its processing and fractionation joint venture ("Joint Venture") to accommodate Antero Resources development program. Today in a separate news release, Antero Resources announced its 2018 consolidated drilling and completion capital budget of $1.3 billion, which is forecast to generate production growth of 20%. In addition, Antero Resources reaffirmed that it is targeting a 20% compound annual growth rate for net production for the years 2018 through 2020 and introduced 15% annual production growth targets for both 2021 and 2022. Antero Resources' release can be found at www.anteroresources.com.
Commenting on the Antero Resources long-term outlook, along with its impact on Antero Midstream's growth, Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream, said, "Antero Resources' development plan focuses on high margin liquids-rich locations on Antero Midstream dedicated acreage over the next five years. We expect our development plan to generate peer leading growth and approximately $1.6 billion in E&P standalone free cash flow, resulting in a self-funded business model and deleveraging balance sheet. This attractive profile puts Antero Resources in an elite group of E&P's and also provides Antero Midstream with a high level of confidence in its long term throughput and distribution growth targets."
Antero Midstream has budgeted an investment of $585 million and $65 million in expansion and maintenance capital, respectively, resulting in a total Antero Midstream capital budget of $650 million in 2018. This capital budget includes $385 million of capital for gathering and compression infrastructure, resulting in 840 MMcf/d of incremental compression capacity and over 51 miles of incremental gathering pipelines in the Marcellus and Ohio Utica Shales combined. Approximately 90% of the gathering and compression capital is planned to be invested in the Marcellus Shale and the remaining 10% invested in the Ohio Utica Shale. This mix is driven by Antero Resources' development program focus on Marcellus Shale liquids rich drilling on Antero Midstream dedicated acreage.
In addition to capital expenditures for gathering and compression, Antero Midstream has budgeted an investment of $35 million for water infrastructure facilities to construct 25 miles of additional fresh water trunklines and surface pipelines to support Antero's completion activities. Approximately 85% of the water infrastructure budget will be allocated to the Marcellus Shale and the remaining 15% will be allocated to the Ohio Utica Shale. This excludes approximately $15 million of capital for the final completion milestone payments for the Antero Clearwater Facility after delays in the commissioning schedule due to process improvements. The Antero Clearwater Facility is expected to be placed into full commercial service during the first quarter of 2018.
Antero Midstream has budgeted an investment of $215 million for its 50% interest in the Joint Venture with MPLX, LP. During 2018, the Joint Venture expects to place online three additional processing plants, Sherwood 9, 10 and 11, bringing the Joint Venture's total processing capacity to five plants, or 1.0 Bcf/d. Sherwood 9 was placed online earlier this month. Sherwood 10 is expected to be placed online in the third quarter of 2018 and Sherwood 11 is expected to be placed online during the fourth quarter of 2018. In addition, the budget includes the Joint Venture's option to purchase an additional 20,000 Bbls/d of capacity at the Hopedale 4 fractionation plant, which is expected to be placed online during the fourth quarter of 2018.
Antero Midstream expects to fund all 2018 capital expenditures through cash flow from operations and available borrowing capacity within Antero Midstream's existing $1.5 billion bank credit facility. As of September 30, 2017, Antero Midstream had approximately $1.0 billion of liquidity under its credit facility to fund organic growth opportunities.
Below is a comparison of the 2018 capital budget to the 2017 capital budget:
Year Ended December 31, |
||||||
Capital Comparison ($MM) |
2017 |
2018 |
% Change | |||
Gathering and Compression Infrastructure |
$350 |
$385 |
10% | |||
Fresh Water Infrastructure |
75 |
35 |
(53)% | |||
Advanced Wastewater Treatment Facility |
100 |
15 |
(85)% | |||
Processing and Fractionation Joint Venture |
275 |
215 |
(22)% | |||
Total Capital |
$800 |
$650 |
(19)% | |||
Expansion Capital |
$735 |
$585 |
(20)% | |||
Maintenance Capital |
65 |
65 |
- | |||
Total Capital |
$800 |
$650 |
(19)% |
Antero Midstream 2018 Guidance
Antero Midstream is forecasting net income of $435 million to $480 million, Adjusted EBITDA of $705 million to $755 million and Distributable Cash Flow of $575 million to $625 million for 2018. Antero Midstream's 2018 guidance includes $10 to $15 million of distributions from its 15% interest in the Stonewall Gathering Pipeline and $30 to $35 million of distributions from its 50% interest in the Joint Venture. Additionally, Antero Midstream is forecasting annual distribution growth of 28% to 30% as compared to 2017, resulting in an average DCF coverage ratio of 1.25x to 1.35x on an annual basis. Antero Midstream's 2018 guidance excludes any impact from potential third party volumes or transactions.
Below is a comparison of the 2018 guidance to 2017 guidance.
2017 |
2018 |
||||||||
Low |
High |
Low |
High |
% Change | |||||
Net Income ($MM) |
$305 |
— |
$345 |
$435 |
— |
$480 |
41% | ||
Adjusted EBITDA ($MM) |
$520 |
— |
$560 |
$705 |
— |
$755 |
35% | ||
Distributable Cash Flow ($MM) |
$405 |
— |
$445 |
$575 |
— |
$625 |
41% | ||
Year-Over-Year Distribution Growth |
29% |
28% |
— |
30% |
— |
AMGP 2018 Guidance
2017 |
2018(1) | ||||||||
Actual |
Low |
High | |||||||
Distributions Per Share |
$0.16 |
$0.52 |
— |
$0.55 | |||||
Year-Over-Year Distribution Growth |
— |
154% |
— |
172% | |||||
1) |
2018 represents year-over-year growth compared to full-year 2017 distributions. 2017 actual distributions include pro-rated distributions for the second quarter of 2017 for the period following the initial public offering through June 30, 2017. |
Antero Midstream Fourth Quarter 2017 Operating Update
Low pressure gathering volumes for the fourth quarter of 2017 averaged 1,711 MMcf/d, a 12% increase as compared to the fourth quarter of 2016. Low pressure gathering volumes were negatively impacted by lower Antero Resources production in the Utica than budgeted due to the delayed in-service date of the Rover Pipeline. Compression volumes for the fourth quarter of 2017 averaged 1,355 MMcf/d, a 47% increase as compared to the fourth quarter of 2016. High pressure gathering volumes for the fourth quarter of 2017 averaged 1,842 MMcf/d, a 28% increase from the fourth quarter of 2016. High pressure gathering volumes were in excess of low pressure gathering volumes due to Antero Resources' temporary use of an Antero Midstream owned high pressure line to avoid downstream pipeline constraints. The increase in gathering and compression volumes was driven by production growth from Antero Resources in Antero Midstream's area of dedication. Fresh water delivery volumes averaged 149 MBbl/d during the quarter, in line with the fourth quarter of 2016.
Gross processing volumes from the Joint Venture for the fourth quarter of 2017 averaged 425 MMcf/d, an increase of 16% compared to the third quarter of 2017. Gross Joint Venture fractionation volumes averaged 9,096 Bbl/d, a 41% increase sequentially, driven by increased rich gas volumes processed by MPLX and the Joint Venture.
Three Months Ended December 31, |
||||||
Average Daily Volumes: |
2016 |
2017 |
% | |||
Low Pressure Gathering (MMcf/d) |
1,522 |
1,711 |
12% | |||
Compression (MMcf/d) |
920 |
1,355 |
47% | |||
High Pressure Gathering (MMcf/d) |
1,437 |
1,842 |
28% | |||
Fresh Water Delivery (MBbl/d) |
150 |
149 |
(1)% | |||
Gross Joint Venture Processing (MMcf/d) |
— |
425 |
* | |||
Gross Joint Venture Fractionation (Bbl/d) |
— |
9,096 |
* |
Antero Midstream Preliminary Fourth Quarter 2017 Financial Results
Based on preliminary analysis of the financial results for the three months ended December 31, 2017, the Partnership expects net income to be between $61 million and $67 million and Adjusted EBITDA to be between $136 million and $148 million, respectively.
The following reconciles net income to Adjusted EBITDA based on these preliminary financial results for the three months ended December 31, 2017 (in thousands):
Three months ended | ||||||
December 31, 2017 | ||||||
Low |
High | |||||
Net income |
$ |
60,500 |
— |
$ |
66,500 | |
Interest expense |
9,500 |
— |
11,000 | |||
Depreciation expense |
29,000 |
— |
33,000 | |||
Impairment expense |
23,000 |
— |
24,000 | |||
Accretion of contingent acquisition consideration |
3,500 |
— |
4,000 | |||
Equity-based compensation |
6,500 |
— |
7,500 | |||
Equity in earnings of unconsolidated affiliates |
(5,500) |
— |
(8,500) | |||
Distributions from unconsolidated affiliates |
9,500 |
— |
10,500 | |||
Adjusted EBITDA |
$ |
136,000 |
— |
$ |
148,000 | |
The information presented above is based upon information available to the Partnership as of January 17, 2018 and is not a comprehensive statement of the Partnership's financial results. These are preliminary unaudited financial results. The Partnership's completed results to be reported for the three months ended December 31, 2017 may differ materially from these preliminary results. During the course of the preparation of the Partnership's consolidated financial statements and related notes to be included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2017, additional adjustments to the preliminary financial information presented below may be identified. Any such adjustments may be material.
Non-GAAP Financial Measures and Definitions
Antero Midstream views Adjusted EBITDA as an important indicator of the Partnership's performance. Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
The Partnership defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
The Partnership defines Free Cash Flow as cash flow from operating activities before changes in working capital less capital expenditures. Management believes that Free Cash Flow is a useful indicator of the Partnership's ability to internally fund infrastructure investments, service or incur additional debt, and assess the company's financial performance and its ability to generate excess cash from its operations. Management believes that changes in operating assets and liabilities relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred.
The Partnership defines Return on Invested Capital as net income plus interest expense divided by average total liabilities and partners' capital, excluding current liabilities. Management believes that Return on Invested Capital is a useful indicator of the Partnership's return on its infrastructure investments.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Antero Midstream has not included a reconciliation of Adjusted EBITDA and Distributable Cash Flow to the nearest GAAP financial measure for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero Midstream is able to forecast the following reconciling items between Adjusted EBITDA and Distributable Cash Flow and net income (in thousands):
Twelve months ended | ||||||
December 31, 2018 | ||||||
Low |
High | |||||
Depreciation expense |
$ |
160,000 |
— |
$ |
170,000 | |
Equity based compensation expense |
25,000 |
— |
35,000 | |||
Accretion of contingent acquisition consideration |
15,000 |
— |
20,000 | |||
Equity in earnings of unconsolidated affiliates |
30,000 |
— |
40,000 | |||
Distributions from unconsolidated affiliates |
40,000 |
— |
50,000 | |||
The Partnership cannot forecast interest expense due to the timing and uncertainty of debt issuances and associated interest rates. Additionally, Antero Midstream cannot reasonably forecast impairment expense as the impairment is driven by a number of factors that will be determined in the future and are beyond Antero Midstream's control currently.
Free Cash Flow and Return on Invested Capital are non-GAAP financial measures. The GAAP measures most directly comparable to Free Cash Flow and Return on Invested Capital are cash flow from operating activities and net income plus interest expense divided by average total liabilities and partners' capital, respectively. The non-GAAP financial measures of Free Cash Flow and Return on Invested Capital should not be considered as alternatives to the GAAP measure of cash flow from operating activities. Free Cash Flow and Return on Invested Capital are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Free Cash Flow and Return on Invested Capital. You should not consider Free Cash Flow and Return on Invested Capital in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Free Cash Flow and Return on Invested Capital may not be comparable to similarly titled measures of other partnerships.
Antero Midstream has not included reconciliations of Free Cash Flow and Return on Invested Capital to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. Antero Midstream is able to forecast capital expenditures, which is a reconciling item between Free Cash Flow and Return on Invested capital to their most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative capital expenditures of $2.7 billion.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering, compression, processing and fractionation assets as well as integrated water assets that primarily service Antero Resources Corporation's properties located in West Virginia and Ohio. Holders of Antero Midstream common units will receive a Schedule K-1 with respect to distributions received on the common units.
AMGP is a Delaware limited partnership that has elected to be classified as an entity taxable as a corporation for U.S. federal income tax purposes. Holders of AMGP common shares will receive a Form 1099 with respect to distributions received on the common shares. AMGP owns the general partner of Antero Midstream and indirectly owns the incentive distribution rights in Antero Midstream.
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's and AMGP's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release and are based upon a number of assumptions. Although the Partnership and AMGP each believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that the assumptions underlying these forward-looking statements will be accurate or the plans, intentions or expectations expressed herein will be achieved. For example, future acquisitions, dispositions or other strategic transactions may materially impact the forecasted or targeted results described in this release. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Resources.
Antero Midstream and AMGP caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership's and AMGP's control, incident to the gathering and processing and fresh water and waste water treatment businesses. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2016.
For more information, contact Michael Kennedy – CFO of Antero Midstream and AMGP at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream; Antero Midstream GP LP
DENVER, Jan. 17, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced its 2018 capital budget and guidance, extended long-term targets through 2022 and provided an update to 2017. Antero will also host its analyst day tomorrow, January 18, 2018 in New York City. The event will be webcast live beginning at 9:00 am ET. Interested parties may access the live audio webcast and related presentation materials on Antero's investor relations website at http://investors.anteroresources.com.
2018 Guidance and Long-Term Target Highlights Include:
Preliminary Fourth Quarter 2017 Highlights Include:
For a discussion of the non-GAAP financial measures Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted operating cash flow, Consolidated Adjusted operating cash flow and Free Cash Flow, please see "Non-GAAP Financial Measures."
Commenting on Antero's long-term targets, Paul Rady, Chairman and CEO, said, "2018 will be a transformational year for the company as we move toward free cash flow generation, while maintaining our peer leading high margin growth profile. Through continued efficiency gains, we reduced our five-year capital spend target by a cumulative $2.9 billion as compared to last year's internal long term targets, while maintaining our annual production growth targets through 2022. Due to the significant capital efficiencies that we have achieved over the past several years including from longer lateral drilling, we expect to deliver this high growth profile with flat annual drilling and completion spending through 2020 followed by modest spending increases in 2021 and 2022. Antero's ability to target top-tier production growth, while generating free cash flow and a declining leverage profile, speaks to our extensive high quality liquids rich drilling inventory. As the largest NGL producer in the U.S., we have substantial exposure to the improving liquids commodity price environment, which supports our ability to deliver peer leading Adjusted EBITDAX margins and achieve the long term targets outlined here today."
2018 Capital Budget
Antero's consolidated capital budget for 2018 is $1.45 billion, including $1.3 billion for drilling and completion, $25 million for leasehold maintenance and $125 million for discretionary leasehold expenditures. Antero's drilling and completion budget has remained essentially flat for three consecutive years. Net production is expected to average approximately 2.7 Bcfe/d in 2018, representing year-over-year growth of 20% as compared to 2017, including 23% liquids growth to 130,000 Bbl/d. Approximately 80% of the drilling and completion budget for 2018 is allocated to the Marcellus Shale and the remaining 20% is allocated to the Ohio Utica Shale.
The Company's 2018 capital budget excludes Antero Midstream Partners LP's ("Antero Midstream") (NYSE: AM) $650 million capital budget for the construction of low and high pressure gathering pipelines, compressor stations, processing and fractionation facilities, fresh water delivery and advanced wastewater treatment infrastructure. Antero Midstream announced its 2018 capital budget and guidance today in a separate news release, which can be found at www.anteromidstream.com.
In 2018, Antero plans to operate an average of five drilling rigs and four completion crews in the Marcellus Shale and expects to complete 120 to 125 wells with an average lateral length of 9,300 feet. The drilling plan in the Marcellus averages nine wells per pad. As average lateral lengths continue to increase, total well costs are expected to decline further in 2018 to $0.80 million per 1,000' of lateral, a 45% decline from 2014 and a 9% reduction from 2017 well costs.
The Company plans to operate one drilling rig and one completion crew in the Ohio Utica Shale in 2018 and expects to complete 20 to 25 wells with an average lateral length of approximately 11,600 feet. Antero is currently drilling and completing its Utica wells at an average budgeted cost of $0.89 million per 1,000' of lateral, a 43% well cost improvement over 2014 and a 9% improvement from 2017 well costs.
Antero is budgeting to continue to consolidate acreage for development plan purposes in the core of its Marcellus and Ohio Utica leasehold positions in 2018 along with extending leases on acreage that is planned to be developed over the next several years. Antero has budgeted $125 million for discretionary leasehold expenditures and approximately $25 million is budgeted for leasehold maintenance spending required to support the five-year development plan. Consistent with historical practices, the Company does not budget for asset or corporate acquisitions.
The following is a comparison of the 2018 consolidated capital budget to 2017 guidance.
($ in MM) |
Year Ended December 31, | |||||||||
Capital Comparison |
2017 |
2018 |
% Change | |||||||
Drilling & Completion |
$1,300 |
$1,300 |
0% | |||||||
Discretionary Leasehold Capital |
$200 |
$125 |
(38)% | |||||||
Leasehold Maintenance Capital (1) |
N/A |
$25 |
N/A | |||||||
Total Capital |
$1,500 |
$1,450 |
(3)% | |||||||
Average Operated Drilling Rigs (2) |
6 |
6 |
0% | |||||||
Average Operated Completion Crews (2) |
5 |
5 |
0% | |||||||
Operated Wells Spud (2) |
117 |
115 - 125 |
0% | |||||||
Operated Wells Completed (2) |
135 |
140 - 150 |
7% | |||||||
1) |
Leasehold maintenance capital expenditures were not previously guided to in 2017. Leasehold maintenance capital represents the leasehold capital required to achieve targeted working interest of 95% included in the five year targeted development plan, plus renewals associated with the 5-year development plan. |
2) |
Adjusted for 2017 actuals. |
The 2018 capital budget is expected to be primarily funded through cash flow from operations, with any additional funding coming from available borrowing capacity on Antero's bank credit facility. As of September 30, 2017, Antero had $2.9 billion of available consolidated liquidity.
2018 Guidance
Antero's 2018 net daily production, including liquids, is forecast to grow 20% as compared to 2017 volumes to approximately 2.7 Bcfe/d. Net liquids production is forecast to increase approximately 23% to an average of 130,000 Bbl/d in 2018, including 77,500 Bbl/d of C3+ NGLs, 43,000 Bbl/d of ethane and 9,500 Bbl/d of condensate.
Natural Gas and NGL Price Realizations and Cash Costs
The Company expects to realize a $0.00 to $0.05 price premium compared to Nymex for its natural gas sales during 2018. Antero's firm transportation and sales portfolio allows the Company to transport and sell virtually all of its natural gas production at current favorably priced indices, including TCO, Chicago, MichCon and Gulf Coast hubs. Driven by improved local differentials and the Mariner East 2 project, Antero is forecasting an average realized price for C3+ NGLs of 62.5% to 67.5% of WTI oil prices in 2018 compared to 60% of WTI oil for 2017 C3+ NGL pricing. Accordingly, the sales points for propane and butane are expected to be a combination of Marcus Hook, PA and Houston, PA. Antero is forecasting oil price differentials to WTI of $5.00 to $6.00 per barrel in 2018. Combining the expected improvement in pricing for NGLs and continued strong oil prices, Antero expects an overall increase in Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX of approximately $300 million from liquids in 2018 compared to 2017, before the impact of hedging.
Antero is forecasting a modest increase in Cash Production Expenses due to an increase in transportation expenses. The increase in transportation expenses are associated with Antero's firm commitments on new pipelines that have recently been placed in service or are expected to be placed in service during 2018. The new pipeline commitments allow Antero to continue to deliver natural gas to premium indices and receive a positive differential to Nymex. Net marketing expense is expected to remain flat at $0.10 to $0.15 per Mcfe in 2018 as the increase in unutilized pipeline capacity due to Antero's new firm commitment is offset by increasing production throughout the year and mitigation efforts executed in the first quarter of 2018.
The Company is providing the following guidance for 2018 on both a consolidated and an Antero Resources stand-alone basis:
2018 Guidance |
Consolidated |
Stand-alone E&P | ||||||
Low |
High |
Low |
High | |||||
Production |
||||||||
Net Daily Production (MMcfe/d) |
2,700 1,925 130,000 77,500 43,000 9,500 |
2,700 1,925 130,000 77,500 43,000 9,500 | ||||||
Net Daily Residue Natural Gas Production (MMcf/d) |
||||||||
Net Daily Liquids Production (Bbl/d) |
||||||||
Net Daily C3+ NGL Production (Bbl/d) |
||||||||
Net Daily Ethane Production (Bbl/d) |
||||||||
Net Daily Oil Production (Bbl/d) |
||||||||
Realized Pricing (1) |
||||||||
Natural Gas Realized Price vs. Nymex Henry Hub ($/Mcf)(2) |
$0.00 |
$0.05 |
$0.00 |
$0.05 | ||||
Oil Realized Price vs. WTI Oil ($/Bbl) |
$(5.00) |
$(6.00) |
$(5.00) |
$(6.00) | ||||
C3+ NGL Realized Price (% of Nymex WTI) (1) |
62.5% |
67.5% |
62.5% |
67.5% | ||||
Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) |
$(0.03) |
$(0.05) |
$(0.03) |
$(0.05) | ||||
Cash Expenses |
||||||||
Cash Production Expense ($/Mcfe)(3) |
$1.65 |
$1.75 |
$2.10 |
$2.20 | ||||
Marketing Expense, Net of Marketing Revenue ($/Mcfe) |
$0.10 |
$0.15 |
$0.10 |
$0.15 | ||||
G&A Expense ($/Mcfe) (4) |
$0.15 |
$0.20 |
$0.125 |
$0.175 | ||||
Adjusted Operating Cash Flow ($MM) (5) |
$1,750 - $1,900 |
$1,480 - $1,600 | ||||||
Adjusted EBITDAX ($MM) (5) |
$2,050 - $2,150 |
$1,700 - $1,800 | ||||||
Capital Expenditures |
||||||||
Drilling and Completion Capital ($MM) (6) |
$1,300 |
$1,500 | ||||||
Leasehold Maintenance Capital ($MM) |
$25 |
$25 | ||||||
Discretionary Land Capital ($MM) |
$125 |
$125 | ||||||
Total |
$1,450 |
$1,650 |
(1) |
Based on strip pricing as of December 31, 2017; natural gas price of $2.84/Mcf and WTI of $59.57/Bbl, all prices before hedging. |
(2) |
Includes Btu upgrade as Antero's processed tailgate and unprocessed dry gas production is greater than 1050 Btu on average. |
(3) |
Includes lease operating expenses, gathering, compression, transportation expenses and production and ad valorem taxes. Stand-alone cash production expense includes 100% of gathering and compression and water fees paid to Antero Midstream that are eliminated on a consolidated basis. |
(4) |
Excludes equity-based compensation. |
(5) |
For a description of the non-GAAP financial measures Adjusted Operating Cash Flow and Adjusted EBITDAX, please read "Non-GAAP Financial Measures." |
(6) |
Stand-alone Drilling and Completion Capital includes 100% of the water fees paid to Antero Midstream that are eliminated on a consolidated basis and capitalized on a Stand-alone basis. |
Extended Long-Term Targets
As a result of continued capital efficiency gains, significant liquids exposure, favorable price realizations due to firm transportation arrangements, attractively hedged gas prices and Appalachian-leading core drilling inventory, Antero is maintaining its 20% compound annual growth rate target for net gas equivalent production through 2020 and is introducing a 15% growth rate target in each of 2021 and 2022. This equates to a debt-adjusted compounded annual production growth rate of 24% through 2020 and 20% to 24% in each of 2021 and 2022. Antero is able to forecast this long-term growth target, despite reducing the targeted 5-year drilling and completion capital by a cumulative $2.9 billion compared to the 2017 long-term outlook. Due to these substantial efficiency improvements, driven by a combination of longer laterals, improved cycle times, capital allocation and enhanced recoveries, Antero is now targeting Free Cash Flow generation of approximately $1.6 billion over the five-year period based on year end 2017 strip pricing of $54.71/Bbl WTI and $2.84/MMBtu natural gas and $2.8 billion over the five-year period assuming flat $60 per barrel WTI oil and $2.85/MMBtu natural gas prices. Antero expects this to result in a declining net debt to Adjusted EBITDAX ratio to the low 2.0-times range by year end 2018 and below 2.0 times in 2019, assuming strip pricing.
Antero forecasts the percentage of natural gas production sold at current favorably priced indices through 2022 to improve relative to 2018 guidance resulting in natural gas price realizations, before hedges, at a $0.05 to $0.10 per Mcf premium to Nymex including the BTU premium. Further enhancing price realizations, Antero has hedged approximately 80% of natural gas production targets for the years 2018 through 2020 at an average hedged price of $3.50 per MMBtu. The Company has 2.8 Tcfe hedged through 2023 with a mark to market value of approximately $1.3 billion, based on December 31, 2017 strip pricing.
Updated for the longer lateral drilling plan, Antero has an inventory of approximately 3,300 undrilled core 3P locations with an average lateral length of 10,800 feet. Approximately 59% of Antero's drilling inventory is comprised of laterals greater than 10,000 feet and 44% is greater than 12,000 feet.
Supported by Antero Resources' long-term production growth targets, Antero Midstream today announced a long-term distribution growth target of 28% to 30% per year through 2020 and 20% per year in 2021 and 2022. As of December 31, 2017, Antero Resources owned approximately 53% of Antero Midstream common units.
Commenting on the 2018 capital budget and guidance, Glen Warren, Antero's President and CFO, said, "Continued drilling efficiency improvements, a longer lateral drilling program, strong production growth and our position as the largest NGL producer in the U.S. provides a significant step-up in free cash flow over our extended five-year outlook. Our $1.6 billion in targeted Free Cash Flow generation through 2022 before discretionary leasehold acquisitions, (based on current strip pricing) is expected to provide significant financial flexibility to pay down debt or return capital to shareholders. We forecast a significant decrease in leverage ratios to the low 2.0-times on a stand-alone basis by year-end 2018, with further declines over the five-year outlook when using the Free Cash Flow to pay down debt. This profile places Antero in an elite group comprised of a handful of upstream companies that are generating double digit percentage production growth and near term free cash flow on the foundation of a strong balance sheet and a large core drilling inventory."
Fourth Quarter 2017 Operating Update
Antero's net daily production for the fourth quarter of 2017 averaged 2,347 MMcfe/d, including 1,702 MMcf/d (72%) of natural gas, 101,226 Bbl/d (26%) of natural gas liquids, including 31,425 Bbl/d of ethane, and 6,207 Bbl/d (2%) of oil.
The following table provides an update to Adjusted EBITDAX for the fourth quarter of 2017, including a revised range for Consolidated Adjusted EBITDAX of $430 - $445 million, up from the $410 - $440 million original guidance and Stand-alone E&P Adjusted EBITDAX that is expected to be $370 - $385 million:
($MM) |
Consolidated |
Stand-alone E&P | ||||||
Net income or loss including noncontrolling interests |
$515 - $550 |
$480 - $500 | ||||||
Adjusted EBITDAX (1) |
$430 - $445 |
$370 - $385 | ||||||
(1) |
For a description of the non-GAAP financial measure, Adjusted EBITDAX, please read "Non-GAAP Financial Measures." Stand-alone E&P Adjusted EBITDAX includes 100% of gathering and compression and water fees paid to Antero Midstream that are eliminated on consolidated basis and expensed on Stand-alone basis. |
Fourth quarter 2017 production represents an organic production growth rate of 18% from the fourth quarter of 2016 and a 1% increase compared to the third quarter of 2017. Fourth quarter 2017 production was negatively impacted by the delayed in-service date of the Rover Pipeline, resulting in 10 Utica wells not being placed into sales until year-end 2017. Those 10 wells are currently producing approximately 175 MMcfe/d on restricted choke and were previously scheduled to come on-line in November 2017. Liquids production for the fourth quarter of 2017 represents an organic production growth rate of 24% from the fourth quarter of 2016 and a 4% decrease sequentially. The sequential decline in liquids production reflects the effect of higher NGL distributions to royalty owners as a result of the improvement in liquids pricing.
Antero's average realized natural gas price before settled derivatives for the fourth quarter of 2017 was $2.80 per Mcf, a $0.13 per Mcf negative differential to the average Nymex price for the period. This differential represents an improvement from the $0.29 per Mcf negative differential to Nymex realized in the third quarter of 2017. The improvement was primarily driven by reduced impacts from the disputes with Washington Gas Light Company and one of its affiliates (collectively, "WGL") and South Jersey Resources Group and one of its affiliates (collectively, "South Jersey"), which negatively impacted realizations by $0.18 per Mcf and $0.02 per Mcf, respectively during the quarter compared to $0.22 per Mcf and $0.04 per Mcf, respectively, during the third quarter of 2017. Looking ahead to 2018, Antero does not expect a material impact to its realized pricing and cash flow from these contractual disputes due in part to additional takeaway capacity that is expected to be placed in service throughout the year and narrow regional basis differentials based on current strip pricing.
Antero's average realized C3+ NGL price before settled derivatives for the fourth quarter of 2017 was $39.16 per barrel, or approximately 71% of the average WTI oil price for the period. This reflects a 55% increase in realized price as compared to the fourth quarter of 2016 and a 35% increase sequentially. The increase was driven primarily by the strengthening of Mont Belvieu pricing relative to WTI, which continues to benefit by an increase in export volumes.
Antero's average realized oil price before hedging for the fourth quarter of 2017 was $49.37 per barrel, a $6.00 per barrel negative differential to the average WTI oil price. The Company's average realized oil price after hedging for the quarter was $49.06 per barrel, a $6.31 per barrel negative differential to the average WTI oil price.
The following table details the components of average net production average realized prices for the three months ended December 31, 2017:
Three Months Ended December 31, 2017 | |||||||||||||||
Gas |
Oil |
NGL (C3+) |
Ethane (C2) |
Combined | |||||||||||
Average Net Production |
1,702 |
6,207 |
69,801 |
31,425 |
2,347 | ||||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
NGL (C3+) |
Ethane (C2) ($/Bbl) |
Combined | ||||||||||
Average realized price before settled derivatives |
$ |
2.80 |
$ |
49.37 |
$ |
39.16 |
$ |
10.02 |
$ |
3.46 | |||||
Settled derivatives |
0.87 |
(0.31) |
(9.24) |
0.15 |
0.36 | ||||||||||
Average realized price after settled derivatives |
$ |
3.67 |
$ |
49.06 |
$ |
29.92 |
$ |
10.17 |
$ |
3.82 | |||||
Nymex average price |
$ |
2.93 |
$ |
55.37 |
$ |
2.93 | |||||||||
Premium / (Differential) to Nymex |
$ |
0.74 |
$ |
(6.31) |
$ |
0.89 |
The information presented above is based upon information available to the Company as of January 17, 2018 and is not a comprehensive statement of the Company's financial results. These are preliminary non-reviewed unaudited financial results. The Company's completed results to be reported for the three months ended December 31, 2017 may differ materially from this preliminary data. During the course of the preparation of the Company's consolidated financial statements and related notes to be included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, additional adjustments to the preliminary financial information presented herein may be identified. Any such adjustments may be material.
Analyst Day Presentation and Live Webcast
Antero plans to host an analyst day on Thursday, January 18, 2018 in New York City. Interested parties may access the live audio webcast and related presentation materials by visiting the investor relations section on Antero's website as detailed below. Paul Rady, Chairman and Chief Executive Officer, and Glen Warren, President and Chief Financial Officer, along with other Antero executives, will present Antero's corporate strategy and long-term outlook. The event will be webcast live beginning at 9:00 am ET and may be accessed on Antero's investor relations website at http://investors.anteroresources.com. A replay of the webcast will also be available on Antero's investor relations website.
Non-GAAP Financial Measures
Debt-adjusted production growth is defined as net production per Debt-Adjusted share for each specified period. Debt-adjusted shares represent period ending projected debt balances divided by ending share price plus ending shares outstanding. Forecasted debt-adjusted shares assumes Antero share price of $19.87 per share as of January 12, 2018.
Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow are financial measures that are not calculated in accordance with U.S. generally accepted accounting principles ("GAAP"). The non-GAAP financial measures used by the company may not be comparable to similarly titled measures utilized by other companies. These measures should not be considered in isolation or as substitutes for their nearest GAAP measures. The Stand-alone measures are presented to isolate the results of the operations of Antero apart from the performance of Antero Midstream, which is otherwise consolidated into the results of Antero.
Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX
Consolidated Adjusted EBITDAX as defined by the Company represents net income or loss from continuing operations, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Consolidated Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.
Stand-alone E&P Adjusted EBITDAX as defined by the Company represents income or loss from continuing operations as reported in the Parent column of Antero's guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero's consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. While there are limitations associated with the use of Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company's financial performance because these measures:
There are significant limitations to using Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-alone basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX provide no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow
Consolidated Adjusted Operating Cash Flow as defined by the Company represents net cash provided by operating activities before changes in current assets and liabilities. Stand-alone E&P Adjusted Operating Cash Flow as defined by the Company represents Stand-alone net cash provided by operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements before changes in current assets and liabilities, plus earn out payments of $125 million expected in each of 2019 and 2020 from Antero Midstream associated with the water drop down transaction that occurred in 2015. Free cash flow as defined by the Company represents Stand-alone E&P Adjusted operating cash flow, less Stand-alone E&P Drilling and Completion capital, less Land Maintenance Capital.
The GAAP financial measure nearest to Consolidated Adjusted Operating Cash Flow is cash flow from operating activities as reported in Antero's consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow is Stand-alone cash flow from operating activities that will be reported in the Parent column of Antero's guarantor footnote to its financial statements. Management believes that Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow are useful indicators of the company's ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-alone basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations. Management believes that Free Cash Flow is a useful measure for assessing the company's financial performance and measuring its ability to generate excess cash from its operations.
There are significant limitations to using Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company's net income on a consolidated and Stand-alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow reported by different companies. Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.
The following table provides a range of preliminary results for the fourth quarter of 2017:
($MM)
|
Three Months Ended December 31, 2017 | ||||||||||
Consolidated |
Stand-alone E&P | ||||||||||
Low |
High |
Low |
High | ||||||||
Net income including noncontrolling interest (1) |
$ |
525,000 |
— |
$ |
560,000 |
$ |
490,000 |
— |
$ |
510,000 | |
Commodity derivative (gains) |
(175,000) |
— |
(180,000) |
(175,000) |
— |
(180,000) | |||||
Gains (losses) on settled derivative instruments |
76,000 |
— |
78,000 |
76,000 |
— |
78,000 | |||||
Interest expense |
62,000 |
— |
64,000 |
50,000 |
— |
55,000 | |||||
Loss on early extinguishment of debt |
1,000 |
— |
2,000 |
1,000 |
— |
2,000 | |||||
Provision (benefit) for income taxes |
(390,000) |
— |
(430,000) |
(390,000) |
— |
(430,000) | |||||
Depreciation, depletion, amortization, and accretion |
210,000 |
— |
218,000 |
176,000 |
— |
191,000 | |||||
Impairment of unproved properties |
70,000 |
— |
77,000 |
70,000 |
— |
77,000 | |||||
Impairment of fixed assets and other |
22,000 |
— |
24,000 |
— |
— |
— | |||||
Exploration expense |
3,000 |
— |
4,000 |
3,000 |
— |
4,000 | |||||
Gain on change in fair value of contingent acquisition consideration |
— |
— |
— |
(3,000) |
— |
(4,000) | |||||
Equity-based compensation expense |
23,000 |
— |
25,000 |
17,000 |
— |
20,000 | |||||
Equity in earnings of unconsolidated affiliate |
(6,000) |
— |
(8,000) |
— |
— |
— | |||||
Distributions from unconsolidated affiliates |
9,000 |
— |
11,000 |
— |
— |
— | |||||
Equity in income of Antero Midstream |
— |
— |
— |
22,000 |
— |
28,000 | |||||
Distributions from limited partner interest in Antero Midstream |
— |
— |
— |
33,000 |
— |
34,000 | |||||
Adjusted EBITDAX |
$ |
430,000 |
$ |
445,000 |
$ |
370,000 |
$ |
385,000 | |||
(1) |
The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income including noncontrolling interest as reported in Antero's consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of AR's guarantor footnote to its financial statements. |
Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-alone E&P Adjusted EBITDAX to their nearest GAAP financial measures for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero is able to forecast the following reconciling items between Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX to net income from continuing operations including noncontrolling interest:
(in thousands) |
|||||||
Consolidated |
Stand-alone E&P | ||||||
Low |
High |
Low |
High | ||||
Interest expense |
$250,000 |
$300,000 |
$200,000 |
$220,000 | |||
Depreciation, depletion, amortization, and accretion expense |
950,000 |
1,050,000 |
800,000 |
900,000 | |||
Impairment expense |
100,000 |
125,000 |
100,000 |
125,000 | |||
Exploration expense |
5,000 |
15,000 |
5,000 |
15,000 | |||
Equity-based compensation expense |
95,000 |
115,000 |
70,000 |
90,000 | |||
Equity in earnings of unconsolidated affiliate |
30,000 |
40,000 |
N/A |
N/A | |||
Distributions from unconsolidated affiliates |
40,000 |
50,000 |
N/A |
N/A | |||
Distributions from limited partner interest in Antero Midstream |
N/A |
N/A |
166,000 |
170,000 |
Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets, for 2018. For income tax expense (benefit), Antero is forecasting a 2018 effective tax rate of 18% to 19%.
Antero has not included reconciliations of Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. However, Antero is able to forecast the earn out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015, each of which is a reconciling item between Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow, as applicable, and cash flow from operating activities as reported in the Parent column of Antero's guarantor footnote to its financial statements. Antero forecasts these items to be $125 million in each of 2019 and 2020. Additionally, Antero is able to forecast lease maintenance expenditures and Stand-alone drilling and completion capital, each of which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative lease maintenance expenditures of $200 million and cumulative Stand-alone E&P drilling and completion capital of $8.6 billion.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow, Free Cash Flow, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
AR cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the AR's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in AR's Annual Report on Form 10-K for the year ended December 31, 2016.
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SOURCE Antero Resources Corporation
DENVER, Nov. 29, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company"), Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream") and Antero Midstream GP LP (NYSE: AMGP) ("AMGP") plan to host their first joint analyst day meeting on Thursday, January 18, 2018 in New York City for institutional investors and sell-side analysts. Other interested parties may access the live audio webcast and related presentation materials by visiting the investor relations section on Antero's website as detailed below. Paul Rady, Chairman and Chief Executive Officer, and Glen Warren, President and Chief Financial Officer, along with other Antero executives, will present Antero's corporate strategy and long-term outlook.
The event will be webcast live beginning at 9:00 am ET and may be accessed on Antero's investor relations website at http://investors.anteroresources.com. A replay of the webcast will also be available on Antero's investor relations website.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering, compression, processing and fractionation assets as well as integrated water assets that primarily service Antero Resources Corporation's properties located in West Virginia and Ohio. Holders of Antero Midstream common units will receive a Schedule K-1 with respect to distributions received on the common units.
AMGP is a Delaware limited partnership that has elected to be classified as an entity taxable as a corporation for U.S. federal income tax purposes. Holders of AMGP common shares will receive a Form 1099 with respect to distributions received on the common shares. AMGP owns the general partner of Antero Midstream and indirectly owns the incentive distribution rights in Antero Midstream.
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SOURCE Antero Resources Corporation; Antero Midstream GP LP; Antero Midstream Partners LP
DENVER, Nov. 1, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its third quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, which has been filed with the Securities and Exchange Commission (the "SEC").
Highlights Include:
Commenting on the quarter and long-term outlook, Paul Rady, Chairman and CEO, said, "We took a number of steps during the quarter to delever the balance sheet, and have positioned Antero to generate attractive growth and returns while spending within cash flow in 2018 and beyond. This is a testament to the capital efficiencies and EUR improvements that we have achieved to date. Through increased EURs and lower well costs, we have been able to reduce our drilling and completion capital spending plans over the 2018 through 2020 period by approximately $1.5 billion while delivering the same production growth. Importantly, this production growth includes rapid NGL production growth, providing us with substantial upside exposure to a continuing rise in liquids pricing. The combination of the sizeable reduction in capital needs with the increased liquids cash flow provides Antero with declining leverage and an improving balance sheet. This trend positions Antero to be able to return capital to shareholders in the coming years, subject to Board review and approval."
Recent Developments
Antero Three Year Outlook
Based on the Company's internal development plan, Antero is targeting a compound annual production growth rate of 20% over the four year period of 2017 to 2020, with a drilling and completion capital program that is self-funded with E&P stand-alone cash flow. The current development plan assumes flat $3.00/MMBtu NYMEX gas and $54/Bbl WTI oil, in line with 2018 strip pricing, and a targeted drilling and completion capital program of approximately $1.3 billion in 2018, $1.5 billion in 2019 and $1.5 billion in 2020. These capital budget targets have not been approved by Antero's Board. The $1.3 billion targeted drilling and completion capital program in 2018 reflects the third consecutive year of maintaining a flat capital program while still delivering top tier production growth. Additionally, as a result of increased EURs, lower well costs, and land consolidation efforts supporting long lateral drilling, this development plan represents a reduction of 200 wells and approximately $1.5 billion in capital through 2020 when compared to the prior development plan targeting the same production growth. This capital plan focuses on liquids-rich, high margin locations designed to deliver significant per share cash flow and production growth over the next three years.
Updated NGL Pricing Realizations Forecast
Based on public company disclosure, Antero is now the largest NGL producer in the U.S. with 105,609 Bbl/d produced in the third quarter of 2017, representing 37% growth compared to the prior year quarter. This includes 75,290 Bbl/d of C3+ NGLs and 30,319 Bbl/d of recovered ethane. Antero's average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter. Due to continued strength in domestic C3+ NGL markets and export demand, Antero is forecasting realizations of 70% to 75% of WTI on its C3+ NGL production for the fourth quarter of 2017. In addition, based on strip pricing, Antero is forecasting realizations of approximately $35/Bbl, or 65% of WTI for 2018. Based on current strip prices and production targets, Antero estimates that cash flow from liquids production is forecast to be approximately $390 million higher in 2018 as compared to 2017.
Completion of $1 Billion Delevering Program
Antero previously announced that it monetized over $1 billion of non-exploration and production ("E&P") assets in September 2017. This includes the sale of 10 million common units representing limited partner interests in Antero Midstream Partners LP (NYSE:AM) ("Antero Midstream") and the restructuring of a portion of its commodity hedge portfolio. Proceeds from the monetization program were used to repay credit facility borrowings. The monetization program was tax-efficient due to the utilization of a portion of Antero's $1.6 billion of net operating losses. Antero Resources' stand-alone E&P net debt to last twelve months stand-alone adjusted EBITDAX ratio was 2.6x and its consolidated net debt to last twelve months consolidated adjusted EBITDAX ratio was 3.0x as of September 30, 2017, a reduction of 0.4x and 0.6x, respectively, as compared to June 30, 2017. For a description of stand-alone E&P net debt and Adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
New Credit Facility Agreement
Antero has entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion. The $4.5 billion borrowing base under the credit facility represents a $250 million reduction from the Company's previous borrowing base of $4.75 billion net of the $750 million hedge monetization executed in September 2017. Lender commitments were reduced by $1.5 billion from the previous commitments of $4.0 billion. The decision to materially reduce lender commitments reflects Antero's current essentially undrawn balance on its facility and its plan to primarily fund its drilling program with cash flow from operations. The new credit facility matures in October 2022, subject to certain exceptions, and includes fall away covenants that are triggered if and when Antero is assigned an investment grade credit rating by the rating agencies. The credit facility is supported by a bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. The bank syndicate is comprised of 24 banks, 23 of which were lenders in the prior credit facility.
Commenting on liquids exposure, the recent delevering program and the new credit facility, Glen Warren, President and CFO, said, "As the largest NGL producer in the U.S. during the third quarter, Antero continues to benefit from the significant increase in NGL pricing that has occurred over the last several months. NGL production has been a key pillar of our business strategy for a number of years and we believe that it will be a key differentiator for Antero for many years to come. The Mariner East 2 NGL pipeline project will be completed soon and export demand continues to grow. The increase in cash flow associated with our liquids-rich drilling inventory is one of the many drivers behind our decision to lower commitments on our new credit facility to $2.5 billion. The $1.5 billion reduction in commitments not only reflects the fact that we are essentially undrawn on our facility today, but is also a function of Antero's plan to primarily fund our drilling program with cash flow from operations and distributions from our ownership in Antero Midstream."
Contract Disputes
During the third quarter of 2017, Antero's realized natural gas price was negatively impacted by contract disputes with two counterparties related to two separate long-term natural gas sales agreements.
WGL's Natural Gas Sales Contract
Antero is currently contracted to sell and deliver natural gas volumes varying between 500,000 MMBtu/d and 600,000 MMBtu/d to Washington Gas Light Company, a regulated utility based in Washington, D.C. and WGL Midstream, Inc. (collectively, "WGL") at a delivery point in Braxton, West Virginia where the Stonewall Pipeline interconnects with Columbia's WB Pipeline. Beginning in April 2017, WGL failed to take delivery of a portion of the contracted sales volume in direct violation of the contract terms due to WGL's lack of downstream primary firm transportation capacity to move the purchased gas. WGL's nonperformance under the contract has resulted in Antero selling approximately 380,000 MMBtu/d, on average, of natural gas volumes that WGL was obligated to take at other regional indices at a lower price relative to the contracted price. Per its contracts, Antero has invoiced WGL for cover damages resulting from reselling the contracted natural gas at lower prices, which WGL has failed to pay. For the three months ended September 30, 2017, this has resulted in a loss of approximately $40 million net to Antero and resulted in a $(0.22)/Mcf negative impact to Antero's total company realized natural gas pricing. Year to date through September 30, 2017, cover damages net to Antero have totaled approximately $55 million. Antero will continue to vigorously seek recovery of its cover damages, as clearly defined in the contracts, and other unpaid amounts as part of its claims against WGL. Antero has not accrued for these amounts in the Company's financial statements.
As it relates to this contractual dispute, WGL and Antero have also recently been involved in two previous lawsuits related to pricing and delivery points on these contracts. In the first lawsuit, which was ultimately referred to arbitration, the arbitration panel ruled in Antero's favor and the award was confirmed by the Colorado District Court in April 2017. In the second lawsuit, the Colorado District Court dismissed with prejudice WGL's claims against Antero and found that Antero had not breached its contracts with WGL. For further information on this dispute, please see note 10 to Antero's condensed consolidated financial statements included in Antero's Form 10-Q for the period ending September 30, 2017.
South Jersey Natural Gas Sales Contract
Antero's third quarter 2017 realized gas price was also negatively impacted by an ongoing breach of contract by South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, "SJGC") related to two long term natural gas sales contracts that total 80,000 MMBtu/d. The price for natural gas sales was specifically based on the Platt's Columbia Appalachia Index outlined in the contracts. Beginning in October 2014, SJGC began short paying Antero based on price indices unilaterally selected by SJGC and not the Platt's Columbia Appalachia Index specified in the contracts. SJGC claimed that a market disruption event had occurred and, as a result, a new index price was required to be determined by the parties. Antero filed a lawsuit against SJGC in the U.S. District Court in Colorado to recover against SJGC for their breach of the contracts. In early May 2017, a jury returned a unanimous verdict finding in favor of Antero's positions in the lawsuit against SJGC. In July 2017, final judgment on the jury's unanimous verdict was entered by the court. SJGC continues to short pay the Company while it challenges the court's final judgment, resulting in approximately $7 million in damages net to Antero and a $(0.04)/Mcf negative impact to Antero's total company realized natural gas pricing for the three months ended September 30, 2017. From January 1, 2015 through September 30, 2017, damages net to Antero total approximately $47 million. Antero has not accrued for this amount in the Company's financial statements. Antero will continue to vigorously seek recovery from SJGC of all underpayments and damages, including those short payments continuing after the court's final judgment. For further information on this dispute, please see note 10 to Antero's condensed consolidated financial statements included in Antero's Form 10-Q for the period ending September 30, 2017.
In combination, the Company does not expect a material impact to its realized natural gas pricing and cash flow beyond year-end 2017 from these contractual disputes due to the start-up of the Cove Point LNG export facility expected in the first quarter of 2018, additional takeaway capacity expected to be placed in service throughout 2018, and narrower regional basis differentials based on current strip pricing.
For the third quarter and first nine months of 2017, these two disputes resulted in the following impact to Antero's realized natural gas pricing:
As Adjusted |
||||||
As Reported |
For WGL and |
Variance | ||||
Three months ended 9/30/17 |
||||||
Realized Natural Gas Price ($/Mcf) |
$2.71 |
$2.97 |
($0.26) | |||
Discount to Nymex ($/Mcf) |
($0.29) |
($0.03) |
($0.26) | |||
Nine months ended 9/30/17 |
||||||
Realized Natural Gas Price ($/Mcf) |
$3.06 |
$3.18 |
($0.12) | |||
Discount to Nymex ($/Mcf) |
($0.11) |
$0.01 |
($0.12) |
Revised 2017 Guidance
As a result of the two aforementioned contract disputes and the significant increase in realized NGL pricing both on an absolute basis and on a relative basis to WTI oil, Antero is revising its 2017 realized pricing guidance and is also providing new guidance for the fourth quarter of 2017.
Full Year 2017 Guidance | |||||||
2017 - OLD |
2017 - NEW | ||||||
Realized Pricing (Unhedged) |
Low |
High |
Low |
High | |||
Natural Gas Differential to Nymex Henry Hub ($/Mcf)(1)(2) |
$0.00 |
$0.10 |
$(0.15) |
$(0.10) | |||
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl) |
$(7.00) |
$(9.00) |
$(7.00) |
$(6.50) | |||
C3+ NGL Price (% of Nymex WTI) (1) |
50% |
55% |
57.5% |
62.5% |
4Q 2017 Guidance | |||||||
4Q 2017 | |||||||
Realized Pricing (Unhedged) |
Low |
High | |||||
Natural Gas Premium/(Discount) to Nymex Henry Hub ($/Mcf)(1)(2) |
$(0.20) |
$(0.15) | |||||
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl) |
$(6.00) |
$(5.00) | |||||
C3+ NGL Price (% of Nymex WTI) (1) |
70% |
75% | |||||
Consolidated Adjusted EBITDAX ($MM) (3)(4) |
$410 |
$440 |
(1) |
Based on strip pricing as of October 27, 2017, before hedging. |
(2) |
Includes Btu upgrade as Antero's processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average. |
(3) |
Based on strip pricing as of October 27, 2017. |
(4) |
For a description of the non-GAAP financial measure Adjusted EBITDAX, please read "Non-GAAP Financial Measures." Antero has not included a reconciliation of consolidated Adjusted EBITDAX to net income for the fourth quarter of 2017 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero is able to forecast interest expense and depreciation, depletion, amortization and accretion expense for the fourth quarter of 2017 between a range of $63 million and $67 million and $210 million and $220 million, respectively, each of which is a reconciling item between Adjusted EBITDAX and net income. However, Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized (gains) losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. |
Third Quarter 2017 Financial and Operating Results
As of September 30, 2017, Antero owned a 53% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated with Antero's results.
For the three months ended September 30, 2017, the Company reported a net loss of $135 million on a GAAP basis, or $0.43 per basic and diluted share, compared to net income of $238 million, or $0.78 per basic and $0.77 per diluted share, in the third quarter of 2016. The net loss for the third quarter of 2017 included the following items:
Excluding the items detailed above, the Company's results for the third quarter of 2017 were as follows:
Antero's net daily production for the third quarter of 2017 averaged 2,317 MMcfe/d, including a record 112,393 Bbl/d of liquids (29% liquids by volume). Third quarter 2017 production represents an organic production growth rate of 24% from the third quarter of 2016 and a 5% increase compared to the second quarter of 2017. Third quarter 2017 C3+ natural gas liquids ("NGLs") and oil production averaged 75,290 Bbl/d and 6,784 Bbl/d, respectively. Propane made up approximately 43,000 Bbl/d of the C3+ NGL production volume. Ethane (C2) production averaged 30,319 Bbl/d while leaving approximately 124,000 Bbl/d of ethane in the natural gas stream. Total liquids production of 112,393 Bbl/d for the third quarter of 2017 represents an organic production growth rate of 38% and 9% as compared to the third quarter of 2016 and second quarter of 2017, respectively. Liquids revenues made up approximately 38% of total product revenues during the third quarter of 2017, an increase from 25% of total product revenues during the prior year quarter.
Antero's average natural gas price before hedging decreased by 5% from the prior year quarter to $2.71 per Mcf, a $0.29 differential to the average Nymex natural gas price for the period. Excluding the $(0.26) negative impact from the aforementioned natural gas contract disputes, Antero's average natural gas price before hedging would have been $2.97 per Mcf, a $0.03 negative differential to the average Nymex natural gas price for the period. Antero's average realized natural gas price after hedging for the third quarter of 2017 was $3.37 per Mcf, a $0.37 premium to the Nymex average natural gas price for the period, and a 22% decrease compared to the prior year quarter. During the third quarter, Antero realized a cash settled natural gas hedge gain of $100 million on swaps that matured during the quarter, or $0.66 per Mcf compared to $184 million, or $1.44 per Mcf in the prior year quarter.
The Company's average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter. Further, the Company's average realized C3+ price was $33.23 per barrel ($0.79 per gallon) for the month of September as NGL prices improved throughout the third quarter. The improvement in realized C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing driven by exports combined with an improvement in local differentials. During the quarter, Antero realized a cash settled C3+ NGL hedge loss of $40 million, or $5.77 per barrel. Antero's average realized C3+ NGL price including hedges was $23.15 per barrel, a 16% increase compared to the third quarter of 2016. The Company's average realized ethane price before hedging for the third quarter of 2017 was $0.21 per gallon, or $8.68 per barrel. During the quarter, Antero realized a cash settled ethane hedge loss of $0.4 million, or $0.15 per barrel. Antero's average realized ethane price including hedges for the third quarter of 2017 was $0.20 per gallon, or $8.53 per barrel. The average realized oil price before hedging was $42.50 per barrel, a $5.66 differential to Nymex WTI for the period and a 22% increase as compared to the third quarter of 2016. Antero's average realized oil price including hedges was $45.40 per barrel, a $2.76 differential to Nymex WTI for the period. During the quarter, Antero realized a cash settled hedge gain on oil of $2 million, or $2.90 per barrel.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by $0.28 to $3.10 per Mcfe. Liquids production increased equivalent pricing for dry gas by $0.39 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 14% to $3.39 per Mcfe compared to the prior year quarter. For the third quarter of 2017, Antero realized a total cash settled hedge gain on all products of $61 million, or $0.29 per Mcfe.
Total operating revenue for the third quarter of 2017 was $648 million as compared to $1.1 billion for the third quarter of 2016. Operating revenue for the third quarter of 2017 included an $878 million non-cash loss on unsettled hedges, while the third quarter of 2016 included a $334 million non-cash gain on unsettled hedges. The non-cash loss on unsettled hedges was primarily driven by the $750 million hedge monetization where Antero reduced the average fixed index price on some of its 2018 through 2022 natural gas hedges while maintaining the total volume hedged. Liquids production contributed 38% of total product revenues before hedges in the third quarter of 2017 as compared to 25% in the prior year quarter. For a reconciliation of revenue excluding unrealized hedge (gains) losses to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the third quarter of 2017 was $51 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the third quarter of 2017 was $79 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $28 million, or $0.13 per Mcfe, for the third quarter of 2017, representing a $0.03 per Mcfe increase from the third quarter of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the third quarter of 2017 was $1.54 per Mcfe, which was in line with the prior year quarter. The per unit cash production expense for the quarter included $0.11 per Mcfe for lease operating costs, $1.32 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the third quarter of 2017, excluding non-cash equity-based compensation expense, was $0.17 per Mcfe, a 6% decrease from the third quarter of 2016, driven by a 24% increase in production. Per unit depreciation, depletion and amortization expense decreased 16% from the prior year quarter to $0.97 per Mcfe, primarily driven by increases in our estimated recoverable reserves, improved well performance, and decreases in our per-unit development costs. For the Marcellus alone, per unit depreciation, depletion and amortization expense also decreased 16% from the prior year quarter to $0.83 per Mcfe.
Adjusted EBITDAX of $336 million for the third quarter of 2017 represents a 10% decrease compared to the prior year quarter. Adjusted EBITDAX does not include $750 million of realized gains from the partial monetization of certain natural gas hedges or $47 million impact from the natural gas contract disputes. Adjusted EBITDAX margin for the quarter was $1.58 per Mcfe, representing a 27% decrease from the prior year quarter. For the third quarter of 2017, cash flow from operations was $1.0 billion, a 220% increase from the prior year quarter. Cash flow from operations before changes in working capital was $1.0 billion, a 228% increase from the third quarter of 2016.
Adjusted EBITDAX is a non-GAAP financial measure. For a description of Adjusted EBITDAX, Adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended September 30, 2017:
Three Months Ended | ||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Net Production |
1,643 |
6,784 |
75,290 |
30,319 |
2,317 | |||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Realized Prices |
||||||||||||||
Average realized price before settled derivatives |
$ |
2.71 |
$ |
42.50 |
$ |
28.92 |
$ 8.68 |
$ |
3.10 | |||||
Settled derivatives |
0.66 |
2.90 |
(5.77) |
(0.15) |
0.29 | |||||||||
Average realized price after settled derivatives |
$ |
3.37 |
$ |
45.40 |
$ |
23.15 |
$ 8.53 |
$ |
3.39 | |||||
Nymex average price |
$ |
3.00 |
$ |
48.16 |
$ |
3.00 | ||||||||
Premium / (Differential) to Nymex |
$ |
0.37 |
$ |
(2.76) |
$ |
0.39 |
Marcellus Shale — Antero completed and placed on line 31 horizontal Marcellus wells during the third quarter of 2017 with an average lateral length of 9,500 feet. During the period, Antero drilled an average of 4,884 lateral feet per day, which represents a 42% increase compared to 2016. Out of the 31 wells completed in the third quarter, 25 have been on line for more than 30 days and had an average 30-day rate on choke of 17 MMcfe/d (17% liquids), assuming 25% ethane recovery.
Current average well costs are $0.91 million per 1,000 feet of lateral in the Marcellus assuming a 2,000 pounds of proppant per foot completion. Average drilling days from spud to final rig release was 12 days in the third quarter of 2017, a 20% reduction from 2016. Antero is currently operating five drilling rigs and three completion crews in the Marcellus Shale.
In early July 2017, Antero drilled its longest laterals to date in the Marcellus, with three laterals averaging 14,000 feet. These wells are expected to be completed during the fourth quarter of 2017 and placed to sales in the first quarter of 2018. Additionally, Antero completed a four-well pad using 2,500 pounds of proppant per foot and with an average lateral of 11,100 feet, that had a 90-day rate of 20 MMcfe/d per well including 921 Bbl/d of NGLs and 31 Bbl/d of oil, and an unprocessed EUR of approximately 2.2 Bcf/1,000' (2.7 Bcfe/1,000' assuming 25% ethane recovery). Antero also put to sales another four-well pilot pad that was completed using 2,500 pounds of proppant per foot and had an average lateral of 5,400 feet. The pad delivered an average 90-day rate of 12 MMcfe/d per well including 438 Bbl/d of NGLs and an unprocessed EUR of approximately 2.3 Bcf/1,000' (2.8 Bcfe/1,000' assuming 25% ethane recovery).
Furthermore, in the first quarter of 2017, Antero completed a four-well pad using 2,000 pounds of proppant per foot and with an average lateral length of 11,100 feet, that had a 90-day rate of 22.4 MMcfe/d per well (30% liquids) and an unprocessed EUR of approximately 2.2 Bcf/1,000' (2.6 Bcfe/1,000' assuming 25% ethane recovery). This pad included a 14,000 foot lateral that had a 90-day rate of 27.1 MMcfe/d (30% liquids).
Ohio Utica Shale – Antero completed and placed on line six horizontal Utica wells during the third quarter of 2017 with an average lateral length of approximately 9,600 feet. During the period, Antero drilled four 17,000' laterals and set a record for drilling its longest lateral to date at 17,445 feet. This lateral was drilled within a 7 foot target zone and was drilled in five days. The wells are expected to be placed to sales in the second quarter of 2018.
Current average well costs are $0.99 million per 1,000 feet of lateral in the Ohio Utica assuming a 2,000 pounds of proppant per foot completion. Antero is currently operating one drilling rig and one completion crew in the Utica Shale. Upon Rover phase 1B being placed in service, Antero expects to turn in line two dry focused Ohio Utica pads that total ten wells.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
For the three months ended September 30, 2017, Antero Midstream reported revenues of $194 million, comprised of $101 million from the Gathering and Processing segment and $93 million from the Water Handling and Treatment segment. Revenues increased 29% compared to the prior year quarter, driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $45 million from wastewater handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $11 million and $52 million, respectively, for a total of $63 million compared to $33 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $44 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the third quarter of 2016. General and administrative expenses excluding equity-based compensation were $7 million during the third quarter of 2017, in line with the third quarter of 2016. Total operating expenses were $111 million, including $31 million of depreciation and $3 million of accretion of contingent acquisition consideration.
Net income for the third quarter of 2017 was $81 million, a 15% increase compared to the prior year quarter. Net income per limited partner unit was $0.33 per unit, an 11% decrease compared to the prior year quarter. Adjusted EBITDA was $128 million, a 16% increase compared to the prior year quarter. The increase in net income and Adjusted EBITDA is primarily driven by increased throughput and fresh water delivery volumes. Adjusted EBITDA for the quarter included $4 million in distributions from Stonewall Gathering LLC ("Stonewall") and the processing and fractionation joint venture. Cash interest paid was $21 million. Decrease in cash reserved for bond interest during the quarter decreased $9 million and cash reserved for payment of income tax withholding upon vesting of Antero Midstream equity-based compensation awards was $2 million. Maintenance capital expenditures during the quarter totaled $11 million and distributable cash flow was $104 million, resulting in a DCF coverage ratio of 1.3x.
Antero Midstream Distribution
The Board of Directors of Antero Midstream Partners GP LLC, the general partner of Antero Midstream, declared a cash distribution of $0.34 per unit ($1.36 per unit annualized) for the third quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 6% increase sequentially. The distribution is Antero Midstream's eleventh consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on November 16, 2017 to unitholders of record as of November 1, 2017.
Stand-alone Balance Sheet and Liquidity
As of September 30, 2017, Antero's stand-alone total debt and net debt were $3.4 billion, of which $25 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under the new upstream credit facility are $2.5 billion. Reduced for $700 million in letters of credit outstanding, the company had $1.8 billion in available stand-alone liquidity as of September 30, 2017. Antero Resources' stand-alone E&P net debt to last twelve months adjusted EBITDAX ratio was 2.6x as of September 30, 2017. For a reconciliation of stand-alone net debt to stand-alone total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Consolidated Balance Sheet and Liquidity
As of September 30, 2017, Antero's consolidated total debt and net debt was $4.5 billion, of which $452 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two new facilities is now $4.0 billion. Reduced for $700 million in letters of credit outstanding, the company had $2.9 billion in available consolidated liquidity as of September 30, 2017. Antero Resources' consolidated net debt to last twelve months consolidated Adjusted EBITDAX ratio was 3.0x as of September 30, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Third Quarter 2017 Capital Spending
Antero's drilling and completion costs for the three months ended September 30, 2017 were $317 million. In addition, the Company invested $52 million for land. Antero Midstream invested $99 million for gathering and compression systems and $48 million for water infrastructure projects, including $33 million on the Antero Clearwater Treatment Facility. Investments in unconsolidated affiliates for Antero Midstream's processing and fractionation joint venture were $26 million during the quarter.
Hedge Position
Antero currently has hedged 2.9 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2017 through December 31, 2023 at an average index price of $3.36 per MMBtu. At September 30, 2017, the Company's estimated fair value of commodity derivative instruments was $1.2 billion.
The following table summarizes Antero's hedge position as of September 30, 2017:
Period |
Natural Gas |
Average |
Liquids |
Average | ||
4Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.46 |
— |
— | ||
CGTLA |
420,000 |
$4.37 |
— |
— | ||
Chicago |
70,000 |
$4.68 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.40 | ||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
Total |
1,860,000 |
$3.71 |
50,500 |
N/A (1) | ||
2018: |
||||||
Nymex Henry Hub |
2,002,500 |
$3.50 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
3,000 |
$0.67 | ||
Nymex WTI ($/Bbl) |
— |
— |
1,000 |
49.96 | ||
2019 Nymex Henry Hub |
2,330,000 |
$3.50 |
— |
— | ||
2020 Nymex Henry Hub |
1,417,500 |
$3.25 |
— |
— | ||
2021 Nymex Henry Hub |
710,000 |
$3.00 |
— |
— | ||
2022 Nymex Henry Hub |
850,000 |
$3.00 |
— |
— | ||
2023 Nymex Henry Hub |
90,000 |
$2.91 |
— |
— |
(1) |
Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges. |
Conference Call
A conference call is scheduled on Thursday, November 2, 2017 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, November 10, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10111894.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, November 10, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the November 2, 2017 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled hedges. Antero believes that revenue excluding unrealized hedge (gains) losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge (gains) losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge (gains) losses (in thousands):
Three months ended |
Nine months ended | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Total operating revenue |
$ |
1,116,503 |
$ |
647,880 |
$ |
1,588,309 |
$ |
2,633,848 | ||||
Hedge (gains) losses |
(530,334) |
65,957 |
(125,624) |
(458,459) | ||||||||
Cash receipts for settled hedges |
196,712 |
61,479 |
813,559 |
137,392 | ||||||||
Revenue excluding unrealized hedge (gains) losses |
$ |
782,881 |
$ |
775,316 |
$ |
2,276,244 |
$ |
2,312,781 |
Adjusted net income (loss) as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income (loss) is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income (loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (loss) (in thousands):
Three months ended |
Nine months ended | |||||||||||
September 30, |
September 30, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net income (loss) |
$ |
238,255 |
$ |
(135,063) |
$ |
(363,044) |
$ |
128,201 | ||||
Hedge (gains) losses |
(530,334) |
65,957 |
(125,624) |
(458,459) | ||||||||
Cash receipts for settled hedges |
196,712 |
61,479 |
813,559 |
137,392 | ||||||||
Impairment of unproved properties |
11,753 |
41,000 |
47,223 |
83,098 | ||||||||
Equity-based compensation |
26,381 |
26,447 |
75,667 |
78,925 | ||||||||
Income tax effect of reconciling items |
112,490 |
(73,735) |
(308,675) |
60,175 | ||||||||
Adjusted net income (loss) |
$ |
55,257 |
$ |
(13,915) |
$ |
139,106 |
$ |
29,332 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended |
Nine months ended | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net cash provided by operating activities |
$ |
326,991 |
$ |
1,045,222 |
$ |
905,697 |
$ |
1,692,808 | ||||
Net change in working capital |
(17,327) |
(29,899) |
(35,939) |
(130,089) | ||||||||
Cash flow from operations before changes in working capital |
$ |
309,664 |
$ |
1,015,323 |
$ |
869,758 |
$ |
1,562,719 |
The following table reconciles total debt to net debt on a consolidated basis and a stand-alone E&P basis (in thousands):
December 31, |
September 30, | |||||
2016 |
2017 | |||||
AR Bank credit facility |
$ |
440,000 |
$ |
25,000 | ||
AM Bank credit facility |
210,000 |
427,000 | ||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | ||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | ||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | ||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | ||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | ||||
AR net unamortized premium |
1,749 |
1,588 | ||||
AR net unamortized debt issuance costs |
(37,690) |
(33,789) | ||||
AM net unamortized debt issuance costs |
(10,086) |
(9,278) | ||||
Consolidated total debt |
$ |
4,703,973 |
$ |
4,510,521 | ||
Less: AR cash and cash equivalents |
17,568 |
21,199 | ||||
Less: AM cash and cash equivalents |
14,042 |
2,495 | ||||
Consolidated net debt |
$ |
4,672,363 |
$ |
4,486,827 | ||
Stand-alone E&P net debt |
$ |
3,836,491 |
$ |
3,421,600 |
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes Adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to Adjusted EBITDAX, a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to Adjusted EBITDAX margin (in thousands except Adjusted EBITDAX margin).
Three months ended |
Nine months ended | |||||||||||||||||||
September 30, |
September 30, | |||||||||||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||||||||||
Net income (loss) including noncontrolling interest |
$ |
268,196 |
$ |
(90,000) |
$ |
(296,644) |
$ |
255,523 | ||||||||||||
Commodity derivative (gains) losses |
(530,334) |
65,957 |
(125,624) |
(458,459) | ||||||||||||||||
Gains on settled derivative instruments |
196,712 |
61,479 |
813,559 |
137,392 | ||||||||||||||||
Interest expense |
59,755 |
70,059 |
185,634 |
205,311 | ||||||||||||||||
Income tax expense (benefit) |
140,924 |
(45,078) |
(230,755) |
105,087 | ||||||||||||||||
Depreciation, depletion, amortization, and accretion |
199,741 |
207,626 |
589,903 |
612,823 | ||||||||||||||||
Impairment of unproved properties |
11,753 |
41,000 |
47,223 |
83,098 | ||||||||||||||||
Exploration expense |
1,166 |
1,599 |
3,289 |
5,510 | ||||||||||||||||
Equity-based compensation expense |
26,381 |
26,447 |
75,667 |
78,925 | ||||||||||||||||
Equity in earnings of unconsolidated affiliate |
(1,543) |
(7,033) |
(2,027) |
(12,887) | ||||||||||||||||
Distributions from unconsolidated affiliates |
— |
4,300 |
— |
10,120 | ||||||||||||||||
State franchise taxes |
— |
— |
39 |
— | ||||||||||||||||
Consolidated Adjusted EBITDAX |
372,751 |
336,356 |
1,060,264 |
1,022,443 | ||||||||||||||||
Interest expense |
(59,755) |
(70,059) |
(185,634) |
(205,311) | ||||||||||||||||
Exploration expense |
(1,166) |
(1,599) |
(3,289) |
(5,510) | ||||||||||||||||
Changes in current assets and liabilities |
17,327 |
29,899 |
35,939 |
130,089 | ||||||||||||||||
State franchise taxes |
— |
— |
(39) |
— | ||||||||||||||||
Proceeds from derivative monetization |
— |
749,906 |
— |
749,906 | ||||||||||||||||
Other non-cash items |
(2,166) |
719 |
(1,544) |
1,191 | ||||||||||||||||
Net cash provided by operating activities |
$ |
326,991 |
$ |
1,045,222 |
$ |
905,697 |
$ |
1,692,808 |
Three months ended |
Nine months ended | ||||||||||||||||||
September 30, |
September 30, | ||||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2016 |
2017 |
2016 |
2017 | |||||||||||||||
Realized price before cash receipts for settled hedges |
$ |
2.82 |
$ |
3.10 |
$ |
2.36 |
$ |
3.30 | |||||||||||
Gathering, compression, water handling and treatment revenues |
0.01 |
0.01 |
0.03 |
0.01 | |||||||||||||||
Distributions from unconsolidated affiliates |
— |
0.02 |
— |
0.02 | |||||||||||||||
Lease operating expense |
(0.08) |
(0.11) |
(0.08) |
(0.09) | |||||||||||||||
Gathering, compression, processing and transportation costs |
(1.36) |
(1.32) |
(1.32) |
(1.35) | |||||||||||||||
Marketing, net |
(0.10) |
(0.13) |
(0.19) |
(0.13) | |||||||||||||||
Production taxes |
(0.09) |
(0.11) |
(0.11) |
(0.12) | |||||||||||||||
General and administrative(1) |
(0.18) |
(0.17) |
(0.20) |
(0.18) | |||||||||||||||
Adjusted EBITDAX margin before settled hedges |
$ |
1.02 |
$ |
1.29 |
$ |
0.49 |
$ |
1.46 | |||||||||||
Cash receipts for settled hedges |
1.14 |
0.29 |
1.66 |
0.23 | |||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.16 |
$ |
1.58 |
$ |
2.15 |
$ |
1.69 |
(1) |
Excludes equity-based stock compensation |
The following table reconciles Antero's consolidated net income to consolidated Adjusted EBITDAX for the twelve months ending September 30, 2017 as used in this release (in thousands):
Twelve months ended | ||
September 30, | ||
2017 | ||
Net loss including noncontrolling interest |
$ |
(197,281) |
Commodity derivative losses |
181,346 | |
Net cash receipts on settled derivative instruments |
326,916 | |
Gain on sale of assets |
(97,635) | |
Interest expense |
273,229 | |
Loss on early extinguishment of debt |
16,956 | |
Income tax benefit |
(160,534) | |
Depreciation, depletion, amortization and accretion |
835,266 | |
Impairment of unproved properties |
198,810 | |
Exploration expense |
9,083 | |
Equity-based compensation expense |
105,679 | |
Equity in earnings of unconsolidated affiliates |
(11,345) | |
Distributions from unconsolidated affiliates |
17,822 | |
State franchise taxes |
11 | |
Total Adjusted EBITDAX |
$ |
1,498,323 |
"Stand-alone E&P Adjusted EBITDAX" is also used by our management team for various purposes, including as a measure of operating performance of our exploration and production and marketing segments and as a basis for strategic planning and forecasting. Stand-alone E&P Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income or loss before derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. Operating income or loss represents net income or loss, including noncontrolling interests, before interest expense and interest income, income taxes, and equity in earnings of unconsolidated affiliates. Operating income is the most directly comparable GAAP financial measure to Stand-alone E&P Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis.
The following table reconciles operating income to total Adjusted EBITDAX on a stand-alone E&P basis. Stand-alone E&P basis includes operations from both the exploration and production segment and marketing segment (in thousands):
Twelve months ended | ||
September 30, | ||
2017 | ||
Stand-alone E&P operating loss |
$ |
(235,777) |
Commodity derivative gains |
181,346 | |
Net cash receipts on settled derivatives instruments |
326,916 | |
Depreciation, depletion, amortization and accretion |
719,999 | |
Impairment of unproved properties |
198,810 | |
Exploration expense |
9,083 | |
Change in fair value of contingent acquisition consideration |
(15,777) | |
Equity-based compensation expense |
78,560 | |
Gain on sale of assets |
(93,776) | |
State franchise taxes |
11 | |
Distributions from limited partner interest in Antero Midstream |
126,833 | |
Stand-alone E&P Adjusted EBITDAX |
$ |
1,296,228 |
The following table reconciles Antero Midstream's net income to Adjusted EBITDA and distributable cash flow as used in this release (in thousands):
Three months ended | |||||
September 30, | |||||
2016 |
2017 | ||||
Net income |
$ |
70,524 |
$ |
80,893 | |
Interest expense |
5,303 |
9,311 | |||
Depreciation expense |
26,136 |
30,556 | |||
Accretion of contingent acquisition consideration |
3,527 |
2,556 | |||
Equity-based compensation |
6,599 |
7,199 | |||
Equity in earnings of unconsolidated affiliates |
(1,544) |
(7,033) | |||
Distributions from unconsolidated affiliates |
— |
4,300 | |||
Adjusted EBITDA |
$ |
110,545 |
$ |
127,782 | |
Interest paid |
(4,043) |
(20,554) | |||
Decrease in cash reserved for bond interest (1) |
— |
8,831 | |||
Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2) |
(1,000) |
(1,500) | |||
Cash distribution to be received from unconsolidated affiliate |
2,221 |
— | |||
Maintenance capital expenditures(3) |
(4,638) |
(10,771) | |||
Distributable cash flow |
$ |
103,085 |
$ |
103,788 | |
Distributions Declared to Antero Midstream Holders |
|||||
Limited Partners |
$ |
47,025 |
$ |
63,454 | |
Incentive distribution rights |
4,820 |
19,067 | |||
Total Aggregate Distributions |
$ |
51,845 |
$ |
82,521 | |
DCF coverage ratio |
2.0x |
1.3x |
1) |
Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year. |
2) |
Estimate of current period portion of expected cash payment for income tax withholding attributable to vesting of Midstream LTIP equity-based compensation awards to be paid in the fourth quarter. |
3) |
Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems. |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2016.
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Balance Sheets | ||||||
December 31, 2016 and September 30, 2017 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
December 31, 2016 |
September 30, 2017 | |||||
Assets | ||||||
Current assets: |
||||||
Cash and cash equivalents |
$ |
31,610 |
23,694 | |||
Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and September 30, 2017, respectively |
29,682 |
43,854 | ||||
Accrued revenue |
261,960 |
233,585 | ||||
Derivative instruments |
73,022 |
299,796 | ||||
Other current assets |
6,313 |
10,024 | ||||
Total current assets |
402,587 |
610,953 | ||||
Property and equipment: |
||||||
Natural gas properties, at cost (successful efforts method): |
||||||
Unproved properties |
2,331,173 |
2,305,749 | ||||
Proved properties |
9,549,671 |
10,779,043 | ||||
Water handling and treatment systems |
744,682 |
891,869 | ||||
Gathering systems and facilities |
1,723,768 |
1,977,510 | ||||
Other property and equipment |
41,231 |
54,571 | ||||
14,390,525 |
16,008,742 | |||||
Less accumulated depletion, depreciation, and amortization |
(2,363,778) |
(2,973,544) | ||||
Property and equipment, net |
12,026,747 |
13,035,198 | ||||
Derivative instruments |
1,731,063 |
876,293 | ||||
Investments in unconsolidated affiliates |
68,299 |
287,842 | ||||
Other assets |
26,854 |
38,928 | ||||
Total assets |
$ |
14,255,550 |
14,849,214 | |||
Liabilities and Equity | ||||||
Current liabilities: |
||||||
Accounts payable |
$ |
38,627 |
47,457 | |||
Accrued liabilities |
393,803 |
429,696 | ||||
Revenue distributions payable |
163,989 |
220,971 | ||||
Derivative instruments |
203,635 |
4,285 | ||||
Other current liabilities |
17,334 |
15,267 | ||||
Total current liabilities |
817,388 |
717,676 | ||||
Long-term liabilities: |
||||||
Long-term debt |
4,703,973 |
4,510,521 | ||||
Deferred income tax liability |
950,217 |
1,180,564 | ||||
Derivative instruments |
234 |
427 | ||||
Other liabilities |
55,160 |
52,764 | ||||
Total liabilities |
6,526,972 |
6,461,952 | ||||
Commitments and contingencies |
||||||
Equity: |
||||||
Stockholders' equity: |
||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; 314,877 shares and 315,470 shares issued and outstanding at December 31, 2016 and September 30, 2017, respectively |
3,149 |
3,155 | ||||
Additional paid-in capital |
5,299,481 |
6,564,320 | ||||
Accumulated earnings |
959,995 |
1,088,196 | ||||
Total stockholders' equity |
6,262,625 |
7,655,671 | ||||
Noncontrolling interests in consolidated subsidiary |
1,465,953 |
731,591 | ||||
Total equity |
7,728,578 |
8,387,262 | ||||
Total liabilities and equity |
$ |
14,255,550 |
14,849,214 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | ||||||
Three Months Ended September 30, 2016 and 2017 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
Three Months Ended | ||||||
2016 |
2017 | |||||
Revenue: |
||||||
Natural gas sales |
$ |
364,373 |
409,141 | |||
Natural gas liquids sales |
106,958 |
224,533 | ||||
Oil sales |
14,793 |
26,527 | ||||
Gathering, compression, water handling and treatment |
2,969 |
2,869 | ||||
Marketing |
97,076 |
50,767 | ||||
Commodity derivative fair value gains (losses) |
530,334 |
(65,957) | ||||
Total revenue |
1,116,503 |
647,880 | ||||
Operating expenses: |
||||||
Lease operating |
13,854 |
23,491 | ||||
Gathering, compression, processing, and transportation |
234,915 |
282,134 | ||||
Production and ad valorem taxes |
15,554 |
22,995 | ||||
Marketing |
114,611 |
78,884 | ||||
Exploration |
1,166 |
1,599 | ||||
Impairment of unproved properties |
11,753 |
41,000 | ||||
Depletion, depreciation, and amortization |
199,113 |
206,968 | ||||
Accretion of asset retirement obligations |
628 |
658 | ||||
General and administrative (including equity-based compensation expense of $26,381 and $26,447 in 2016 and 2017, respectively) |
57,577 |
62,203 | ||||
Total operating expenses |
649,171 |
719,932 | ||||
Operating income (loss) |
467,332 |
(72,052) | ||||
Other income (expenses): |
||||||
Equity in earnings of unconsolidated affiliates |
1,543 |
7,033 | ||||
Interest |
(59,755) |
(70,059) | ||||
Total other expenses |
(58,212) |
(63,026) | ||||
Income (loss) before income taxes |
409,120 |
(135,078) | ||||
Provision for income tax (expense) benefit |
(140,924) |
45,078 | ||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
268,196 |
(90,000) | ||||
Net income and comprehensive income attributable to noncontrolling interests |
29,941 |
45,063 | ||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
238,255 |
(135,063) | |||
Earnings (loss) per common share—basic |
$ |
0.78 |
(0.43) | |||
Earnings (loss) per common share—assuming dilution |
$ |
0.77 |
(0.43) | |||
Weighted average number of shares outstanding: |
||||||
Basic |
306,785 |
315,463 | ||||
Diluted |
308,657 |
315,463 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | ||||||
Nine Months Ended September 30, 2016 and 2017 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
Nine Months Ended | ||||||
2016 |
2017 | |||||
Revenue and other: |
||||||
Natural gas sales |
$ |
848,936 |
1,330,062 | |||
Natural gas liquids sales |
274,736 |
590,004 | ||||
Oil sales |
41,712 |
79,999 | ||||
Gathering, compression, water handling and treatment |
10,107 |
8,665 | ||||
Marketing |
287,194 |
166,659 | ||||
Commodity derivative fair value gains |
125,624 |
458,459 | ||||
Total revenue and other |
1,588,309 |
2,633,848 | ||||
Operating expenses: |
||||||
Lease operating |
37,190 |
56,034 | ||||
Gathering, compression, processing, and transportation |
649,713 |
815,710 | ||||
Production and ad valorem taxes |
52,296 |
70,341 | ||||
Marketing |
378,521 |
246,298 | ||||
Exploration |
3,289 |
5,510 | ||||
Impairment of unproved properties |
47,223 |
83,098 | ||||
Depletion, depreciation, and amortization |
588,057 |
610,879 | ||||
Accretion of asset retirement obligations |
1,846 |
1,944 | ||||
General and administrative (including equity-based compensation expense of $75,667 and $78,925 in 2016 and 2017, respectively) |
173,966 |
191,000 | ||||
Total operating expenses |
1,932,101 |
2,080,814 | ||||
Operating income (loss) |
(343,792) |
553,034 | ||||
Other income (expenses): |
||||||
Equity in earnings of unconsolidated affiliates |
2,027 |
12,887 | ||||
Interest |
(185,634) |
(205,311) | ||||
Total other expenses |
(183,607) |
(192,424) | ||||
Income (loss) before income taxes |
(527,399) |
360,610 | ||||
Provision for income tax (expense) benefit |
230,755 |
(105,087) | ||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
(296,644) |
255,523 | ||||
Net income and comprehensive income attributable to noncontrolling interests |
66,400 |
127,322 | ||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(363,044) |
128,201 | |||
Earnings (loss) per common share—basic |
$ |
(1.26) |
0.41 | |||
Earnings (loss) per common share—assuming dilution |
$ |
(1.26) |
0.41 | |||
Weighted average number of shares outstanding: |
||||||
Basic |
288,607 |
315,275 | ||||
Diluted |
288,607 |
316,140 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Cash Flows | ||||||
Nine Months Ended September 30, 2016 and 2017 | ||||||
(Unaudited) | ||||||
(In thousands) | ||||||
Nine Months Ended September 30, | ||||||
2016 |
2017 | |||||
Cash flows from operating activities: |
||||||
Net income (loss) including noncontrolling interests |
$ |
(296,644) |
255,523 | |||
Adjustment to reconcile net income (loss) to net cash provided by operating activities: |
||||||
Depletion, depreciation, amortization, and accretion |
589,903 |
612,823 | ||||
Impairment of unproved properties |
47,223 |
83,098 | ||||
Derivative fair value gains |
(125,624) |
(458,459) | ||||
Gains on settled derivatives |
813,559 |
137,392 | ||||
Proceeds from derivative monetizations |
— |
749,906 | ||||
Deferred income tax expense (benefit) |
(230,755) |
105,087 | ||||
Equity-based compensation expense |
75,667 |
78,925 | ||||
Equity in earnings of unconsolidated affiliates |
(2,027) |
(12,887) | ||||
Distributions of earnings from unconsolidated affiliates |
— |
10,120 | ||||
Other |
(1,544) |
1,191 | ||||
Changes in current assets and liabilities: |
||||||
Accounts receivable |
10,077 |
1,771 | ||||
Accrued revenue |
(68,248) |
28,375 | ||||
Other current assets |
4,685 |
(3,836) | ||||
Accounts payable |
5,683 |
4,731 | ||||
Accrued liabilities |
41,386 |
43,043 | ||||
Revenue distributions payable |
42,253 |
56,982 | ||||
Other current liabilities |
103 |
(977) | ||||
Net cash provided by operating activities |
905,697 |
1,692,808 | ||||
Cash flows used in investing activities: |
||||||
Additions to proved properties |
(64,789) |
(179,318) | ||||
Additions to unproved properties |
(559,572) |
(182,207) | ||||
Drilling and completion costs |
(1,009,851) |
(946,508) | ||||
Additions to water handling and treatment systems |
(137,355) |
(143,470) | ||||
Additions to gathering systems and facilities |
(154,136) |
(254,619) | ||||
Additions to other property and equipment |
(1,747) |
(11,417) | ||||
Investments in unconsolidated affiliates |
(45,044) |
(216,776) | ||||
Change in other assets |
(2,173) |
(16,148) | ||||
Other |
— |
2,156 | ||||
Net cash used in investing activities |
(1,974,667) |
(1,948,307) | ||||
Cash flows from financing activities: |
||||||
Issuance of common stock |
837,414 |
— | ||||
Issuance of common units by Antero Midstream Partners LP |
19,605 |
248,949 | ||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
178,000 |
311,100 | ||||
Issuance of senior notes |
650,000 |
— | ||||
Repayments on bank credit facilities, net |
(552,000) |
(198,000) | ||||
Payments of deferred financing costs |
(9,029) |
— | ||||
Distributions to noncontrolling interests in consolidated subsidiary |
(51,238) |
(102,053) | ||||
Employee tax withholding for settlement of equity compensation awards |
(4,876) |
(8,500) | ||||
Other |
(3,867) |
(3,913) | ||||
Net cash provided by financing activities |
1,064,009 |
247,583 | ||||
Net decrease in cash and cash equivalents |
(4,961) |
(7,916) | ||||
Cash and cash equivalents, beginning of period |
23,473 |
31,610 | ||||
Cash and cash equivalents, end of period |
$ |
18,512 |
23,694 | |||
Supplemental disclosure of cash flow information: |
||||||
Cash paid during the period for interest |
$ |
132,928 |
174,324 | |||
Supplemental disclosure of noncash investing activities: |
||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
$ |
(189,234) |
(3,084) |
The following tables set forth selected consolidated operating data for the three months ended September 30, 2016 compared to the three months ended September 30, 2017:
Three Months Ended September |
Amount of |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
364,373 |
$ |
409,141 |
$ |
44,768 |
12 |
% | ||||
NGLs sales |
106,958 |
224,533 |
117,575 |
110 |
% | |||||||
Oil sales |
14,793 |
26,527 |
11,734 |
79 |
% | |||||||
Gathering, compression, water handling and treatment |
2,969 |
2,869 |
(100) |
(3) |
% | |||||||
Marketing |
97,076 |
50,767 |
(46,309) |
(48) |
% | |||||||
Commodity derivative fair value gains (losses) |
530,334 |
(65,957) |
(596,291) |
* |
||||||||
Total operating revenues and other |
1,116,503 |
647,880 |
(468,623) |
(42) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
13,854 |
23,491 |
9,637 |
70 |
% | |||||||
Gathering, compression, processing, and transportation |
234,915 |
282,134 |
47,219 |
20 |
% | |||||||
Production and ad valorem taxes |
15,554 |
22,995 |
7,441 |
48 |
% | |||||||
Marketing |
114,611 |
78,884 |
(35,727) |
(31) |
% | |||||||
Exploration |
1,166 |
1,599 |
433 |
37 |
% | |||||||
Impairment of unproved properties |
11,753 |
41,000 |
29,247 |
249 |
% | |||||||
Depletion, depreciation, and amortization |
199,113 |
206,968 |
7,855 |
4 |
% | |||||||
Accretion of asset retirement obligations |
628 |
658 |
30 |
5 |
% | |||||||
General and administrative (before equity-based compensation) |
31,196 |
35,756 |
4,560 |
15 |
% | |||||||
Equity-based compensation |
26,381 |
26,447 |
66 |
— |
% | |||||||
Total operating expenses |
649,171 |
719,932 |
70,761 |
11 |
% | |||||||
Operating income (loss) |
467,332 |
(72,052) |
(539,384) |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
1,543 |
7,033 |
5,490 |
356 |
% | |||||||
Interest expense |
(59,755) |
(70,059) |
(10,304) |
17 |
% | |||||||
Total other expenses |
(58,212) |
(63,026) |
(4,814) |
8 |
% | |||||||
Income (loss) before income taxes |
409,120 |
(135,078) |
(544,198) |
* |
||||||||
Income tax (expense) benefit |
(140,924) |
45,078 |
186,002 |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
268,196 |
(90,000) |
(358,196) |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
29,941 |
45,063 |
15,122 |
51 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
238,255 |
$ |
(135,063) |
$ |
(373,318) |
* |
|||||
Adjusted EBITDAX (1) |
$ |
372,751 |
$ |
336,356 |
$ |
(36,395) |
(10) |
% | ||||
Three Months Ended September |
Amount of |
Percent |
||||||||||
2016 |
2017 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
128 |
151 |
23 |
18 |
% | |||||||
C2 Ethane (MBbl) |
1,801 |
2,789 |
988 |
55 |
% | |||||||
C3+ NGLs (MBbl) |
5,270 |
6,927 |
1,657 |
31 |
% | |||||||
Oil (MBbl) |
423 |
624 |
201 |
47 |
% | |||||||
Combined (Bcfe) |
172 |
213 |
41 |
24 |
% | |||||||
Daily combined production (MMcfe/d) |
1,875 |
2,317 |
442 |
24 |
% | |||||||
Average prices before effects of derivative settlements(2): |
||||||||||||
Natural gas (per Mcf) |
$ |
2.86 |
$ |
2.71 |
$ |
(0.15) |
(5) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.00 |
$ |
8.68 |
$ |
0.68 |
9 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
17.56 |
$ |
28.92 |
$ |
11.36 |
65 |
% | ||||
Oil (per Bbl) |
$ |
34.93 |
$ |
42.50 |
$ |
7.57 |
22 |
% | ||||
Combined (per Mcfe) |
$ |
2.82 |
$ |
3.10 |
$ |
0.28 |
10 |
% | ||||
Average realized prices after effects of derivative settlements(2): |
||||||||||||
Natural gas (per Mcf) |
$ |
4.30 |
$ |
3.37 |
$ |
(0.93) |
(22) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.00 |
$ |
8.53 |
$ |
0.53 |
7 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
19.96 |
$ |
23.15 |
$ |
3.19 |
16 |
% | ||||
Oil (per Bbl) |
$ |
34.93 |
$ |
45.40 |
$ |
10.47 |
30 |
% | ||||
Combined (per Mcfe) |
$ |
3.96 |
$ |
3.39 |
$ |
(0.57) |
(14) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.11 |
$ |
0.03 |
38 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.36 |
$ |
1.32 |
$ |
(0.04) |
(3) |
% | ||||
Production and ad valorem taxes |
$ |
0.09 |
$ |
0.11 |
$ |
0.02 |
22 |
% | ||||
Marketing expense, net |
$ |
0.10 |
$ |
0.13 |
$ |
0.03 |
30 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.16 |
$ |
0.97 |
$ |
(0.19) |
(16) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.18 |
$ |
0.17 |
$ |
(0.01) |
(6) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX | |
(2) |
Calculation excludes the impact of hedge monetization |
*Not meaningful or applicable |
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SOURCE Antero Resources Corporation
DENVER, Oct. 12, 2017 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its third quarter 2017 earnings release on Wednesday, November 1, 2017 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, November 2, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, November 10, 2017 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10111894.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, November 10, 2017 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
For more information, contact Michael Kennedy – SVP – Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, Sept. 21, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today that it has monetized over $1 billion of non-exploration and production ("E&P") assets including the previously announced sale of 10 million common units representing limited partner interests in Antero Midstream Partners LP (NYSE:AM) ("Antero Midstream") and the restructuring of a portion of its commodity hedge portfolio.
Highlights:
During the third quarter of 2017, Antero Resources monetized over $1 billion of non-E&P assets through a combination of the previously announced sale of Antero Midstream common units and the restructuring of its hedge portfolio. Proceeds from the monetization program were used to repay credit facility borrowings. Proceeds from the monetization program are not expected to result in cash taxes payable due to the utilization of a portion of Antero's $1.5 billion of net operating losses carried forward. Pro forma for the $311 million of net proceeds from the Antero Midstream secondary offering and approximate $750 million hedge portfolio restructuring proceeds, Antero Resources' standalone E&P net debt to last twelve months adjusted EBITDAX ratio and its consolidated net debt to last twelve months adjusted EBITDAX ratio were 2.4x and 2.7x, respectively, as of June 30, 2017. Additionally, on a pro forma basis as of June 30, 2017, the Company had no borrowings under its $4.0 billion revolving credit facility and $154 million of cash, resulting in over $3.4 billion of liquidity, net of letters of credit outstanding.
Glen Warren, President and CFO, commented, "Antero has monetized a portion of its non-E&P assets in a tax-efficient manner with no dilution to shareholders, in order to maintain a healthy and flexible balance sheet. The resulting leverage is in the mid 2-times range. Further, the monetizations highlight the value of Antero's 53% ownership position in Antero Midstream and its industry leading hedge position. Importantly, we have maintained the volume of natural gas hedged through 2022 at prices 16% above current NYMEX strip prices. The implied hedge restructuring cost was in line with Antero's credit facility borrowing costs, resulting in the ability to efficiently bring forward approximately $750 million in hedge value. This delevering further supports Antero's ability to maintain its peer-leading annual production growth target of 20% to 22% through 2020 with no increase to the previously disclosed capital spending outlook."
As a result of the completed delevering program, Antero expects its 2017 standalone E&P net debt to last twelve months EBITDAX ratio to remain in the mid 2-times area, reduced from the previous outlook of low-to-mid 3-times area. In addition, for the 2018 through 2020 period, the Company expects its standalone E&P net debt to last twelve months EBITDAX ratio to further decline to the low-to-mid 2-times range from the previous outlook of the mid 2-times range. During this period, Antero Resources expects to fund drilling and completion capital through stand-alone E&P cash flow from operations assuming current strip pricing.(1)
Antero Resources' Sale of Antero Midstream Common Units
On September 6, 2017, Antero Resources announced the pricing of an underwritten public offering of 10 million common units (the "Offering") representing limited partner interests in Antero Midstream held by Antero Resources at a price of $31.45 per common unit for aggregate net proceeds to Antero Resources of approximately $311 million after underwriting fees but before estimated offering expenses. After giving effect to the Offering and assuming no exercise of the underwriters' option to purchase 1.5 million additional common units, Antero Resources owns approximately 99 million common units, or 53% of Antero Midstream's outstanding common units.
Antero Resources Hedge Portfolio Monetization
During the third quarter of 2017, Antero Resources restructured a portion of its natural gas hedge portfolio for the years 2018 through 2022 to monetize approximately $750 million of the portfolio's $2.0 billion mark-to-market value as of June 30, 2017. The Company has reduced the average fixed index price on its 2018 natural gas hedges to $3.50 per MMBtu while maintaining the total volume hedged in 2018, resulting in approximately 100% of the Company's targeted 2018 natural gas production hedged at price approximately 13% above current NYMEX strip pricing. Additionally, Antero has reduced the average fixed index price on its 2019 natural gas hedges to $3.50 per MMBtu and average fixed index price on its 2020 natural gas hedges to $3.25 per MMBtu while maintaining the total volume hedged. As a result, approximately 80% of the Company's targeted 2018 through 2020 natural gas production is hedged at $3.43 per MMBtu, or approximately 16% above current NYMEX strip pricing. After deducting approximately $750 million of proceeds from the $2.0 billion mark-to-market value as of June 30, 2017, Antero Resources has 3.1 Tcfe hedged through 2023 with a pro forma value of approximately $1.3 billion.
The following table summarizes Antero's pro forma natural gas hedge position as of June 30, 2017:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) | ||
3Q 2017: |
||||
NYMEX Henry Hub |
1,370,000 |
$3.33 | ||
CGTLA |
420,000 |
$4.20 | ||
Chicago |
70,000 |
$4.45 | ||
4Q 2017: |
||||
NYMEX Henry Hub |
1,370,000 |
$3.46 | ||
CGTLA |
420,000 |
$4.37 | ||
Chicago |
70,000 |
$4.68 | ||
2H 2017 Total |
1,860,000 |
$3.64 | ||
2018 NYMEX Henry Hub |
2,002,500 |
$3.50 | ||
2019 NYMEX Henry Hub |
2,330,000 |
$3.50 | ||
2020 NYMEX Henry Hub |
1,417,500 |
$3.25 | ||
2021 NYMEX Henry Hub |
710,000 |
$3.00 | ||
2022 NYMEX Henry Hub |
850,000 |
$3.00 | ||
2023 NYMEX Henry Hub |
90,000 |
$2.91 |
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero Resource's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income including noncontrolling interest to adjusted EBITDAX.
Twelve months ended | ||
June 30, | ||
2017 | ||
Net Income including noncontrolling interest |
$ |
160,915 |
Commodity derivative gains |
(414,945) | |
Net cash receipts on settled derivative instruments |
462,149 | |
Gain on sale of assets |
(97,635) | |
Interest expense |
262,925 | |
Loss on early extinguishment of debt |
16,956 | |
Income tax expense |
25,468 | |
Depreciation, depletion, amortization and accretion |
827,381 | |
Impairment of unproved properties |
169,563 | |
Exploration expense |
8,650 | |
Equity-based compensation expense |
105,613 | |
Equity in earnings of unconsolidated affiliates |
(5,855) | |
Distributions from unconsolidated affiliates |
13,522 | |
State franchise taxes |
11 | |
Total Adjusted EBITDAX |
$ |
1,534,718 |
"Standalone E&P Adjusted EBITDAX" is also used by our management team for various purposes, including as a measure of operating performance of our exploration and production and marketing segments and as a basis for strategic planning and forecasting. Standalone E&P Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income or loss before derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Standalone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. Operating income or loss represents net income or loss, including noncontrolling interests, before interest expense and interest income, income taxes, and equity in earnings of unconsolidated affiliates. Operating income is the most directly comparable GAAP financial measure to Standalone E&P Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis.
The following table reconciles operating income to total Adjusted EBITDAX on a standalone E&P basis. Standalone E&P basis includes operations from both the exploration and production segment and marketing segment (in thousands):
Twelve months ended | ||
June 30, | ||
2017 | ||
Standalone E&P operating income |
$ |
315,172 |
Commodity derivative gains |
(414,945) | |
Net cash receipts on settled derivatives instruments |
462,149 | |
Depreciation, depletion, amortization and accretion |
716,516 | |
Impairment of unproved properties |
169,563 | |
Exploration expense |
8,650 | |
Change in fair value of contingent acquisition consideration |
(16,748) | |
Equity-based compensation expense |
79,093 | |
Gain on sale of assets |
(93,776) | |
State franchise taxes |
11 | |
Distributions from limited partner interest in Antero Midstream |
119,213 | |
Standalone E&P Adjusted EBITDAX |
$ |
1,344,898 |
The following table reconciles total debt to net debt on a consolidated basis and a standalone E&P basis (in thousands):
June 30, |
Pro Forma June 30, | |||||
2017 |
2017 | |||||
AR Bank credit facility |
$ |
930,000 |
$ |
— | ||
AM Bank credit facility |
305,000 |
305,000 | ||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | ||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | ||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | ||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | ||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | ||||
AR Net unamortized premium |
1,655 |
1,655 | ||||
AR Net unamortized debt issuance costs |
(35,131) |
(35,131) | ||||
AM Net unamortized debt issuance costs |
(9,551) |
(9,551) | ||||
Consolidated total debt |
$ |
5,291,973 |
$ |
4,361,973 | ||
Less: AR Cash and cash equivalents |
22,657 |
153,657 | ||||
Less: AM Cash and cash equivalents |
17,533 |
17,533 | ||||
Consolidated net debt |
$ |
5,251,783 |
$ |
4,190,783 | ||
Standalone E&P net debt |
$ |
4,323,867 |
$ |
3,262,867 |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Resource's control. All statements, other than historical facts included in this release, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Midstream Partners LP.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resource's Annual Report on Form 10-K for the year ended December 31, 2016.
1. |
Includes distributions from limited partner interests in Antero Midstream and expected contingent payments to be received from Antero Midstream related to the divestiture of its fresh water delivery business. |
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SOURCE Antero Resources Corporation
DENVER, Sept. 6, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today the pricing of an underwritten public offering of 10,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream Partners LP (NYSE: AM) (the "Partnership") held by Antero Resources at a price of $31.45 per common unit for aggregate gross proceeds of approximately $315 million before estimated offering expenses. In connection with the Offering, Antero Resources granted the underwriters a 30-day option to purchase up to an additional 1,500,000 common units. After giving effect to the Offering and assuming no exercise of the underwriters' option to purchase additional common units, Antero Resources will own approximately 53% of the Partnership's outstanding common units.
Barclays and Wells Fargo are acting as joint book-running managers for the Offering. The Offering will only be made by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Barclays Capital Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY 11717 barclaysprospectus@broadridge.com Toll-Free: 1-888-603-5847 |
Wells Fargo Securities c/o Equity Syndicate Department 375 Park Avenue New York, NY 10152 cmclientsupport@wellsfargo.com Telephone: 1-800-326-5897 |
Antero Midstream Partners LP has filed a registration statement (including a prospectus) with the Securities and Exchange Commission (the "SEC") for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents Antero Midstream Partners LP has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, Antero Resources will arrange to send you the prospectus after filing if you request it by calling (303) 357-7310. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Resource's control. All statements, other than historical facts included in this release, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Midstream Partners LP.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resource's Annual Report on Form 10-K for the year ended December 31, 2016.
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SOURCE Antero Resources Corporation
DENVER, Sept. 6, 2017 /PRNewswire/ -- Antero Midstream Partners (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced the pricing of an underwritten public offering of 10,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream held by Antero Resources Corporation (NYSE: AR) at a price of $31.45 per unit for aggregate gross proceeds to Antero Resources Corporation of approximately $315 million before estimated offering expenses. Antero Midstream will not receive any proceeds from the sale of common units in the Offering. In connection with the Offering, Antero Resources granted the underwriters a 30-day option to purchase up to an additional 1,500,000 common units. After giving effect to the Offering and assuming no exercise of the underwriters' option to purchase additional common units, Antero Resources will own approximately 53% of the Partnership's outstanding common units.
Barclays and Wells Fargo are acting as joint book-running managers for the Offering. The Offering will only be made by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Barclays Capital Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY 11717 barclaysprospectus@broadridge.com Toll-Free: 1-888-603-5847 |
Wells Fargo Securities c/o Equity Syndicate Department 375 Park Avenue New York, NY 10152 cmclientsupport@wellsfargo.com Telephone: 1-800-326-5897 |
Antero Midstream has filed a registration statement (including a prospectus) with the Securities and Exchange Commission (the "SEC") for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents Antero Midstream has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, Antero Resources will arrange to send you the prospectus after filing if you request it by calling (303) 357-7310. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering, compression, processing and fractionation assets as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio. Holders of Antero Midstream common units will receive a Schedule K-1 with respect to distributions received on the common units.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Midstream's control. All statements, other than historical facts included in this release, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Midstream believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Midstream.
Antero Midstream cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership's control, incident to the gathering and processing and fresh water and waste water treatment businesses. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2016.
For more information, contact Michael Kennedy – CFO of Antero Midstream, at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream Partners LP
DENVER, Sept. 6, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources," the "Company" or the "Selling Unitholder") announced today the commencement of an underwritten public offering (the "Offering") of 10,000,000 common units representing limited partner interests in Antero Midstream Partners LP (NYSE: AM) held by Antero Resources. In addition, the Selling Unitholder anticipates granting the underwriters a 30-day option to purchase up to an additional 1,500,000 common units. Antero Resources intends to use the net proceeds from the Offering to repay borrowings under its credit facility. The Company currently owns 108,870,335 common units.
Barclays and Wells Fargo are acting as joint book-running managers for the Offering. The Offering will only be made by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Barclays Capital Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY 11717 barclaysprospectus@broadridge.com Toll-Free: 1-888-603-5847 |
Wells Fargo Securities c/o Equity Syndicate Department 375 Park Avenue New York, NY 10152 cmclientsupport@wellsfargo.com Telephone: 1-800-326-5897 |
Antero Midstream Partners LP intends to file a registration statement (including a prospectus) with the Securities and Exchange Commission (the "SEC") for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents Antero Midstream Partners LP has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, Antero Resources will arrange to send you the prospectus after filing if you request it by calling (303) 357-7310. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Resource's control. All statements, other than historical facts included in this release, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Midstream Partners LP.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resource's Annual Report on Form 10-K for the year ended December 31, 2016.
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SOURCE Antero Resources Corporation
DENVER, Sept. 6, 2017 /PRNewswire/ -- Antero Midstream Partners (NYSE: AM) ("Antero Midstream" or the "Partnership") announced today that Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Selling Unitholder") commenced an underwritten public offering (the "Offering") of 10,000,000 common units representing limited partner interests in Antero Midstream held by Antero Resources. In addition, the Selling Unitholder anticipates granting the underwriters a 30-day option to purchase up to an additional 1,500,000 common units. Antero Resources intends to use the net proceeds from the Offering to repay borrowings under its credit facility. Antero Resources currently owns 108,870,335 common units. Antero Midstream will not receive any proceeds from the sale of common units in the Offering.
Barclays and Wells Fargo are acting as joint book-running managers for the Offering. The Offering will only be made by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from
Barclays Capital Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY 11717 barclaysprospectus@broadridge.com Toll-Free: 1-888-603-5847 |
Wells Fargo Securities c/o Equity Syndicate Department 375 Park Avenue New York, NY 10152 cmclientsupport@wellsfargo.com Telephone: 1-800-326-5897 |
Antero Midstream intends to file a registration statement (including a prospectus) with the Securities and Exchange Commission (the "SEC") for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents Antero Midstream has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, Antero Resources will arrange to send you the prospectus after filing if you request it by calling (303) 357-7310. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering, compression, processing and fractionation assets as well as integrated water assets that primarily service Antero Resources'properties located in West Virginia and Ohio. Holders of Antero Midstream common units will receive a Schedule K-1 with respect to distributions received on the common units.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Midstream's control. All statements, other than historical facts included in this release, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero Midstream believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Midstream.
Antero Midstream cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership's control, incident to the gathering and processing and fresh water and waste water treatment businesses. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2016.
For more information, contact Michael Kennedy – CFO of Antero Midstream, at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream Partners LP
DENVER, Aug. 2, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its second quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, which has been filed with the Securities and Exchange Commission (the "SEC").
Highlights Include:
Recent Developments
Raising 2017 Guidance
The Company is raising its 2017 net production guidance from a range of 2,160 to 2,250 Bcfe/d to a range of 2,250 to 2,300 Bcfe/d. This represents a 3% increase from the previously announced guidance. The increase in production guidance is primarily a function of the improved recoveries Antero continues to achieve through its advanced completions. Antero's advanced completions have utilized 1,500 to 2,500 pounds of proppant per foot, averaging 2,045 pounds of proppant per foot year to date in 2017. These techniques have yielded encouraging results with initial wellhead EURs ranging from 1.9 to 2.7 Bcf per 1,000' of lateral as compared to the Company's historical 1.7 Bcf per 1,000' type curve.
While the net production guidance is being raised, there is no change to the Company's $1.3 billion drilling and completion budget for 2017 due to continued efficiency gains. Drilling efficiencies include a reduction in drilling days in the Marcellus from 15 days in 2016 to 12 days in the second quarter of 2017 despite drilling longer laterals. In the second quarter of 2017, Antero drilled an average of 5,200 lateral feet per day in the Marcellus and the Company's average completed lateral was 9,400 feet and 11,200 feet in the Marcellus and Ohio Utica, respectively. Further, the Company continues to increase pad sizes and is currently drilling both a 12-well and a 14-well pad in the Marcellus.
Year to date in 2017, Antero has placed 59 total wells to sales. Of the 54 wells Antero has completed in the Marcellus, 46, or 85%, have used greater than 1,750 pounds of proppant per foot and have generated aggregate production in excess of the Company's 2.0 Bcf/1,000' type curve target through 180 days.
The following table is a comparison of the original 2017 production guidance issued in January 2017 and the revised 2017 guidance.
Guidance |
2017 – New |
2017 – Previous | ||||||||
Low |
High |
Low |
High | |||||||
Production |
||||||||||
Net Daily Production (MMcfe/d) |
2,250 |
2,300 |
2,160 |
2,250 | ||||||
Net Daily Residue Natural Gas Production (MMcf/d) |
1,650 |
1,675 |
1,625 |
1,675 | ||||||
Net Daily Liquids Production (Bbl/d) |
100,000 |
105,000 |
88,500 |
96,500 | ||||||
Net Daily C3+ NGL Production (Bbl/d) |
68,000 |
71,000 |
65,000 |
70,000 | ||||||
Net Daily Ethane Production (Bbl/d) |
26,000 |
27,000 |
18,000 |
20,000 | ||||||
Net Daily Oil Production (Bbl/d) |
6,000 |
7,000 |
5,500 |
6,500 | ||||||
Capital Expenditures ($MM) |
||||||||||
Drilling and Completion Capital |
$1,300 |
$1,300 | ||||||||
Land |
$200 |
$200 |
Mid-Year 2017 Proved and 3P Reserves
Antero announced today that internally estimated proved reserves at mid-year 2017 were 16.5 Tcfe, a 7% increase compared to estimated proved reserves at December 31, 2016. Assuming futures strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing, the pre-tax present value discounted at 10% ("pre-tax PV–10") of the June 30, 2017 estimated proved reserves was $10.1 billion, including $1.7 billion of hedge value. All-in finding and development cost for proved reserve additions was $0.48 per Mcfe. Drill bit only finding and development cost for proved reserve additions was $0.47 per Mcfe. Proved developed reserves increased by 20% from year-end 2016 to 8.3 Tcfe at June 30, 2017 and the percentage of proved reserves classified as proved developed increased to 50%. The Company's proved, probable and possible ("3P") reserves at mid-year 2017 totaled 53.0 Tcfe, which represents a 14% increase compared to year-end 2016. Assuming futures strip benchmark pricing and applying the same company-specific production weighting for Appalachian index pricing, the pre-tax PV–10 of the June 30, 2017 3P reserves was $17.0 billion, including hedges. The 3P reserve figures exclude virtually all of the Company's Upper Devonian and West Virginia Utica resource.
Included in the mid-year 2017 reserves are 199 proved undeveloped and 398 probable locations that were upgraded to an approximate 2.0 Bcf/1,000' type curve from a 1.7 Bcf/1,000' type curve at year-end 2016. There are now 294 proved undeveloped locations, or 83% of the total proved undeveloped locations in the Marcellus that are booked at an approximate 2.0 Bcf/1,000' type curve. The remaining 60 Marcellus proved undeveloped locations are booked at a 1.7 Bcf/1,000' type curve.
Commenting on the continued enhanced recoveries and the impact on production and reserves, Paul Rady, Chairman and CEO, said, "We continue to see outstanding results from our advanced completions in the Marcellus that we began implementing in early 2016. In recognition of these productivity gains, our reserve engineers have now upgraded nearly 600 proved and probable drilling locations in the Marcellus from our previous 1.7 Bcf/1,000' type curve to an approximate 2.0 Bcf/1,000' type curve. The enhanced productivity from these completions combined with continued operational efficiencies has resulted in a further reduction in per unit development costs and a further increase in capital efficiency. The enhanced completions program has also resulted in a 3% increase to our production guidance without raising capital spending guidance."
Asset Acquisition
In early June of 2017, Antero closed on a 10,300 net acre Marcellus acquisition primarily located in Doddridge and Wetzel Counties, West Virginia for approximately $130 million. The acquisition included approximately 17 MMcfe/d of net equivalent production, 15 drilled but uncompleted wells with an average lateral length of 8,200 feet and one undeveloped drilling pad. Antero estimates the undeveloped properties include 418 Bcfe and 958 Bcfe of unaudited Marcellus proved reserves and 3P reserves, respectively, which were included in Antero's mid-year reserve analysis. In total, the acquisition adds 89 undeveloped 3P locations and enhances 74 existing 3P locations with incremental working interests and/or increased lateral length. The lateral length of the new or enhanced 3P locations average 8,700 feet.
Second Quarter 2017 Financial and Operating Results
As of June 30, 2017, Antero owned a 58% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated with Antero's results.
For the three months ended June 30, 2017, the Company reported a net loss of $5 million, or $(0.02) per basic and diluted share, compared to a net loss of $596 million, or $(2.12) per basic and diluted share, in the second quarter of 2016. The net loss for the second quarter of 2017 included the following items:
Excluding the items detailed above, the Company's results for the second quarter of 2017 were as follows:
For a description of adjusted net loss and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the second quarter of 2017 averaged 2,200 MMcfe/d, including 102,766 Bbl/d of liquids (28% liquids). Second quarter 2017 production represents an organic production growth rate of 25% from the second quarter of 2016 and a 3% increase compared to the first quarter of 2017. Second quarter 2017 C3+ natural gas liquids ("NGLs") and oil production averaged 68,026 Bbl/d and 6,738 Bbl/d, respectively. Ethane (C2) production averaged 28,003 Bbl/d while leaving approximately 91,710 Bbl/d of ethane in the natural gas stream. Total liquids production of 102,766 Bbl/d for the second quarter of 2017 represents an organic production growth rate of 37% and 4% as compared to the second quarter of 2016 and first quarter of 2017, respectively.
Commenting on capital spending and cash flow levels, Glen Warren, President and CFO, said, "Our ability to grow production 25% year-over-year while essentially holding capital spending flat speaks to our material gains in capital efficiency, especially in the face of the commodity down cycle. These gains are driven by a combination of drilling efficiencies which we have continued to achieve and the operational momentum we have been able to sustain through the downturn due to our ability to lock in volumes and pricing through our hedge book and firm transportation portfolio. Looking ahead, we expect to continue to build off this momentum as we are targeting 20% to 22% production growth in 2018 while maintaining a D&C budget at or below 2017 levels. Furthermore, we are targeting drilling and completion capital to be within discretionary cash flow in 2018."
Antero's average natural gas price before hedging increased 63% from the prior year quarter to $3.15 per Mcf, a $0.03 differential to the average Nymex natural gas price for the period. Antero's average realized natural gas price after hedging for the second quarter of 2017 was $3.53 per Mcf, a $0.35 premium to the Nymex average natural gas price for the period, and an 18% decrease compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $55 million, or $0.38 per Mcf compared to $283 million, or $2.38 per Mcf in the prior year quarter.
The Company's average realized C3+ NGL price before hedging for the second quarter of 2017 was $24.14 per barrel, or 50% of the average Nymex WTI oil price, which represents a 41% increase as compared to the prior year quarter. The improvement in C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing combined with an improvement in local differentials. Antero's average realized C3+ NGL price including hedges was $19.92 per barrel, a 5% increase compared to the second quarter of 2016. The Company's average realized ethane price before hedging for the second quarter of 2017 was $0.20 per gallon, or $8.40 per barrel. Antero's average realized ethane price including hedges for the second quarter of 2017 was $0.21 per gallon, or $8.61 per barrel. The average realized oil price before hedging was $43.24 per barrel, a $5.00 differential to Nymex WTI for the period and a 23% increase as compared to the second quarter of 2016. Antero's average realized oil price including hedges was $46.12 per barrel, a $2.12 differential to Nymex WTI for the period.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by $1.13 to $3.26 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 14% to $3.41 per Mcfe compared to the prior year quarter. For the second quarter of 2017, Antero realized a total cash settled hedge gain on all products of $31 million, or $0.16 per Mcfe.
Total operating revenue for the second quarter of 2017 was $790 million as compared to a $249 million loss for the second quarter of 2016. Operating revenue for the second quarter of 2017 included a $55 million non-cash gain on unsettled hedges, while the second quarter of 2016 included a $977 million non-cash loss on unsettled hedges. Revenue excluding the unrealized hedge gain for the quarter was $736 million, which was in line with the second quarter of 2016. Liquids production contributed 30% of total product revenues before hedges in the second quarter of 2017. For a reconciliation of revenue excluding unrealized hedge (gains) losses to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the second quarter of 2017 was $50 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the second quarter of 2017 was $77 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $27 million, or $0.14 per Mcfe, for the second quarter of 2017, representing a 36% or $0.08 per Mcfe decrease from the second quarter of 2016. The reduction in net marketing expense was primarily driven by the decrease in unutilized excess firm transportation capacity, a portion of which was assumed by a third party beginning July 1, 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the second quarter of 2017 was $1.52 per Mcfe, a 3% increase compared to $1.48 per Mcfe in the prior year quarter. The increase is primarily a result of an increase in fuel costs as compared to the prior year due to higher natural gas prices. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.33 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the second quarter of 2017, excluding non-cash equity-based compensation expense, was $0.19 per Mcfe, a 10% decrease from the second quarter of 2016, driven by a 25% increase in production. Per unit depreciation, depletion and amortization expense decreased 18% from the prior year quarter to $1.01 per Mcfe, primarily driven by increases in Antero's estimated recoverable reserves combined with decreases in its per unit development costs. For the Marcellus, per unit depreciation, depletion and amortization expense decreased 19% from the prior year quarter to $0.85 per Mcfe.
Adjusted EBITDAX of $321 million for the second quarter of 2017 represents a 3% decrease compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $1.60 per Mcfe, representing a 23% decrease from the prior year quarter, driven primarily by a reduction in gains on settled derivatives. For the second quarter of 2017, cash flow from operations was $254 million, a 6% increase from the prior year quarter. Cash flow from operations before changes in working capital was $251 million, a 7% decrease from the second quarter of 2016.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended June 30, 2017:
Three Months Ended June 30, 2017 | ||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Net Production |
1,583 |
6,738 |
68,026 |
28,003 |
2,200 | |||||||||
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Realized Prices |
||||||||||||||
Average realized price before settled derivatives |
$ |
3.15 |
$ |
43.24 |
$ |
24.14 |
$ 8.40 |
$ |
3.26 | |||||
Settled derivatives |
0.38 |
2.88 |
(4.22) |
0.21 |
0.15 | |||||||||
Average realized price after settled derivatives |
$ |
3.53 |
$ |
46.12 |
$ |
19.92 |
$ 8.61 |
$ |
3.41 | |||||
Nymex average price |
$ |
3.18 |
$ |
48.24 |
$ |
3.18 | ||||||||
Premium / (Differential) to Nymex |
$ |
0.35 |
$ |
(2.12) |
$ |
0.23 | ||||||||
Marcellus Shale — Antero completed and placed on line 29 horizontal Marcellus wells during the second quarter of 2017 with an average lateral length of 9,380 feet. During the period, Antero drilled an average of 5,200 lateral feet per day, which represents a 50% increase compared to 2016.
Current average well costs are $0.9 million per 1,000 feet of lateral in the Marcellus assuming a 2,000 pounds of proppant per foot completion. Average drilling days from spud to final rig release was 12 days in the second quarter of 2017, a 4% reduction from 2016. Antero is currently operating four drilling rigs and three completion crews in the Marcellus Shale.
In late March 2017, Antero placed two wells to sales on a pad with average lateral lengths of 13,700 feet. The 13,700' laterals each averaged 26 MMcfe/d of production in the first 30 days and have an average wellhead EUR of 2.1 Bcf/1000' and a processed EUR of 2.5 Bcfe/1,000'. The two wells have an average EUR of approximately 34 Bcfe per well.
In mid-July of 2017, the Sherwood 8 processing plant (200 MMcf/d) was placed into service. The Sherwood 8 plant is the second Antero Midstream / MPLX joint venture (the "Joint Venture") plant placed in service during the year and is already 100% utilized. The Joint Venture's next plant, Sherwood 9 (200 MMcf/d), is expected to be in service in January of 2018.
Ohio Utica Shale — Antero completed and placed on line 5 horizontal Utica wells during the second quarter of 2017 with an average lateral length of 11,222 feet. During the period, Antero set a record for drilling its longest lateral to date at 17,380 feet. This lateral was drilled within a 7 foot target zone and was drilled in 12 days. The well is expected to be placed to sales in the third quarter of 2017.
Current average well costs are $1.0 million per 1,000 feet of lateral in the Utica. Antero is currently operating two drilling rigs and two completion crews in the Utica Shale.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the second quarter of 2017 averaged 1,683 MMcf/d, a 24% increase from the second quarter of 2016 and a 3% increase sequentially. Compression volumes for the second quarter of 2017 averaged 1,192 MMcf/d, an 81% increase from the second quarter of 2016 and a 17% increase sequentially. High pressure gathering volumes for the second quarter of 2017 averaged 1,734 MMcf/d, a 38% increase from the second quarter of 2016 and an 11% increase sequentially. The increase in gathering and compression volumes was driven by production growth from Antero Resources in Antero Midstream's area of dedication. Joint Venture processing volumes for the second quarter of 2017 averaged 216 MMcf/d and fractionation volumes averaged 4,039 Bbl/d. Fresh water delivery volumes averaged 173 MBbl/d during the quarter, a 64% increase compared to the prior year quarter and an 18% increase sequentially.
For the three months ended June 30, 2017, Antero Midstream reported revenues of $194 million, comprised of $99 million from the Gathering and Processing segment and $95 million from the Water Handling and Treatment segment. Revenues increased 42% compared to the prior year quarter, driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $36 million from produced water handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $10 million and $42 million, respectively, for a total of $52 million compared to $43 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $35 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $15 million, a $2 million increase compared to the second quarter of 2016. General and administrative expenses excluding equity-based compensation were $8 million during the second quarter of 2017, a $1 million increase compared to the second quarter of 2016. Total operating expenses were $101 million, including $30 million of depreciation and $4 million of accretion of contingent acquisition consideration. During the quarter, Antero Midstream continued construction on the Antero Clearwater Facility, which is expected to be placed into service in the fourth quarter of 2017 and have up to 60,000 Bbl/d of treating capacity.
Antero Midstream Distribution
Antero Midstream declared a cash distribution of $0.32 per unit ($1.28 per unit annualized) for the second quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 7% increase sequentially. The distribution is Antero Midstream's tenth consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on August 16, 2017 to unitholders of record as of August 3, 2017.
Balance Sheet and Liquidity
As of June 30, 2017, Antero's consolidated net debt was $5.3 billion, of which $1.2 billion were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two facilities is currently $5.5 billion. Reduced for $706 million in letters of credit outstanding, the company had $3.6 billion in available consolidated liquidity as of June 30, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Second Quarter 2017 Capital Spending
Antero's drilling and completion costs for the three months ended June 30, 2017 were $322 million. In addition, the Company invested $74 million for land and $130 million for proved property acquisitions. Antero Midstream invested $88 million for gathering and compression systems and $58 million for water infrastructure projects, including $46 million on the Antero Clearwater Treatment Facility. Investments in unconsolidated affiliates for Antero Midstream's processing and fractionation joint venture were $31 million during the quarter.
Hedge Position
Antero currently has hedged 3.1 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from July 1, 2017 through December 31, 2023 at an average index price of $3.62 per MMBtu. At June 30, 2017, the Company's estimated fair value of commodity derivative instruments was $2.0 billion.
The following table summarizes Antero's hedge position as of June 30, 2017:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
3Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.33 |
— |
— | ||
CGTLA |
420,000 |
$4.20 |
— |
— | ||
Chicago |
70,000 |
$4.45 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.39 | ||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
4Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.46 |
— |
— | ||
CGTLA |
420,000 |
$4.37 |
— |
— | ||
Chicago |
70,000 |
$4.68 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.40 | ||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
2017 Total |
1,860,000 |
$3.64 |
50,500 |
N/A (1) | ||
2018: |
||||||
Nymex Henry Hub |
2,002,500 |
$3.91 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
2,000 |
$0.65 | ||
2019 Nymex Henry Hub |
2,330,000 |
$3.70 |
— |
— | ||
2020 Nymex Henry Hub |
1,417,500 |
$3.63 |
— |
— | ||
2021 Nymex Henry Hub |
710,000 |
$3.31 |
— |
— | ||
2022 Nymex Henry Hub |
850,000 |
$3.16 |
— |
— | ||
2023 Nymex Henry Hub |
90,000 |
$2.91 |
— |
— |
(1) |
Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges. |
Conference Call
A conference call is scheduled on Thursday, August 3, 2017 at 9:00 am MT to discuss the quarterly results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, August 11, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10108841.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, August 11, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the August 3, 2017 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled hedges. Antero believes that revenue excluding unrealized hedge (gains) losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge (gains) losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge (gains) losses (in thousands):
Three months ended |
Six months ended June 30, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Total operating revenue |
$ |
(249,198) |
$ |
790,389 |
$ |
471,806 |
$ |
1,985,968 | ||||
Hedge (gains) losses |
684,634 |
(85,641) |
404,710 |
(524,416) | ||||||||
Cash receipts for settled hedges |
292,500 |
31,064 |
616,847 |
75,913 | ||||||||
Revenue excluding unrealized hedge (gains) losses |
$ |
727,936 |
$ |
735,812 |
$ |
1,493,363 |
$ |
1,537,465 |
Adjusted net income (loss) as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income (loss) is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income (loss) is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (loss) (in thousands):
Three months ended |
Six months ended | |||||||||||
June 30, |
June 30, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net income (loss) |
$ |
(596,244) |
$ |
(5,132) |
$ |
(601,299) |
$ |
263,264 | ||||
Hedge (gains) losses |
684,634 |
(85,641) |
404,710 |
(524,416) | ||||||||
Cash receipts for settled hedges |
292,500 |
31,064 |
616,847 |
75,913 | ||||||||
Impairment of unproved properties |
19,944 |
15,199 |
35,470 |
42,098 | ||||||||
Equity-based compensation |
25,816 |
26,975 |
49,286 |
52,478 | ||||||||
Income tax effect of reconciling items |
(385,928) |
4,693 |
(417,401) |
133,918 | ||||||||
Adjusted net income (loss) |
$ |
40,722 |
$ |
(12,842) |
$ |
87,613 |
$ |
43,255 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended |
Six months ended June 30, | |||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||
Net cash provided by operating activities |
$ |
238,538 |
$ |
253,647 |
$ |
578,706 |
$ |
647,586 | ||||
Net change in working capital |
30,218 |
(2,853) |
(18,612) |
(100,190) | ||||||||
Cash flow from operations before changes in working capital |
$ |
268,756 |
$ |
250,794 |
$ |
560,094 |
$ |
547,396 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, |
June 30, | ||||||
2016 |
2017 | ||||||
Bank credit facilities |
$ |
650,000 |
$ |
1,235,000 | |||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | |||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | |||||
Net unamortized premium |
1,749 |
1,655 | |||||
Net unamortized debt issuance costs |
(47,776) |
(44,682) | |||||
Consolidated total debt |
$ |
4,703,973 |
$ |
5,291,973 | |||
Less: Cash and cash equivalents |
31,610 |
40,190 | |||||
Consolidated net debt |
$ |
4,672,363 |
$ |
5,251,783 | |||
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
Three months ended |
Six months ended | |||||||||||||||||||
June 30, |
June 30, | |||||||||||||||||||
2016 |
2017 |
2016 |
2017 | |||||||||||||||||
Net Income (loss) including noncontrolling interest |
$ |
(575,490) |
$ |
39,965 |
$ |
(564,840) |
$ |
345,523 | ||||||||||||
Commodity derivative (gains) losses |
684,634 |
(85,641) |
404,710 |
(524,416) | ||||||||||||||||
Gains on settled derivative instruments |
292,500 |
31,064 |
616,847 |
75,913 | ||||||||||||||||
Interest expense |
62,595 |
68,582 |
125,879 |
135,252 | ||||||||||||||||
Income tax expense (benefit) |
(376,494) |
18,819 |
(371,679) |
150,165 | ||||||||||||||||
Depreciation, depletion, amortization, and accretion |
197,982 |
201,831 |
390,162 |
405,197 | ||||||||||||||||
Impairment of unproved properties |
19,944 |
15,199 |
35,470 |
42,098 | ||||||||||||||||
Exploration expense |
1,109 |
1,804 |
2,123 |
3,911 | ||||||||||||||||
Equity-based compensation expense |
25,816 |
26,975 |
49,286 |
52,478 | ||||||||||||||||
Equity in earnings of unconsolidated affiliate |
(484) |
(3,623) |
(484) |
(5,854) | ||||||||||||||||
Distributions from unconsolidated affiliates |
— |
5,820 |
— |
5,820 | ||||||||||||||||
State franchise taxes |
— |
— |
39 |
— | ||||||||||||||||
Total Adjusted EBITDAX |
332,112 |
320,795 |
687,513 |
686,087 | ||||||||||||||||
Interest expense |
(62,595) |
(68,582) |
(125,879) |
(135,252) | ||||||||||||||||
Exploration expense |
(1,109) |
(1,804) |
(2,123) |
(3,911) | ||||||||||||||||
Changes in current assets and liabilities |
(30,218) |
2,853 |
18,612 |
100,190 | ||||||||||||||||
State franchise taxes |
— |
— |
(39) |
— | ||||||||||||||||
Other non-cash items |
348 |
385 |
622 |
472 | ||||||||||||||||
Net cash provided by operating activities |
$ |
238,538 |
$ |
253,647 |
$ |
578,706 |
$ |
647,586 | ||||||||||||
Three months ended |
Six months ended |
|||||||||||||||||||
June 30, |
June 30, |
|||||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2016 |
2017 |
2016 |
2017 |
||||||||||||||||
Realized price before cash receipts for settled hedges |
$ |
2.13 |
$ |
3.26 |
$ |
2.12 |
$ |
3.41 |
||||||||||||
Gathering, compression, water handling and treatment revenues |
0.02 |
0.04 |
0.02 |
0.03 |
||||||||||||||||
Lease operating expense |
(0.08) |
(0.08) |
(0.07) |
(0.08) |
||||||||||||||||
Gathering, compression, processing and transportation costs |
(1.29) |
(1.33) |
(1.29) |
(1.36) |
||||||||||||||||
Marketing, net |
(0.22) |
(0.14) |
(0.23) |
(0.13) |
||||||||||||||||
Production taxes |
(0.11) |
(0.11) |
(0.11) |
(0.12) |
||||||||||||||||
General and administrative(1) |
(0.21) |
(0.19) |
(0.21) |
(0.19) |
||||||||||||||||
Adjusted EBITDAX margin before settled hedges |
0.24 |
1.45 |
0.23 |
1.56 |
||||||||||||||||
Cash receipts for settled hedges |
1.82 |
0.15 |
1.93 |
0.19 |
||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.06 |
$ |
1.60 |
$ |
2.16 |
$ |
1.75 |
||||||||||||
(1) Excludes equity-based stock compensation |
||||||||||||||||||||
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2016.
Reserves Disclosure
In this release, Antero has provided a number of unaudited reserve metrics, which include all-in finding and development cost per unit and drill bit only finding and development cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The finding and development costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the finding and development costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. The calculations for both all-in and drill bit only finding and development cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Pre-tax PV–10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV–10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV–10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV–10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV–10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.
ANTERO RESOURCES CORPORATION |
|||||||
Condensed Consolidated Balance Sheets |
|||||||
December 31, 2016 and June 30, 2017 |
|||||||
(unaudited) |
|||||||
(In thousands, except per share amounts) |
|||||||
December 31, 2016 |
June 30, 2017 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
31,610 |
40,190 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2016 and 2017 |
29,682 |
16,494 |
|||||
Accrued revenue |
261,960 |
218,621 |
|||||
Derivative instruments |
73,022 |
452,005 |
|||||
Other current assets |
6,313 |
8,573 |
|||||
Total current assets |
402,587 |
735,883 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
2,331,173 |
2,309,839 |
|||||
Proved properties |
9,549,671 |
10,493,932 |
|||||
Water handling and treatment systems |
744,682 |
840,183 |
|||||
Gathering systems and facilities |
1,723,768 |
1,884,712 |
|||||
Other property and equipment |
41,231 |
48,537 |
|||||
14,390,525 |
15,577,203 |
||||||
Less accumulated depletion, depreciation, and amortization |
(2,363,778) |
(2,767,358) |
|||||
Property and equipment, net |
12,026,747 |
12,809,845 |
|||||
Derivative instruments |
1,731,063 |
1,600,165 |
|||||
Investments in unconsolidated affiliates |
68,299 |
259,697 |
|||||
Other assets |
26,854 |
36,631 |
|||||
Total assets |
$ |
14,255,550 |
15,442,221 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
38,627 |
51,567 |
||||
Accrued liabilities |
393,803 |
418,352 |
|||||
Revenue distributions payable |
163,989 |
203,151 |
|||||
Derivative instruments |
203,635 |
3,279 |
|||||
Other current liabilities |
17,334 |
16,711 |
|||||
Total current liabilities |
817,388 |
693,060 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,703,973 |
5,291,973 |
|||||
Deferred income tax liability |
950,217 |
1,100,382 |
|||||
Derivative instruments |
234 |
172 |
|||||
Other liabilities |
55,160 |
53,772 |
|||||
Total liabilities |
6,526,972 |
7,139,359 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 314,877 shares and 315,448 shares, respectively |
3,149 |
3,154 |
|||||
Additional paid-in capital |
5,299,481 |
6,435,047 |
|||||
Accumulated earnings |
959,995 |
1,223,259 |
|||||
Total stockholders' equity |
6,262,625 |
7,661,460 |
|||||
Noncontrolling interests in consolidated subsidiary |
1,465,953 |
641,402 |
|||||
Total equity |
7,728,578 |
8,302,862 |
|||||
Total liabilities and equity |
$ |
14,255,550 |
15,442,221 |
ANTERO RESOURCES CORPORATION | ||||||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Loss | ||||||||||||||
Three Months Ended June 30, 2016 and 2017 | ||||||||||||||
(unaudited) | ||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||
Three Months Ended June 30, |
||||||||||||||
2016 |
2017 |
|||||||||||||
Revenue: |
||||||||||||||
Natural gas sales |
$ |
229,787 |
454,257 |
|||||||||||
Natural gas liquids sales |
94,713 |
170,819 |
||||||||||||
Oil sales |
16,740 |
26,512 |
||||||||||||
Gathering, compression, water handling and treatment |
3,294 |
3,192 |
||||||||||||
Marketing |
90,902 |
49,968 |
||||||||||||
Commodity derivative fair value gains (losses) |
(684,634) |
85,641 |
||||||||||||
Total revenue |
(249,198) |
790,389 |
||||||||||||
Operating expenses: |
||||||||||||||
Lease operating |
12,043 |
16,992 |
||||||||||||
Gathering, compression, processing, and transportation |
206,060 |
266,747 |
||||||||||||
Production and ad valorem taxes |
17,458 |
22,553 |
||||||||||||
Marketing |
125,977 |
77,421 |
||||||||||||
Exploration |
1,109 |
1,804 |
||||||||||||
Impairment of unproved properties |
19,944 |
15,199 |
||||||||||||
Depletion, depreciation, and amortization |
197,362 |
201,182 |
||||||||||||
Accretion of asset retirement obligations |
620 |
649 |
||||||||||||
General and administrative (including equity-based compensation expense of $25,816 and $26,975 in 2016 and 2017, respectively) |
60,102 |
64,099 |
||||||||||||
Total operating expenses |
640,675 |
666,646 |
||||||||||||
Operating income (loss) |
(889,873) |
123,743 |
||||||||||||
Other income (expenses): |
||||||||||||||
Equity in earnings of unconsolidated affiliates |
484 |
3,623 |
||||||||||||
Interest |
(62,595) |
(68,582) |
||||||||||||
Total other expenses |
(62,111) |
(64,959) |
||||||||||||
Income (loss) before income taxes |
(951,984) |
58,784 |
||||||||||||
Provision for income tax (expense) benefit |
376,494 |
(18,819) |
||||||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
(575,490) |
39,965 |
||||||||||||
Net income and comprehensive income attributable to noncontrolling interests |
20,754 |
45,097 |
||||||||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation |
$ |
(596,244) |
(5,132) |
|||||||||||
Loss per common share—basic |
$ |
(2.12) |
(0.02) |
|||||||||||
Loss per common share—assuming dilution |
$ |
(2.12) |
(0.02) |
|||||||||||
Weighted average number of shares outstanding: |
||||||||||||||
Basic |
281,786 |
315,401 |
||||||||||||
Diluted |
281,786 |
315,401 |
||||||||||||
ANTERO RESOURCES CORPORATION |
|||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) |
|||||||
Six Months Ended June 30, 2016 and 2017 |
|||||||
(unaudited) |
|||||||
(In thousands, except per share amounts) |
|||||||
Six Months Ended June 30, |
|||||||
2016 |
2017 |
||||||
Revenue and other: |
|||||||
Natural gas sales |
484,563 |
920,921 |
|||||
Natural gas liquids sales |
167,778 |
365,471 |
|||||
Oil sales |
26,919 |
53,472 |
|||||
Gathering, compression, water handling and treatment |
7,138 |
5,796 |
|||||
Marketing |
190,118 |
115,892 |
|||||
Commodity derivative fair value gains (losses) |
(404,710) |
524,416 |
|||||
Total revenue and other |
471,806 |
1,985,968 |
|||||
Operating expenses: |
|||||||
Lease operating |
23,336 |
32,543 |
|||||
Gathering, compression, processing, and transportation |
414,798 |
533,576 |
|||||
Production and ad valorem taxes |
36,742 |
47,346 |
|||||
Marketing |
263,910 |
167,414 |
|||||
Exploration |
2,123 |
3,911 |
|||||
Impairment of unproved properties |
35,470 |
42,098 |
|||||
Depletion, depreciation, and amortization |
388,944 |
403,911 |
|||||
Accretion of asset retirement obligations |
1,218 |
1,286 |
|||||
General and administrative (including equity-based compensation expense of $49,286 and $52,478 in 2016 and 2017, respectively) |
116,389 |
128,797 |
|||||
Total operating expenses |
1,282,930 |
1,360,882 |
|||||
Operating income (loss) |
(811,124) |
625,086 |
|||||
Other income (expenses): |
|||||||
Equity in earnings of unconsolidated affiliates |
484 |
5,854 |
|||||
Interest |
(125,879) |
(135,252) |
|||||
Total other expenses |
(125,395) |
(129,398) |
|||||
Income (loss) before income taxes |
(936,519) |
495,688 |
|||||
Provision for income tax (expense) benefit |
371,679 |
(150,165) |
|||||
Net income (loss) and comprehensive income (loss) including noncontrolling interests |
(564,840) |
345,523 |
|||||
Net income and comprehensive income attributable to noncontrolling interests |
36,459 |
82,259 |
|||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
(601,299) |
263,264 |
|||||
Earnings (loss) per common share—basic |
$ |
(2.15) |
0.84 |
||||
Earnings (loss) per common share—assuming dilution |
$ |
(2.15) |
0.83 |
||||
Weighted average number of shares outstanding: |
|||||||
Basic |
279,418 |
315,179 |
|||||
Diluted |
279,418 |
315,927 |
ANTERO RESOURCES CORPORATION |
||||||||
Condensed Consolidated Statements of Cash Flows |
||||||||
Six Months Ended June 30, 2016 and 2017 |
||||||||
(unaudited) |
||||||||
(In thousands) |
||||||||
Six Months Ended June 30, |
||||||||
2016 |
2017 |
|||||||
Cash flows from operating activities: |
||||||||
Net income (loss) including noncontrolling interests |
$ |
(564,840) |
345,523 |
|||||
Adjustment to reconcile net income (loss) to net cash provided by operating activities: |
||||||||
Depletion, depreciation, amortization, and accretion |
390,162 |
405,197 |
||||||
Impairment of unproved properties |
35,470 |
42,098 |
||||||
Derivative fair value (gains) losses |
404,710 |
(524,416) |
||||||
Gains on settled derivatives |
616,848 |
75,913 |
||||||
Deferred income tax expense (benefit) |
(371,679) |
150,165 |
||||||
Equity-based compensation expense |
49,286 |
52,478 |
||||||
Equity in earnings of unconsolidated affiliates |
(484) |
(5,854) |
||||||
Distributions of earnings from unconsolidated affiliates |
— |
5,820 |
||||||
Other |
621 |
472 |
||||||
Changes in current assets and liabilities: |
||||||||
Accounts receivable |
7,798 |
13,188 |
||||||
Accrued revenue |
(5,237) |
43,339 |
||||||
Other current assets |
1,559 |
(2,385) |
||||||
Accounts payable |
13,223 |
2,072 |
||||||
Accrued liabilities |
(3,362) |
4,204 |
||||||
Revenue distributions payable |
5,105 |
39,162 |
||||||
Other current liabilities |
(474) |
610 |
||||||
Net cash provided by operating activities |
578,706 |
647,586 |
||||||
Cash flows used in investing activities: |
||||||||
Additions to proved properties |
— |
(179,318) |
||||||
Additions to unproved properties |
(58,195) |
(129,876) |
||||||
Drilling and completion costs |
(709,974) |
(629,308) |
||||||
Additions to water handling and treatment systems |
(78,625) |
(95,451) |
||||||
Additions to gathering systems and facilities |
(97,300) |
(155,365) |
||||||
Additions to other property and equipment |
(1,296) |
(6,564) |
||||||
Investments in unconsolidated affiliates |
(45,044) |
(191,364) |
||||||
Change in other assets |
(47,925) |
(12,452) |
||||||
Other |
— |
2,156 |
||||||
Net cash used in investing activities |
(1,038,359) |
(1,397,542) |
||||||
Cash flows from financing activities: |
||||||||
Issuance of common stock |
752,599 |
— |
||||||
Issuance of common units by Antero Midstream Partners LP |
— |
246,585 |
||||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
178,000 |
— |
||||||
Borrowings (repayments) on bank credit facilities, net |
(427,000) |
585,000 |
||||||
Payments of deferred financing costs |
(96) |
— |
||||||
Distributions to noncontrolling interests in consolidated subsidiary |
(31,681) |
(61,869) |
||||||
Employee tax withholding for settlement of equity compensation awards |
(4,819) |
(8,433) |
||||||
Other |
(2,572) |
(2,747) |
||||||
Net cash provided by financing activities |
464,431 |
758,536 |
||||||
Net increase in cash and cash equivalents |
4,778 |
8,580 |
||||||
Cash and cash equivalents, beginning of period |
23,473 |
31,610 |
||||||
Cash and cash equivalents, end of period |
$ |
28,251 |
40,190 |
|||||
Supplemental disclosure of cash flow information: |
||||||||
Cash paid during the period for interest |
$ |
121,128 |
125,284 |
|||||
Supplemental disclosure of noncash investing activities: |
||||||||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment |
$ |
(155,671) |
31,182 |
|||||
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the three months ended June 30, 2016 compared to the three months ended June 30, 2017: | ||||||||||||
Three Months Ended June 30, |
Amount of |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
229,787 |
$ |
454,257 |
$ |
224,470 |
98 |
% | ||||
NGLs sales |
94,713 |
170,819 |
76,106 |
80 |
% | |||||||
Oil sales |
16,740 |
26,512 |
9,772 |
58 |
% | |||||||
Gathering, compression, water handling and treatment |
3,294 |
3,192 |
(102) |
(3) |
% | |||||||
Marketing |
90,902 |
49,968 |
(40,934) |
(45) |
% | |||||||
Commodity derivative fair value gains (losses) |
(684,634) |
85,641 |
770,275 |
* |
||||||||
Total operating revenues and other |
(249,198) |
790,389 |
1,039,587 |
* |
||||||||
Operating expenses: |
||||||||||||
Lease operating |
12,043 |
16,992 |
4,949 |
41 |
% | |||||||
Gathering, compression, processing, and transportation |
206,060 |
266,747 |
60,687 |
29 |
% | |||||||
Production and ad valorem taxes |
17,458 |
22,553 |
5,095 |
29 |
% | |||||||
Marketing |
125,977 |
77,421 |
(48,556) |
(39) |
% | |||||||
Exploration |
1,109 |
1,804 |
695 |
63 |
% | |||||||
Impairment of unproved properties |
19,944 |
15,199 |
(4,745) |
(24) |
% | |||||||
Depletion, depreciation, and amortization |
197,362 |
201,182 |
3,820 |
2 |
% | |||||||
Accretion of asset retirement obligations |
620 |
649 |
29 |
5 |
% | |||||||
General and administrative (before equity-based compensation) |
34,286 |
37,124 |
2,838 |
8 |
% | |||||||
Equity-based compensation |
25,816 |
26,975 |
1,159 |
4 |
% | |||||||
Total operating expenses |
640,675 |
666,646 |
25,971 |
4 |
% | |||||||
Operating income (loss) |
(889,873) |
123,743 |
1,013,616 |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
484 |
3,623 |
3,139 |
649 |
% | |||||||
Interest expense |
(62,595) |
(68,582) |
(5,987) |
10 |
% | |||||||
Total other expenses |
(62,111) |
(64,959) |
(2,848) |
5 |
% | |||||||
Income (loss) before income taxes |
(951,984) |
58,784 |
1,010,768 |
* |
||||||||
Income tax (expense) benefit |
376,494 |
(18,819) |
(395,313) |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
(575,490) |
39,965 |
615,455 |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
20,754 |
45,097 |
24,343 |
117 |
% | |||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation |
$ |
(596,244) |
$ |
(5,132) |
$ |
591,112 |
(99) |
% | ||||
Adjusted EBITDAX (1) |
$ |
332,112 |
$ |
320,795 |
$ |
(11,317) |
(3) |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
119 |
144 |
25 |
21 |
% | |||||||
C2 Ethane (MBbl) |
1,581 |
2,548 |
967 |
61 |
% | |||||||
C3+ NGLs (MBbl) |
4,771 |
6,190 |
1,419 |
30 |
% | |||||||
Oil (MBbl) |
477 |
613 |
136 |
29 |
% | |||||||
Combined (Bcfe) |
160 |
200 |
40 |
25 |
% | |||||||
Daily combined production (MMcfe/d) |
1,762 |
2,200 |
438 |
25 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
1.93 |
$ |
3.15 |
$ |
1.22 |
63 |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.36 |
$ |
8.40 |
$ |
0.04 |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
17.08 |
$ |
24.14 |
$ |
7.06 |
41 |
% | ||||
Oil (per Bbl) |
$ |
35.08 |
$ |
43.24 |
$ |
8.16 |
23 |
% | ||||
Combined (per Mcfe) |
$ |
2.13 |
$ |
3.26 |
$ |
1.13 |
53 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.31 |
$ |
3.53 |
$ |
(0.78) |
(18) |
% | ||||
C2 Ethane (per Bbl) |
$ |
8.36 |
$ |
8.61 |
$ |
0.25 |
3 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
18.98 |
$ |
19.92 |
$ |
0.94 |
5 |
% | ||||
Oil (per Bbl) |
$ |
35.08 |
$ |
46.12 |
$ |
11.04 |
31 |
% | ||||
Combined (per Mcfe) |
$ |
3.95 |
$ |
3.41 |
$ |
(0.54) |
(14) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.08 |
$ |
— |
* |
|||||
Gathering, compression, processing, and transportation |
$ |
1.29 |
$ |
1.33 |
$ |
0.04 |
3 |
% | ||||
Production and ad valorem taxes |
$ |
0.11 |
$ |
0.11 |
$ |
— |
* |
|||||
Marketing expense, net |
$ |
0.22 |
$ |
0.14 |
$ |
(0.08) |
(36) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.23 |
$ |
1.01 |
$ |
(0.22) |
(18) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.21 |
$ |
0.19 |
$ |
(0.02) |
(10) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
ANTERO RESOURCES CORPORATION | ||||||||||||
The following tables set forth selected operating data for the six months ended June 30, 2016 compared to the six months ended June 30, 2017: | ||||||||||||
Six Months Ended June 30, |
Amount of |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
484,563 |
$ |
920,921 |
$ |
436,358 |
90 |
% | ||||
NGLs sales |
167,778 |
365,471 |
197,693 |
118 |
% | |||||||
Oil sales |
26,919 |
53,472 |
26,553 |
99 |
% | |||||||
Gathering, compression, water handling and treatment |
7,138 |
5,796 |
(1,342) |
(19) |
% | |||||||
Marketing |
190,118 |
115,892 |
(74,226) |
(39) |
% | |||||||
Commodity derivative fair value gains (losses) |
(404,710) |
524,416 |
929,126 |
* |
||||||||
Total operating revenues and other |
471,806 |
1,985,968 |
1,514,162 |
321 |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
23,336 |
32,543 |
9,207 |
39 |
% | |||||||
Gathering, compression, processing, and transportation |
414,798 |
533,576 |
118,778 |
29 |
% | |||||||
Production and ad valorem taxes |
36,742 |
47,346 |
10,604 |
29 |
% | |||||||
Marketing |
263,910 |
167,414 |
(96,496) |
(37) |
% | |||||||
Exploration |
2,123 |
3,911 |
1,788 |
84 |
% | |||||||
Impairment of unproved properties |
35,470 |
42,098 |
6,628 |
19 |
% | |||||||
Depletion, depreciation, and amortization |
388,944 |
403,911 |
14,967 |
4 |
% | |||||||
Accretion of asset retirement obligations |
1,218 |
1,286 |
68 |
6 |
% | |||||||
General and administrative (before equity-based compensation) |
67,103 |
76,319 |
9,216 |
14 |
% | |||||||
Equity-based compensation |
49,286 |
52,478 |
3,192 |
6 |
% | |||||||
Total operating expenses |
1,282,930 |
1,360,882 |
77,952 |
6 |
% | |||||||
Operating income (loss) |
(811,124) |
625,086 |
1,436,210 |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliates |
484 |
5,854 |
5,370 |
1,110 |
% | |||||||
Interest expense |
(125,879) |
(135,252) |
(9,373) |
7 |
% | |||||||
Total other expenses |
(125,395) |
(129,398) |
(4,003) |
3 |
% | |||||||
Income (loss) before income taxes |
(936,519) |
495,688 |
1,432,207 |
* |
||||||||
Income tax (expense) benefit |
371,679 |
(150,165) |
(521,844) |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
(564,840) |
345,523 |
910,363 |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
36,459 |
82,259 |
45,800 |
126 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(601,299) |
$ |
263,264 |
$ |
864,563 |
* |
|||||
Adjusted EBITDAX (1) |
$ |
687,513 |
$ |
686,087 |
$ |
(1,426) |
* |
|||||
Production data: |
||||||||||||
Natural gas (Bcf) |
242 |
284 |
42 |
17 |
% | |||||||
C2 Ethane (MBbl) |
2,662 |
4,858 |
2,196 |
82 |
% | |||||||
C3+ NGLs (MBbl) |
9,452 |
12,159 |
2,707 |
29 |
% | |||||||
Oil (MBbl) |
949 |
1,256 |
307 |
32 |
% | |||||||
Combined (Bcfe) |
320 |
393 |
73 |
23 |
% | |||||||
Daily combined production (MMcfe/d) |
1,760 |
2,172 |
412 |
23 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.00 |
$ |
3.25 |
$ |
1.25 |
63 |
% | ||||
C2 Ethane (per Bbl) |
$ |
7.68 |
$ |
8.21 |
$ |
0.53 |
7 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
15.59 |
$ |
26.78 |
$ |
11.19 |
72 |
% | ||||
Oil (per Bbl) |
$ |
28.36 |
$ |
42.58 |
$ |
14.22 |
50 |
% | ||||
Combined (per Mcfe) |
$ |
2.12 |
$ |
3.41 |
$ |
1.29 |
61 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.42 |
$ |
3.71 |
$ |
(0.71) |
(16) |
% | ||||
C2 Ethane (per Bbl) |
$ |
7.68 |
$ |
8.67 |
$ |
0.99 |
13 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
18.93 |
$ |
21.92 |
$ |
2.99 |
16 |
% | ||||
Oil (per Bbl) |
$ |
28.36 |
$ |
44.61 |
$ |
16.25 |
57 |
% | ||||
Combined (per Mcfe) |
$ |
4.05 |
$ |
3.60 |
$ |
(0.45) |
(11) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.07 |
$ |
0.08 |
$ |
0.01 |
14 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.29 |
$ |
1.36 |
$ |
0.07 |
5 |
% | ||||
Production and ad valorem taxes |
$ |
0.11 |
$ |
0.12 |
$ |
0.01 |
9 |
% | ||||
Marketing expense, net |
$ |
0.23 |
$ |
0.13 |
$ |
(0.10) |
(43) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.22 |
$ |
1.03 |
$ |
(0.19) |
(16) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.21 |
$ |
0.19 |
$ |
(0.02) |
(10) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
View original content with multimedia:http://www.prnewswire.com/news-releases/antero-resources-reports-second-quarter-2017-financial-and-operational-results-and-increases-2017-production-guidance-300498708.html
SOURCE Antero Resources Corporation
DENVER, Aug. 2, 2017 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced estimated reserves as of June 30, 2017.
Highlights:
Antero's estimated proved reserves at June 30, 2017 were 16.5 Tcfe, a 7% increase compared to estimated proved reserves at December 31, 2016. Proved, probable and possible ("3P") reserves at mid-year 2017 totaled 53.0 Tcfe, which represents a 14% increase compared to year-end 2016. Proved and probable reserves comprise over 96% of the total 3P reserves.
Drill bit only finding and development cost, including revisions, was $0.47 per Mcfe for the first half of 2017. All-in finding and development cost for estimated proved reserve additions was $0.48 per Mcfe for mid-year 2017.
Paul Rady, Chairman and CEO, commented, "After announcing encouraging initial results for advanced completions in the Marcellus over the past year, our reserve engineers had the production history necessary to upgrade the type curve on almost 600 proved and probable undrilled locations from 1.7 previously to approximately 2.0 Bcf per 1,000' of lateral at mid-year 2017. Once processed, these rich gas locations deliver gas equivalent reserves of approximately 2.6 Bcfe per 1,000' of lateral assuming ethane rejection. As we expand our advanced completion footprint, we anticipate revising the type curve for a significant portion of our approximate 2,400 undeveloped locations that are still booked at 1.7 Bcf per 1,000' of lateral."
Antero's reserves at June 30, 2017 were prepared by the Company's internal reserve engineers and have not been reviewed or audited by its independent reserve engineers.
Estimated Proved Reserves
As of June 30, 2017, the Company's 16.5 Tcfe of estimated proved reserves were comprised of 59% natural gas, 40% NGLs and 1% oil. The Marcellus Shale accounted for 88% of estimated proved reserves and the Ohio Utica Shale accounted for 12%. For the first half of 2017, Antero added 1.3 Tcfe of estimated proved reserves through the drill bit, which is reflective of the continued productivity gains from the use of advanced completion techniques and longer laterals.
Included in the mid-year 2017 reserves are 294 proved undeveloped locations, or 83% of the total proved undeveloped locations in the Marcellus, booked at an approximate 2.0 Bcf/1,000' type curve. This includes an increase of 199 proved undeveloped locations that were previously booked at a 1.7 Bcf/1,000' type curve at year-end 2016 that have now been upgraded to an approximate 2.0 Bcf/1,000' type curve. The remaining 60 Marcellus proved undeveloped locations are booked at a 1.7 Bcf/1,000' type curve and are generally outside of areas where advanced completions have been applied.
Approximately 29% of Antero's combined 636,000 net acre leasehold position was classified as proved at June 30, 2017 which was in line with year-end 2016. Based on Antero's successful drilling results to date, as well as those of other operators in the vicinity of Antero's leasehold position, the Company believes that a substantial portion of its Marcellus and Ohio Utica Shale undeveloped acreage will be classified as proved over time as more wells are drilled. Virtually no West Virginia Upper Devonian or Utica locations were classified as 3P reserves at June 30, 2017, with the exception of four proved developed producing Upper Devonian locations and one proved developed producing Utica location, due to the early stage of drilling and production in the play.
Estimated proved developed reserves increased by 20% from year-end 2016 to 8.3 Tcfe at June 30, 2017. The Company added 76 Marcellus and 25 Ohio Utica wells to estimated proved developed reserves in the first half of 2017. The percentage of estimated proved reserves classified as proved developed increased to 50% at June 30, 2017 from 45% at year-end 2016. The average heating content of the Marcellus and Utica proved undeveloped locations is 1250 BTU and 1235 BTU, respectively, and the average lateral length is approximately 9,100 feet per location.
Under the Securities and Exchange Commission ("SEC") reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 888 Bcfe of proved undeveloped reserves to the probable category in the first half of 2017 to comply with the SEC five-year development rule. The proved undeveloped locations were reclassified primarily as a result of fewer wells being needed to meet production growth targets due to the enhanced productivity from advanced completions. Antero's 8.2 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.40 per Mcfe. The future development capital is based on a combination of current contracted rates and spot market rates based on today's market pricing.
Antero incurred estimated capital costs of approximately $939 million during the first half of 2017, including drilling and completion costs of $629 million, proved property acquisitions of $179 million and leasehold additions of $130 million. Assuming the $939 million of capital costs, mid-year 2017 all-in finding and development cost for proved reserve additions from all sources, including revisions, was $0.48 per Mcfe.
Summary of Changes in Estimated Proved Reserves (in Bcfe) |
||
Balance at December 31, 2016 |
15,386 | |
Extensions, discoveries and additions |
479 | |
Purchases of estimated proved reserves |
620 | |
Revisions(1) |
857 | |
Partial ethane recovery |
453 | |
Reclassification to probable due to SEC 5-year development rule |
(888) | |
Production |
(393) | |
Balance at June 30, 2017 |
16,514 | |
1) |
Revisions include 742 Bcfe of performance revisions as a result of the Company's advanced completions program and 115 Bcfe of price revisions. |
Costs Incurred ($ Millions) |
||
Proved leasehold acquisitions: |
$179 | |
Leasehold additions |
130 | |
Drilling and completion |
629 | |
Total costs incurred |
$939 | |
Finding and Development Costs ($/ Mcfe) |
||
All-in F&D cost for proved reserve additions(1) |
$0.48 | |
Drill bit only F&D cost(2) |
$0.47 | |
1) |
Total costs incurred divided by the summation of 479 Bcfe for extensions, discoveries and additions, 620 Bcfe for purchases and 857 Bcfe for revisions. |
2) |
Drilling and completion costs divided by the summation of 479 Bcfe for extensions, discoveries and additions and 857 Bcfe for revisions. |
The table below summarizes both SEC and strip pricing as of June 30, 2017 and the associated PV-10 for estimated proved reserves and hedge values:
2017 Mid-Year |
|||||||
Benchmark Pricing: |
SEC |
Strip |
Variance |
% | |||
WTI Oil Price ($/Bbl) |
$48.85 |
$52.06 |
$3.21 |
7% | |||
Appalachian Oil Price ($/Bbl)(2) |
$43.33 |
$48.05 |
$4.72 |
11% | |||
Nymex Natural Gas Price ($/MMBtu) |
$3.07 |
$3.00 |
$(0.07) |
(2)% | |||
Appalachian Natural Gas Price ($/MMBtu)(2) |
$2.88 |
$2.74 |
$(0.14) |
(5)% | |||
C3+ Natural Gas Liquids ($/Bbl) |
$26.68 |
$30.84 |
$4.14 |
16% | |||
C2+ Natural Gas Liquids ($/Bbl)(3) |
$16.40 |
$18.77 |
$2.37 |
14% | |||
Pre-Tax PV-10 Values ($ Billions): |
|||||||
Estimated proved reserves PV-10 |
$8.0 |
$8.4 |
$0.4 |
5% | |||
Hedge PV-10 (4) |
1.3 |
1.7 |
0.4 |
31% | |||
Total PV-10 |
$9.3 |
$10.1 |
$0.8 |
9% |
1) |
Strip pricing as of June 30, 2017 for each of the first ten years and flat thereafter. |
2) |
Represents SEC and strip prices as of June 30, 2017 on a weighted average Appalachian index basis related to company-specific sales points. |
3) |
Represents realized NGL price including regional market differentials. |
4) |
Hedge PV-10 at strip pricing differs from mid-year 2017 mark-to-market value of $2.0 billion due to the application of a higher discount rate. |
Assuming SEC prices, the pre-tax present value discounted at 10% ("pre-tax PV-10") of the June 30, 2017 estimated proved reserves was $8.0 billion, a 117% increase from year-end 2016. Including Antero's hedges as of June 30, 2017 and assuming SEC prices, the pre-tax PV-10 value of estimated proved reserves was $9.3 billion, which represents a 39% increase from year-end 2016 pre-tax PV-10 values. The GAAP standardized measure is based on SEC pricing, after tax, and does not include hedge values. For further discussion on pre-tax PV-10 values, please read "Non-GAAP Disclosure."
Assuming future strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing as of June 30, 2017, the pre-tax PV-10 value of the same mid-year 2017 estimated proved reserves was $8.4 billion. This represents a 5% increase over the corresponding SEC reserve based pre-tax PV-10, before hedges. Including Antero's hedges, the pre-tax PV-10 value of estimated proved reserves was $10.1 billion assuming strip pricing, a 3% increase compared to year-end 2016.
Assuming SEC prices, the pre-tax PV-10 of the June 30, 2017 estimated proved developed reserves was $5.4 billion, which represents an 86% increase compared to year-end 2016.
Assuming future strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing as of June 30, 2017, the pre-tax PV-10 value of the estimated proved developed reserves was $5.5 billion, a 2% increase over the corresponding SEC reserve based pre-tax PV-10, before hedges, and an 8% increase compared to year-end 2016.
Proved, Probable and Possible Reserves
Antero estimates that it had mid-year 2017 3P reserves of 53.0 Tcfe, a 14% increase from year-end 2016. The 14% increase in 3P reserves was driven by a combination of increased type curves in certain areas driven by continued productivity gains from advanced completions, first-half 2017 leasehold acquisitions and an increase in ethane recovery. Approximately 69 million and 954 million barrels of ethane are accounted for as natural gas rather than liquids in proved and 3P reserves as of June 30, 2017, respectively, as this ethane is assumed to remain in the natural gas stream until such time as pricing supports full ethane recovery. As of June 30, 2017, the Company's 53.0 Tcfe of 3P reserves were comprised of 71% natural gas, 28% NGLs and 1% oil. The Marcellus and Ohio Utica Shale comprised 45.7 Tcfe and 7.3 Tcfe of the 3P reserves, respectively.
Importantly, 44.0 Tcfe of Antero's 45.7 Tcfe, or 96% of estimated 3P reserves in the Marcellus were classified as proved and probable reserves ("2P"), reflecting the low risk and statistically repeatable nature of Antero's Marcellus drilling. The 44.0 Tcfe of 2P reserves includes 398 probable locations that were increased from the 1.7 Bcf/1,000' type curve to the approximate 2.0 Bcf/1,000' type curve. Further, 6.9 Tcfe of Antero's 7.2 Tcfe, or 96% of estimated 3P reserves in the Ohio Utica were classified as 2P.
The tables below summarize Antero's estimated 3P reserve volumes as of June 30, 2017 using SEC pricing, categorized by operating area as well as PV-10 values of Antero's 3P reserve volumes using both SEC and strip pricing:
Marcellus Shale |
Ohio Utica Shale |
||||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
||||||||||||||||
Proved |
8,219 |
1,065 |
14,609 |
972 |
1,518 |
65 |
1,905 |
264 |
|||||||||||||||
Probable |
21,673 |
1,289 |
29,408 |
2,795 |
4,387 |
94 |
4,950 |
608 |
|||||||||||||||
Possible |
1,390 |
56 |
1,727 |
222 |
316 |
6 |
353 |
59 |
|||||||||||||||
Total 3P |
31,282 |
2,410 |
45,744 |
3,989 |
6,221 |
165 |
7,208 |
931 |
|||||||||||||||
% Liquids(1) |
32% |
14% |
|||||||||||||||||||||
Combined 3P Reserves |
|||||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
||||||||||||||||||||
Proved(2) |
9,737 |
1,130 |
16,514 |
1,236 |
|||||||||||||||||||
Probable |
26,059 |
1,383 |
34,358 |
3,403 |
|||||||||||||||||||
Possible |
1,706 |
62 |
2,080 |
281 |
|||||||||||||||||||
Total 3P |
37,502 |
2,575 |
52,952 |
4,920 |
|||||||||||||||||||
% Liquids(1) |
29% |
||||||||||||||||||||||
1) |
Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 1,170 million barrels of ethane, 1,279 million barrels of C3+ NGLs and 126 million barrels of oil | ||||||||||||||||||||||
2) |
437 of the 1,236 proved locations were undeveloped locations | ||||||||||||||||||||||
Pre-Tax 3P PV-10 Values ($ Billion): |
SEC Pricing |
Strip Pricing(1) |
Variance |
% Variance |
|||||||||||||||||||
3P Reserves PV-10 |
$13.3 |
$15.3 |
$2.0 |
15% |
|||||||||||||||||||
Hedge PV-10 (2) |
1.3 |
1.7 |
0.4 |
31% |
|||||||||||||||||||
Total PV-10 |
$14.6 |
$17.0 |
$2.4 |
16% |
|||||||||||||||||||
1) |
Strip pricing as of June 30, 2017 for each of the first ten years and flat thereafter. | ||||||||||||||||||||||
2) |
Hedge PV-10 at strip pricing differs from mid-year 2017 mark-to-market value of $2.0 billion due to the application of a higher discount rate. |
Assuming SEC prices, the pre-tax PV-10 of the June 30, 2017 3P reserves was $13.3 billion before hedges and $14.6 billion including hedges. Assuming mid-year 2017 future strip pricing, with adjustments similar to SEC pricing, the pre-tax PV-10 of the same year-end 2016 3P reserves was $15.3 billion which represents a 15% increase over the corresponding SEC reserve based pre-tax PV-10, before hedges. Including Antero's hedges, the pre-tax PV-10 value of estimated 3P reserves was $17.0 billion assuming strip pricing, a 2% increase compared to year-end 2016. For further discussion on pre-tax PV-10 values, please read "Non-GAAP Disclosure."
Non-GAAP Disclosure
Certain selected financial information in this release is unaudited. Additional unaudited financial information will be provided in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, which the Company intends to file with the SEC on August 2, 2017. In this release, Antero has provided a number of unaudited metrics, which include all-in finding and development cost per unit and drill bit only finding and development cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The finding and development costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the finding and development costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies.
Calculations for all-in and drill bit only finding and development cost per unit are based on estimated and unaudited costs incurred in the first half of 2017 and can be found in the footnotes to the table on page two of this release. The calculations for both all-in and drill bit only finding and development cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Pre-tax PV-10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV-10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV-10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV-10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.
Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measure employed by other companies.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future development costs, future capital spending plans, expected drilling and development plans, plans with respect to the rejection of ethane and the prices we will receive for future production as well as future production volumes are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2016 and any subsequently filed Quarterly Report on Form 10-Q.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have not been audited by its third party reserve engineer in this release. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
This release provides a summary of Antero's reserves as of June 30, 2017, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
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SOURCE Antero Resources Corporation
DENVER, July 18, 2017 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its second quarter 2017 earnings release on Wednesday, August 2, 2017 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, August 3, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources." A telephone replay of the call will be available until Friday, August 11, 2017 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10108841.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, August 11, 2017 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources Corporation
DENVER, May 8, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its first quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, which has been filed with the Securities and Exchange Commission.
First Quarter Highlights Include:
Recent Developments
Borrowing Base Reaffirmed at $4.75 Billion
As a result of the recent spring borrowing base redetermination, the borrowing base under Antero's upstream credit facility was reaffirmed at $4.75 billion. Lender commitments under the facility remain at $4.0 billion. The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo, N.A., is currently comprised of 29 banks.
Natural Gas Firm Transportation Update
In February 2017, Energy Transfer Partners, L.P. ("Energy Transfer") received FERC approval to proceed with the construction of the Rover Pipeline ("Rover"). Energy Transfer has confirmed its plans to place Rover into service in the third quarter of 2017, with Phases 1 and 2 expected to come on line in July 2017 and November 2017, respectively. Antero is an anchor shipper on Rover with an 800,000 MMBtu/d firm commitment. The pipeline will connect Antero's Marcellus and Utica Shale assets to the Midwest and Gulf Coast via additional downstream firm transportation already in service. The project will also enable Antero to transport natural gas both from the Seneca (via Phase 1) and Sherwood (via Phase 2) Processing Facilities, allowing for maximum optionality on its firm transportation portfolio, and further strengthens the Company's ability to deliver on its long-term production targets through 2020.
NGL Infrastructure Update
In February 2017, Sunoco Logistics Partners LP ("Sunoco") began construction on the Mariner East 2 pipeline project after receiving the necessary permits from the Pennsylvania Department of Environmental Protection. The pipeline will transport NGLs from Southwestern Pennsylvania and Eastern Ohio to the Marcus Hook terminal and export facility near Philadelphia, Pennsylvania. Antero is an anchor shipper on Mariner East 2 with a 61,500 barrel per day commitment (11,500 barrels of ethane, 35,000 barrels of propane and 15,000 barrels of butane). The pipeline is expected to be placed into service in the fourth quarter of 2017. Antero is forecasting a C3+ NGL price realization improvement once Mariner East 2 is placed into service as the Company will have the ability to export ethane, propane and butane to international markets.
Firm Processing Update
Antero Resources recently committed to plants 8 through 11 at the Sherwood Facility and they are expected to be placed into service over the next 12 to 18 months. These four 200 MMcf/d plants at the Sherwood Processing Facility, in addition to Sherwood 7, will be owned by the recently formed joint venture between Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") and MarkWest Energy Partners, L.P. ("MarkWest"), a wholly owned subsidiary of MPLX, L.P. Plants 8 through 11 are expected to be placed into service in the third quarter of 2017, first quarter of 2018, third quarter of 2018 and fourth quarter of 2018, respectively. Plant 7 was placed into service in February of 2017.
First Quarter 2017 Financial and Operating Results
As of March 31, 2017, Antero owned a 59% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated with Antero's results.
For the three months ended March 31, 2017, the Company reported net income of $268 million, or $0.85 per basic and diluted share, compared to a net loss of $5 million, or $(0.02) per basic and diluted share, in the first quarter of 2016. Net income for the first quarter of 2017 included the following items:
Excluding the items detailed above, the Company's results for the first quarter of 2017 were as follows:
For a description of adjusted net income and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the first quarter of 2017 averaged 2,144 MMcfe/d, including 99,119 Bbl/d of liquids (28% liquids). First quarter 2017 production represents an organic production growth rate of 22% from the first quarter of 2016 and an 8% increase compared to the fourth quarter of 2016. First quarter 2017 C3+ natural gas liquids ("NGLs") and oil production averaged 66,313 Bbl/d and 7,140 Bbl/d, respectively. Ethane (C2) production averaged 25,666 Bbl/d while leaving approximately 68,000 Bbl/d of ethane in the natural gas stream. Total liquids production for the first quarter of 2017 represents an organic production growth rate of 45% and 14% as compared to the first quarter of 2016 and fourth quarter of 2016, respectively.
Antero's average natural gas price before hedging increased 61% from the prior year quarter to $3.35 per Mcf, a $0.03 per Mcf premium to the average Nymex natural gas price for the period. Virtually all of Antero's first quarter 2017 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex. Antero's average realized natural gas price after hedging for the first quarter of 2017 was $3.89 per Mcf, a $0.57 premium to the Nymex average natural gas price for the period, and a 14% decrease compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $75 million, or $0.54 per Mcf compared to $302 million, or $2.46 per Mcf in the prior year quarter.
The Company's average realized C3+ NGL price before hedging for the first quarter of 2017 was $29.52 per barrel, or 57% of the average Nymex WTI oil price, which represents a 110% increase as compared to the prior year quarter. The improvement in C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing combined with an improvement in local differentials. Antero's average realized C3+ NGL price including hedges was $24.01 per barrel, a 27% increase compared to the first quarter of 2016. The Company's average realized ethane price before hedging for the first quarter of 2017 was $0.19 per gallon, or $8.00 per barrel. Antero's average realized ethane price including hedges for the first quarter of 2017 was $0.21 per gallon, or $8.73 per barrel. The average realized oil price before hedging was $41.96 per barrel, a $9.81 differential to Nymex WTI and a 95% increase as compared to the first quarter of 2016. Antero's average realized oil price including hedges was $43.17 per barrel, an $8.60 differential to Nymex WTI for the period.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by 69% to $3.57 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 8% to $3.80 per Mcfe compared to the prior year quarter. For the first quarter of 2017, Antero realized a total cash settled hedge gain on all products of $45 million, or $0.23 per Mcfe.
Commenting on NGL price improvements and the outlook on liquids production, Glen Warren, President and CFO, said, "NGL price realizations for the quarter were strong, as we were able to achieve a pre-hedge C3+ NGL price of 57% of the average Nymex WTI oil price, which is above the high end of our recently increased 2017 NGL price guidance range of 50% to 55%. The uptick in liquids pricing compliments our market leading liquids-rich inventory in Appalachia and further highlights the momentum we have established through increased liquids production and forward-looking approach to capitalize on the NGL infrastructure buildout in the Northeast. Looking ahead, we expect this momentum to continue as Antero Midstream's recently announced joint venture with MarkWest combined with the expected startup of Mariner East 2 pipeline later this year provides tremendous visibility around getting our NGLs to market at favorable pricing."
Total operating revenue for the first quarter of 2017 was $1.2 billion as compared to $721 million for the first quarter of 2016. Operating revenue for the first quarter of 2017 included a $394 million non-cash gain on unsettled hedges, while the first quarter of 2016 included a $44 million non-cash loss on unsettled hedges. During the first quarter of 2017, the non-cash gain on unsettled hedges was driven by a decrease in natural gas futures pricing. Revenue excluding the unrealized hedge gain was $802 million, a 5% increase compared to the first quarter of 2016. Liquids production contributed 32% of total product revenues before hedges in the first quarter of 2017, as compared to a 25% contribution for the prior year quarter. For a reconciliation of revenue excluding unrealized hedge gains to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the first quarter of 2017 was $66 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the first quarter of 2017 was $90 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $24 million, or $0.12 per Mcfe, for the first quarter of 2017, representing a 50%, or $0.12 per Mcfe decrease from the first quarter of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the first quarter of 2017 was $1.59 per Mcfe, a 7% increase compared to $1.49 per Mcfe in the prior year quarter. The increase is primarily due to increased utilization of a long haul pipeline which has higher per unit transportation costs as compared to our transportation portfolio average. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.38 per Mcfe for gathering, compression, processing and transportation costs and $0.13 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the first quarter of 2017, excluding non-cash equity-based compensation expense was $0.20 per Mcfe, a 5% decrease from the first quarter of 2016, driven by the increase in production. Per unit depreciation, depletion and amortization expense decreased 13% from the prior year quarter to $1.05 per Mcfe, primarily driven by increases in Antero's estimated recoverable reserves as well as decreases in its per unit development costs.
Adjusted EBITDAX of $365 million for the first quarter of 2017 represents a 3% increase compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $1.89 per Mcfe, representing a 15% decrease from the prior year quarter, driven primarily by a reduction in gains on settled derivatives. For the first quarter of 2017, cash flow from operations was $394 million, a 16% increase from the prior year quarter. Cash flow from operations before changes in working capital was $297 million, a 2% increase from the first quarter of 2016.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended March 31, 2017:
Three Months Ended March 31, 2017 | ||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Net Production |
1,550 |
7,140 |
66,313 |
25,666 |
2,144 | |||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Realized Prices |
||||||||||||||
Average realized price before settled derivatives |
$ |
3.35 |
$ |
41.96 |
$ |
29.52 |
$ 8.00 |
$ |
3.57 | |||||
Settled derivatives |
0.54 |
1.21 |
(5.51) |
0.73 |
0.23 | |||||||||
Average realized price after settled derivatives |
$ |
3.89 |
$ |
43.17 |
$ |
24.01 |
$ 8.73 |
$ |
3.80 | |||||
Nymex average price |
$ |
3.32 |
$ |
51.77 |
$ |
3.32 | ||||||||
Premium / (Differential) to Nymex |
$ |
0.57 |
$ |
(8.60) |
$ |
0.48 | ||||||||
Marcellus Shale — Antero completed and placed on line 25 horizontal Marcellus wells during the first quarter of 2017 with an average lateral length of 8,850 feet. All 25 wells completed in the first quarter of 2017 have been on line for more than 30 days and had an average 30-day rate on choke of 18.6 MMcfe/d while rejecting ethane (21% liquids).
Current average well costs are $0.87 million per 1,000 feet of lateral in the Marcellus, which represents a 29% reduction from 2015 and in line with the fourth quarter of 2016. In the Marcellus, average drilling days from spud to final rig release declined to 12 days in the first quarter of 2017, a 49% reduction from 2015 and an 18% reduction from 2016. Antero is currently operating four drilling rigs and five completion crews in the Marcellus Shale.
One notable Marcellus pad that was completed late in the fourth quarter of 2016 had 4 wells with an average lateral length of 10,017 feet, an average BTU content of 1227 and an average of 1,700 pounds of proppant per foot. The average EUR for this pad is 2.4 Bcf/1,000 at the wellhead and 2.9 Bcfe/1,000' processed (ethane rejection). This pad had an all-in development cost of $0.39 per Mcfe, driving attractive rates of return.
Ohio Utica Shale — Antero did not complete and place on line any wells during the quarter while managing Utica development ahead of the anticipated Rover in service date. However, the Company drilled an average of 2,757 feet per day in its laterals while drilling and casing 13 wells during the quarter. Antero is currently operating three drilling rigs and one completion crew in the Utica Shale. The Company has plans to move one of these rigs to the Marcellus Shale in the second quarter of 2017.
Current average well costs are $1.01 million per 1,000 feet of lateral in the Utica, which represents a 26% reduction from 2015 and in line with the fourth quarter of 2016. Drilling days from spud to final rig release averaged 18 days in the Utica in the first quarter of 2017.
Commenting on the continued operational momentum and Antero's integrated business strategy, Paul Rady, Chairman and CEO said, "We continue to see increases in well productivity through the utilization of our advanced completion techniques while keeping drilling and completion costs down. We have seen encouraging early results in the Marcellus with completions yielding wellhead EURs in the 2.0 to 2.4 Bcf/1,000' range. Importantly, some of the early results are outside of our current high graded core areas and could lead to an extension of those areas. The continued operational momentum compliments Antero's integrated business strategy which includes best quality rock, firm transport to favorable price indices, an industry leading hedge book, significant exposure to liquids pricing upside and value created by infrastructure buildout through our 59% ownership in Antero Midstream. This high level of operational performance and integration gives us confidence in our ability to achieve our 2017 production growth guidance as well as our production growth targets through 2020."
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the first quarter of 2017 averaged 1,659 MMcf/d, a 26% increase from the first quarter of 2016 and a 9% increase sequentially. Compression volumes for the first quarter of 2017 averaged 1,028 MMcf/d, a 68% increase from the first quarter of 2016 and a 12% increase sequentially. High pressure gathering volumes for the first quarter of 2017 averaged 1,581 MMcf/d, a 28% increase from the first quarter of 2016 and a 12% increase sequentially. The increase in gathering and compression volumes was driven by production growth from Antero Resources in Antero Midstream's area of dedication. Fresh water delivery volumes averaged 148 MBbl/d during the quarter, a 51% increase compared to the prior year quarter and a 1% decrease sequentially.
For the three months ended March 31, 2017, the Partnership reported revenues of $175 million, comprised of $92 million from the Gathering and Processing segment and $83 million from the Water Handling and Treatment segment. Revenues increased 28% compared to the prior year quarter, primarily driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $33 million from produced water handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $8 million and $40 million, respectively, for a total of $48 million compared to $49 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $32 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the first quarter of 2016. General and administrative expenses excluding equity-based compensation were $8 million during the first quarter of 2017, a 15% increase compared to the first quarter of 2016. The increase in general and administrative expenses was primarily driven by non-recurring expenses incurred from the processing and fractionation joint venture with MarkWest. Total operating expenses were $93 million, including $28 million of depreciation and $4 million of accretion of contingent acquisition consideration.
The Board of Directors of the general partner of the Partnership declared a cash distribution of $0.30 per unit ($1.20 per unit annualized) for the first quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 7% increase sequentially. The distribution is the Partnership's ninth consecutive quarterly distribution increase since its initial public offering in November 2014 and will be paid on May 10, 2017 to unitholders of record as of May 3, 2017.
Balance Sheet and Liquidity
As of March 31, 2017, Antero's consolidated net debt was $4.8 billion, of which $720 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two facilities is currently $5.5 billion. Reduced for $710 million in letters of credit outstanding, the company had $4.1 billion in available consolidated liquidity as of March 31, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
First Quarter 2017 Capital Spending
Antero's drilling and completion costs for the three months ended March 31, 2017 were $307 million. In addition, the Company invested $56 million for land and $50 million for proved property acquisitions. Antero Midstream invested $67 million for gathering and compression systems, $37 million for water infrastructure projects, including $19 million on the Antero Clearwater Treatment Facility and $160 million in the recently announced processing and fractionation joint venture with MarkWest.
Hedge Position
Antero currently has hedged 3.3 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from April 1, 2017 through December 31, 2023 at an average index price of $3.61 per MMBtu. At March 31, 2017, the Company's estimated fair value of commodity derivative instruments was $2.0 billion.
The following table summarizes Antero's hedge position as of March 31, 2017:
Period |
Natural Gas |
Average |
Liquids |
Average | ||
2Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.26 |
— |
— | ||
CGTLA |
420,000 |
$4.13 |
— |
— | ||
Chicago |
70,000 |
$4.38 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.38 | ||
Ethane MB ($/Gall) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
3Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.33 |
— |
— | ||
CGTLA |
420,000 |
$4.20 |
— |
— | ||
Chicago |
70,000 |
$4.45 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.39 | ||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
4Q 2017: |
||||||
Nymex Henry Hub |
1,370,000 |
$3.46 |
— |
— | ||
CGTLA |
420,000 |
$4.37 |
— |
— | ||
Chicago |
70,000 |
$4.68 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.40 | ||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | ||
2017 Total |
1,860,000 |
$3.59 |
50,500 |
N/A (1) | ||
2018: |
||||||
Nymex Henry Hub |
2,002,500 |
$3.91 |
— |
— | ||
Propane MB ($/Gal) |
— |
— |
2,000 |
$0.65 | ||
2019 Nymex Henry Hub |
2,330,000 |
$3.70 |
— |
— | ||
2020 Nymex Henry Hub |
1,417,500 |
$3.63 |
— |
— | ||
2021 Nymex Henry Hub |
710,000 |
$3.31 |
— |
— | ||
2022 Nymex Henry Hub |
810,000 |
$3.18 |
— |
— | ||
2023 Nymex Henry Hub |
50,000 |
$2.83 |
— |
— | ||
(1) |
Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges. |
Conference Call
A conference call is scheduled on Tuesday, May 9, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Wednesday, May 17, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10103993.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, May 17, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the May 9, 2017 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge gains as set forth in this release represents total operating revenue adjusted for non-cash gains on unsettled hedges. Antero believes that revenue excluding unrealized hedge gains is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (in thousands):
Three months ended |
|||||||
2016 |
2017 |
||||||
Total operating revenue |
$ |
721,004 |
$ |
1,195,579 |
|||
Commodity derivative fair value gains |
(279,924) |
(438,775) |
|||||
Cash receipts for settled hedges |
324,347 |
44,849 |
|||||
Revenue excluding unrealized hedge gains |
$ |
765,427 |
$ |
801,653 |
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (in thousands):
Three months ended |
|||||||
March 31, |
|||||||
2016 |
2017 |
||||||
Net income (loss) |
$ |
(5,055) |
$ |
268,396 |
|||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
44,423 |
(393,926) |
|||||
Impairment of unproved properties |
15,526 |
26,899 |
|||||
Equity-based compensation |
23,470 |
25,503 |
|||||
Income tax effect of reconciling items |
(31,273) |
129,225 |
|||||
Adjusted net income |
$ |
47,091 |
$ |
56,097 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended |
|||||||
2016 |
2017 |
||||||
Net cash provided by operating activities |
$ |
340,168 |
$ |
393,939 |
|||
Net change in working capital |
(48,830) |
(97,337) |
|||||
Cash flow from operations before changes in working capital |
$ |
291,338 |
$ |
296,602 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, |
March 31, | ||||||
2016 |
2017 | ||||||
Bank credit facilities |
$ |
650,000 |
$ |
720,000 | |||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||||
5.375% AM senior notes due 2024 |
650,000 |
650,000 | |||||
5.000% AR senior notes due 2025 |
600,000 |
600,000 | |||||
Net unamortized premium |
1,749 |
1,721 | |||||
Net unamortized debt issuance costs |
(47,776) |
(46,419) | |||||
Consolidated total debt |
$ |
4,703,973 |
$ |
4,775,302 | |||
Less: Cash and cash equivalents |
31,610 |
— | |||||
Consolidated net debt |
$ |
4,672,363 |
$ |
4,775,302 | |||
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
Three months ended |
||||||||||||||
March 31, |
||||||||||||||
2016 |
2017 |
|||||||||||||
Net income from continuing operations including noncontrolling interest |
$ |
10,650 |
$ |
305,558 |
||||||||||
Commodity derivative fair value gains |
(279,924) |
(438,775) |
||||||||||||
Gains on settled derivative instruments |
324,347 |
44,849 |
||||||||||||
Interest expense |
63,284 |
66,670 |
||||||||||||
Income tax expense |
4,815 |
131,346 |
||||||||||||
Depreciation, depletion, amortization, and accretion |
192,180 |
203,366 |
||||||||||||
Impairment of unproved properties |
15,526 |
26,899 |
||||||||||||
Exploration expense |
1,014 |
2,107 |
||||||||||||
Equity-based compensation expense |
23,470 |
25,503 |
||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
(2,231) |
||||||||||||
State franchise taxes |
39 |
— |
||||||||||||
Total adjusted EBITDAX |
355,401 |
365,292 |
||||||||||||
Interest expense |
(63,284) |
(66,670) |
||||||||||||
Exploration expense |
(1,014) |
(2,107) |
||||||||||||
Changes in current assets and liabilities |
48,830 |
97,337 |
||||||||||||
State franchise taxes |
(39) |
— |
||||||||||||
Other non-cash items |
274 |
87 |
||||||||||||
Net cash provided by operating activities |
$ |
340,168 |
$ |
393,939 |
||||||||||
Three months ended |
||||||||||||||
March 31, |
||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2016 |
2017 |
||||||||||||
Realized price before cash receipts for settled hedges |
$ |
2.11 |
$ |
3.57 |
||||||||||
Gathering, compression, and water handling and treatment revenues |
0.02 |
— |
||||||||||||
Lease operating expense |
(0.07) |
(0.08) |
||||||||||||
Gathering, compression, processing and transportation costs |
(1.30) |
(1.38) |
||||||||||||
Marketing, net |
(0.24) |
(0.12) |
||||||||||||
Production and ad valorem taxes |
(0.12) |
(0.13) |
||||||||||||
General and administrative(1) |
(0.21) |
(0.20) |
||||||||||||
Adjusted EBITDAX margin before settled hedges |
0.19 |
1.66 |
||||||||||||
Cash receipts for settled hedges |
2.03 |
0.23 |
||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.22 |
$ |
1.89 |
(1) Excludes equity-based stock compensation that is included in G&A | ||||||
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2016.
ANTERO RESOURCES CORPORATION Condensed Consolidated Balance Sheets December 31, 2016 and March 31, 2017 (unaudited) (In thousands, except per share amounts) |
|||||||
December 31, 2016 |
March 31, 2017 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
31,610 |
— |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2016 and 2017 |
29,682 |
36,874 |
|||||
Accrued revenue |
261,960 |
220,059 |
|||||
Derivative instruments |
73,022 |
237,086 |
|||||
Other current assets |
6,313 |
9,679 |
|||||
Total current assets |
402,587 |
503,698 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
2,331,173 |
2,330,010 |
|||||
Proved properties |
9,549,671 |
9,942,450 |
|||||
Water handling and treatment systems |
744,682 |
771,239 |
|||||
Gathering systems and facilities |
1,723,768 |
1,785,669 |
|||||
Other property and equipment |
41,231 |
42,290 |
|||||
14,390,525 |
14,871,658 |
||||||
Less accumulated depletion, depreciation, and amortization |
(2,363,778) |
(2,566,359) |
|||||
Property and equipment, net |
12,026,747 |
12,305,299 |
|||||
Derivative instruments |
1,731,063 |
1,811,435 |
|||||
Investments in unconsolidated affiliates |
68,299 |
230,418 |
|||||
Other assets |
26,854 |
37,804 |
|||||
Total assets |
$ |
14,255,550 |
14,888,654 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
38,627 |
37,706 |
||||
Accrued liabilities |
393,803 |
416,588 |
|||||
Revenue distributions payable |
163,989 |
198,775 |
|||||
Derivative instruments |
203,635 |
54,277 |
|||||
Other current liabilities |
17,334 |
16,090 |
|||||
Total current liabilities |
817,388 |
723,436 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,703,973 |
4,775,302 |
|||||
Deferred income tax liability |
950,217 |
1,081,563 |
|||||
Derivative instruments |
234 |
102 |
|||||
Other liabilities |
55,160 |
54,299 |
|||||
Total liabilities |
6,526,972 |
6,634,702 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 314,877 shares and 315,006 shares, respectively |
3,149 |
3,150 |
|||||
Additional paid-in capital |
5,299,481 |
6,407,158 |
|||||
Accumulated earnings |
959,995 |
1,228,391 |
|||||
Total stockholders' equity |
6,262,625 |
7,638,699 |
|||||
Noncontrolling interest in consolidated subsidiary |
1,465,953 |
615,253 |
|||||
Total equity |
7,728,578 |
8,253,952 |
|||||
Total liabilities and equity |
$ |
14,255,550 |
14,888,654 |
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Operations and Comprehensive Income Three Months Ended March 31, 2016 and 2017 (unaudited) (In thousands, except per share amounts) | |||||||||||||||
Three Months Ended March 31, |
|||||||||||||||
2016 |
2017 |
||||||||||||||
Revenue: |
|||||||||||||||
Natural gas sales |
$ |
254,776 |
466,664 |
||||||||||||
Natural gas liquids sales |
73,065 |
194,652 |
|||||||||||||
Oil sales |
10,179 |
26,960 |
|||||||||||||
Gathering, compression, and water handling and treatment |
3,844 |
2,604 |
|||||||||||||
Marketing |
99,216 |
65,924 |
|||||||||||||
Commodity derivative fair value gains |
279,924 |
438,775 |
|||||||||||||
Total revenue |
721,004 |
1,195,579 |
|||||||||||||
Operating expenses: |
|||||||||||||||
Lease operating |
11,293 |
15,551 |
|||||||||||||
Gathering, compression, processing, and transportation |
208,738 |
266,829 |
|||||||||||||
Production and ad valorem taxes |
19,284 |
24,793 |
|||||||||||||
Marketing |
137,933 |
89,993 |
|||||||||||||
Exploration |
1,014 |
2,107 |
|||||||||||||
Impairment of unproved properties |
15,526 |
26,899 |
|||||||||||||
Depletion, depreciation, and amortization |
191,582 |
202,729 |
|||||||||||||
Accretion of asset retirement obligations |
598 |
637 |
|||||||||||||
General and administrative (including equity-based compensation expense of $23,470 and $25,503 in 2016 and 2017, respectively) |
56,287 |
64,698 |
|||||||||||||
Total operating expenses |
642,255 |
694,236 |
|||||||||||||
Operating income |
78,749 |
501,343 |
|||||||||||||
Other income (expenses): |
|||||||||||||||
Equity in earnings of unconsolidated affiliates |
— |
2,231 |
|||||||||||||
Interest |
(63,284) |
(66,670) |
|||||||||||||
Total other expenses |
(63,284) |
(64,439) |
|||||||||||||
Income before income taxes |
15,465 |
436,904 |
|||||||||||||
Provision for income tax expense |
(4,815) |
(131,346) |
|||||||||||||
Net income and comprehensive income including noncontrolling interest |
10,650 |
305,558 |
|||||||||||||
Net income and comprehensive income attributable to noncontrolling interest |
15,705 |
37,162 |
|||||||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(5,055) |
268,396 |
||||||||||||
Earnings (loss) per common share—basic |
$ |
(0.02) |
0.85 |
||||||||||||
Earnings (loss) per common share—assuming dilution |
$ |
(0.02) |
0.85 |
||||||||||||
Weighted average number of shares outstanding: |
|||||||||||||||
Basic |
277,050 |
314,954 |
|||||||||||||
Diluted |
277,050 |
315,769 |
|||||||||||||
ANTERO RESOURCES CORPORATION Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 2016 and 2017 (unaudited) (In thousands) |
||||||||
Three Months Ended March 31, |
||||||||
2016 |
2017 |
|||||||
Cash flows from operating activities: |
||||||||
Net income including noncontrolling interest |
$ |
10,650 |
305,558 |
|||||
Adjustment to reconcile net income to net cash provided by operating activities: |
||||||||
Depletion, depreciation, amortization, and accretion |
192,180 |
203,366 |
||||||
Impairment of unproved properties |
15,526 |
26,899 |
||||||
Derivative fair value gains |
(279,924) |
(438,775) |
||||||
Gains on settled derivatives |
324,347 |
44,849 |
||||||
Deferred income tax expense |
4,815 |
131,346 |
||||||
Equity-based compensation expense |
23,470 |
25,503 |
||||||
Equity in earnings of unconsolidated affiliates |
— |
(2,231) |
||||||
Other |
274 |
87 |
||||||
Changes in current assets and liabilities: |
||||||||
Accounts receivable |
651 |
(7,192) |
||||||
Accrued revenue |
(8,204) |
41,901 |
||||||
Other current assets |
15 |
(3,366) |
||||||
Accounts payable |
4,387 |
12,545 |
||||||
Accrued liabilities |
49,041 |
19,339 |
||||||
Revenue distributions payable |
2,969 |
34,786 |
||||||
Other current liabilities |
(29) |
(676) |
||||||
Net cash provided by operating activities |
340,168 |
393,939 |
||||||
Cash flows used in investing activities: |
||||||||
Additions to proved properties |
— |
(49,664) |
||||||
Additions to unproved properties |
(28,675) |
(55,542) |
||||||
Drilling and completion costs |
(395,185) |
(306,925) |
||||||
Additions to water handling and treatment systems |
(37,036) |
(36,954) |
||||||
Additions to gathering systems and facilities |
(48,686) |
(66,559) |
||||||
Additions to other property and equipment |
(541) |
(590) |
||||||
Investment in unconsolidated affiliate |
— |
(159,889) |
||||||
Change in other assets |
(9,172) |
(12,350) |
||||||
Net cash used in investing activities |
(519,295) |
(688,473) |
||||||
Cash flows from financing activities: |
||||||||
Issuance of common units by Antero Midstream Partners LP |
— |
223,119 |
||||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
178,000 |
— |
||||||
Borrowings on bank credit facilities, net |
33,000 |
70,000 |
||||||
Payments of deferred financing costs |
(64) |
— |
||||||
Distributions to noncontrolling interest in consolidated subsidiary |
(14,013) |
(27,149) |
||||||
Employee tax withholding for settlement of equity compensation awards |
(117) |
(1,657) |
||||||
Other |
(1,282) |
(1,389) |
||||||
Net cash provided by financing activities |
195,524 |
262,924 |
||||||
Net increase (decrease) in cash and cash equivalents |
16,397 |
(31,610) |
||||||
Cash and cash equivalents, beginning of period |
23,473 |
31,610 |
||||||
Cash and cash equivalents, end of period |
$ |
39,870 |
— |
|||||
Supplemental disclosure of cash flow information: |
||||||||
Cash paid during the period for interest |
$ |
14,350 |
35,770 |
|||||
Supplemental disclosure of noncash investing activities: |
||||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
$ |
(119,191) |
(10,020) |
|||||
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended March 31, 2016 compared to the three months ended March 31, 2017:
Three Months Ended March 31, |
Amount of |
Percent |
||||||||||
(in thousands) |
2016 |
2017 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
254,776 |
$ |
466,664 |
$ |
211,888 |
83 |
% | ||||
NGLs sales |
73,065 |
194,652 |
121,587 |
166 |
% | |||||||
Oil sales |
10,179 |
26,960 |
16,781 |
165 |
% | |||||||
Gathering, compression, and water handling and treatment |
3,844 |
2,604 |
(1,240) |
(32) |
% | |||||||
Marketing |
99,216 |
65,924 |
(33,292) |
(34) |
% | |||||||
Commodity derivative fair value gains |
279,924 |
438,775 |
158,851 |
57 |
% | |||||||
Total operating revenues and other |
721,004 |
1,195,579 |
474,575 |
66 |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
11,293 |
15,551 |
4,258 |
38 |
% | |||||||
Gathering, compression, processing, and transportation |
208,738 |
266,829 |
58,091 |
28 |
% | |||||||
Production and ad valorem taxes |
19,284 |
24,793 |
5,509 |
29 |
% | |||||||
Marketing |
137,933 |
89,993 |
(47,940) |
(35) |
% | |||||||
Exploration |
1,014 |
2,107 |
1,093 |
108 |
% | |||||||
Impairment of unproved properties |
15,526 |
26,899 |
11,373 |
73 |
% | |||||||
Depletion, depreciation, and amortization |
191,582 |
202,729 |
11,147 |
6 |
% | |||||||
Accretion of asset retirement obligations |
598 |
637 |
39 |
7 |
% | |||||||
General and administrative (before equity-based compensation) |
32,817 |
39,195 |
6,378 |
19 |
% | |||||||
Equity-based compensation |
23,470 |
25,503 |
2,033 |
9 |
% | |||||||
Total operating expenses |
642,255 |
694,236 |
51,981 |
8 |
% | |||||||
Operating income |
78,749 |
501,343 |
422,594 |
537 |
% | |||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliates |
— |
2,231 |
2,231 |
* |
||||||||
Interest expense |
(63,284) |
(66,670) |
(3,386) |
5 |
% | |||||||
Total other expenses |
(63,284) |
(64,439) |
(1,155) |
2 |
% | |||||||
Income before income taxes |
15,465 |
436,904 |
421,439 |
2,725 |
% | |||||||
Income tax expense |
(4,815) |
(131,346) |
(126,531) |
2,628 |
% | |||||||
Net income and comprehensive income including noncontrolling interest |
10,650 |
305,558 |
294,908 |
2,769 |
% | |||||||
Net income and comprehensive income attributable to noncontrolling interest |
15,705 |
37,162 |
21,457 |
137 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(5,055) |
$ |
268,396 |
$ |
273,451 |
* |
|||||
Adjusted EBITDAX (1) |
$ |
355,401 |
$ |
365,292 |
$ |
9,891 |
3 |
% | ||||
Three Months Ended March 31, |
Amount of |
Percent |
||||||||||
2016 |
2017 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
123 |
139 |
16 |
14 |
% | |||||||
C2 Ethane (MBbl) |
1,081 |
2,310 |
1,229 |
114 |
% | |||||||
C3+ NGLs (MBbl) |
4,681 |
5,968 |
1,287 |
27 |
% | |||||||
Oil (MBbl) |
472 |
643 |
171 |
36 |
% | |||||||
Combined (Bcfe) |
160 |
193 |
33 |
21 |
% | |||||||
Daily combined production (MMcfe/d) |
1,758 |
2,144 |
386 |
22 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.08 |
$ |
3.35 |
$ |
1.27 |
61 |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.68 |
$ |
8.00 |
$ |
1.32 |
20 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
14.07 |
$ |
29.52 |
$ |
15.45 |
110 |
% | ||||
Oil (per Bbl) |
$ |
21.56 |
$ |
41.96 |
$ |
20.40 |
95 |
% | ||||
Combined (per Mcfe) |
$ |
2.11 |
$ |
3.57 |
$ |
1.46 |
69 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.54 |
$ |
3.89 |
$ |
(0.65) |
(14) |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.68 |
$ |
8.73 |
$ |
2.05 |
31 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
18.88 |
$ |
24.01 |
$ |
5.13 |
27 |
% | ||||
Oil (per Bbl) |
$ |
21.56 |
$ |
43.17 |
$ |
21.61 |
100 |
% | ||||
Combined (per Mcfe) |
$ |
4.14 |
$ |
3.80 |
$ |
(0.34) |
(8) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.07 |
$ |
0.08 |
$ |
0.01 |
14 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.30 |
$ |
1.38 |
$ |
0.08 |
6 |
% | ||||
Production and ad valorem taxes |
$ |
0.12 |
$ |
0.13 |
$ |
0.01 |
8 |
% | ||||
Marketing, net |
$ |
0.24 |
$ |
0.12 |
$ |
(0.12) |
(50) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.20 |
$ |
1.05 |
$ |
(0.15) |
(13) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.21 |
$ |
0.20 |
$ |
(0.01) |
(5) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
SOURCE Antero Resources Corporation
DENVER, April 24, 2017 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its first quarter 2017 earnings release on Monday, May 8, 2017 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Tuesday, May 9, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Wednesday, May 17, 2017 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10103993.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Wednesday, May 17, 2017 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
SOURCE Antero Resources
DENVER, Feb. 28, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its fourth quarter and full-year 2016 financial and operating results. The relevant financial statements are included in Antero's Annual Report on Form 10-K for the year ended December 31, 2016, which has been filed with the Securities and Exchange Commission ("SEC").
Fourth Quarter Highlights Include:
Full Year 2016 Highlights Include:
Recent Developments
Increased 2017 NGL Pricing Guidance and NGL Infrastructure Update
Driven by the recent strength in Mont Belvieu prices and regional demand in the Northeast, Antero has increased its 2017 C3+ natural gas liquids ("NGL") price realization guidance before hedging to 50% to 55% of WTI oil prices, up from previous guidance of 45% to 50% of WTI. Importantly, the updated 2017 NGL price realization guidance does not include the anticipated positive effect of the Mariner East 2 pipeline project described below.
On February 13, 2017, the Pennsylvania Department of Environmental Protection issued permits for Sunoco Logistics Partners LP's ("Sunoco") Mariner East 2 pipeline project, which enables Sunoco to begin construction on the 350-mile NGL pipeline. The pipeline will transport NGLs from Southwestern Pennsylvania and Eastern Ohio to the Marcus Hook terminal and export facility near Philadelphia, Pennsylvania, which is also owned by Sunoco. As previously announced, Antero is an anchor shipper on Mariner East 2 with a 61,500 barrels per day commitment (35,000 barrels of propane / 15,000 barrels of butane / 11,500 barrels of ethane). The pipeline is expected to be placed into service by the end of the third quarter of 2017.
On February 6, 2017, Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") announced the formation of a joint venture (the "Joint Venture") to develop processing and fractionation assets in Appalachia with MarkWest Energy Partners, L.P., a wholly owned subsidiary of MPLX, LP. The Joint Venture will develop cryogenic processing assets at the Sherwood Processing Facility in Doddridge County, West Virginia, and also at an additional site still to be designated, also located in West Virginia, to support Antero's continued liquids-rich production growth in the southwestern core of the Marcellus Shale. The Joint Venture participation will begin with the next three 200 MMcf/d plants at the Sherwood Processing Facility (Plants 7, 8 and 9), which are under development and scheduled to be placed into service during the first quarter of 2017, third quarter of 2017, and first quarter of 2018. In addition, Antero Resources recently committed to Plant 10 at the Sherwood facility, which is expected to be placed into service in the third quarter of 2018. The Joint Venture will also own C3+ fractionation capacity at the Hopedale complex in Harrison County, Ohio supported by Antero and other third party producers and will have the option to participate in incremental fractionation capacity to be built in the future as needed.
Natural Gas Firm Transportation Update
In early February 2017, Energy Transfer Partners, L.P. ("Energy Transfer") received FERC approval to proceed with the construction of the Rover Pipeline. Antero is an anchor shipper on the Rover Pipeline with an 800,000 MMBtu/d firm commitment. The pipeline will connect Antero's Marcellus and Utica Shale assets to the Midwest and Gulf Coast via additional downstream firm transportation that Antero already holds. The project will also enable Antero to transport natural gas both from the Sherwood and Seneca processing facilities, allowing for maximum optionality on its firm transportation portfolio. Energy Transfer plans to place the Rover Pipeline into service in the third quarter of 2017.
Year-End 2016 Proved and 3P Reserves
On February 1, 2017, Antero announced that estimated proved reserves at year-end 2016 were 15.4 Tcfe, a 16% increase compared to estimated proved reserves at December 31, 2015. All-in finding and development cost for proved reserve additions was $0.52 per Mcfe. This finding and development cost includes drilling and completion capital as well as costs incurred for well pads, roads, certain production facilities, acquisitions, land additions and gives effect to performance and price revisions. Drill bit only finding and development cost for proved reserve additions was $0.39 per Mcfe. Proved developed reserves increased by 18% from year-end 2015 to 6.9 Tcfe at December 31, 2016. Additionally, the percentage of proved reserves classified as proved developed increased to 45% at December 31, 2016.
The Company's proved, probable and possible ("3P") reserves at year-end 2016 totaled 46.4 Tcfe, which represents a 25% increase compared to the previous year. Antero's Marcellus and Utica 3P drilling inventory totaled 3,630 locations at year-end 2016 with an average lateral length of 8,250', of which approximately 81% were in the Marcellus.
Fourth Quarter 2016 Financial and Operating Results
As of December 31, 2016, pro forma for Antero Midstream's common unit offering in February 2017, Antero owned a 59% limited partner interest in Antero Midstream Partners. Antero Midstream's results are consolidated with Antero's results.
For the three months ended December 31, 2016, the Company reported a net loss of $486 million, or $(1.55) per basic share and diluted share, compared to net income of $158 million, or $0.57 per basic and diluted share, in the fourth quarter of 2015. Net loss for the fourth quarter of 2016 included the following items:
Excluding the items detailed above, the Company's results for the fourth quarter of 2016 were as follows:
For a description of adjusted net income and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the fourth quarter of 2016 averaged 1,990 MMcfe/d, including 86,857 Bbl/d of liquids (26% liquids). Fourth quarter 2016 production represents an organic production growth rate of 33% from the fourth quarter of 2015 and a 6% increase compared to the third quarter of 2016. Fourth quarter 2016 C3+ NGL and oil production averaged 60,405 Bbl/d and 5,439 Bbl/d, respectively. Recovered ethane (C2) production averaged 21,013 Bbl/d, while leaving approximately 66,000 Bbl/d of ethane in the natural gas stream. Total liquids production for the fourth quarter of 2016 represents an organic production growth rate of 59% and 7% from the fourth quarter of 2015 and third quarter of 2016, respectively.
Antero's average natural gas price before hedging increased 43% from the prior year quarter to $3.05 per Mcf, a $0.07 per Mcf premium to the average Nymex price for the period. Virtually all of Antero's fourth quarter 2016 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex. Antero's average realized natural gas price after hedging for the fourth quarter of 2016 was $4.43 per Mcf, a $1.45 premium to the Nymex average price for the period, which was consistent with the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $187 million, or $1.38 per Mcf.
The Company's average realized C3+ NGL price before hedging for the fourth quarter of 2016 was $25.22 per barrel, or 51% of the average Nymex WTI oil price, which represents a 45% increase as compared to the prior year quarter. Antero's average realized C3+ NGL price including hedges was $25.60 per barrel, a 17% increase compared to the fourth quarter of 2015. Antero's average realized ethane price for the fourth quarter of 2016 was $0.22 per gallon, or $9.36 per barrel. The average realized oil price before hedging was $39.18 per barrel, a $9.96 differential to average Nymex WTI and a 37% increase as compared to the fourth quarter of 2015.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by 39% to $3.22 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, was $4.26 per Mcfe which was in line with the prior year quarter. For the fourth quarter of 2016, Antero realized a total cash settled hedge gain on all products of $190 million, or $1.04 per Mcfe.
Commenting on liquids pricing and exposure, Glen Warren, President and CFO, said, "During the fourth quarter, Antero was the largest producer of C3+ natural gas liquids in Appalachia and realized a C3+ natural gas liquids price before hedging of $25.22, which was 51% of the average Nymex WTI oil price and 45% higher than the prior year quarter. This realization was also well above the top of our full year NGL pricing guidance range of 35% to 40% of WTI. When this improvement in NGL pricing outlook is combined with our continued growth in liquids production and the buildout of the Mariner East 2 project, we believe we have the most powerful NGL story in the Northeast."
Total operating revenue for the fourth quarter of 2016 was $156 million as compared to $905 million for the fourth quarter of 2015. Operating revenue for the fourth quarter of 2016 included an $829 million non-cash loss on unsettled hedges and a $98 million gain on the sale of assets, while the fourth quarter of 2015 included a $275 million non-cash gain on unsettled hedges. Revenue excluding the unrealized hedge loss and gain on the sale of assets was $888 million, a 41% increase compared to the fourth quarter of 2015. Liquids production contributed 30% of total product revenues before hedges in the fourth quarter of 2016, as compared to a 28% contribution for the prior year quarter. For a reconciliation of revenue excluding unrealized hedge gain (loss) and gain on sale of assets to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the fourth quarter of 2016 was $106 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the fourth quarter of 2016 was $121 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $15 million, or $0.08 per Mcfe, for the fourth quarter of 2016, representing a 79%, or $0.30 per Mcfe decrease from the fourth quarter of 2015. The significant decrease in net marketing expense from the prior year quarter is primarily attributable to a third party contractual commitment that commenced on July 1, 2016, in which Antero released certain unutilized firm transportation capacity and the costs associated with the unutilized capacity. Additionally, Antero's marketed volumes increased year-over-year and the Company generated a higher spread on its marketed volumes due to wider local northeast indices relative to the end market indices reached through Antero's firm transportation capacity.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem tax) for the fourth quarter of 2016 was $1.42 per Mcfe, a 3% decrease compared to $1.46 per Mcfe in the prior year quarter. The per unit cash production expense for the quarter included $0.07 per Mcfe for lease operating costs, $1.27 per Mcfe for gathering, compression, processing and transportation costs and $0.08 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the fourth quarter of 2016, excluding non-cash equity-based compensation expense, was $0.21 per Mcfe, a 22% decrease from the fourth quarter of 2015. The significant per unit decrease in general and administrative expenses was primarily driven by the increase in production while overall general and administrative expense remained relatively flat. Per unit depreciation, depletion and amortization expense increased 3% from the prior year quarter to $1.22 per Mcfe, primarily due to an increase in the total drilling and completion costs subject to depletion.
Adjusted EBITDAX of $476 million for the fourth quarter of 2016 represents a 55% increase compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $2.60 per Mcfe, representing a 16% increase from the prior year quarter. For the fourth quarter of 2016, cash flow from operations before changes in working capital was $404 million, a 69% increase from the prior year quarter and well in excess of drilling and completion capital expenditures of $318 million.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended December 31, 2016:
Three Months Ended | ||||||||||||||
Gas (MMcf/d) |
Oil |
C3+ NGLs |
Ethane (Bbl/d) |
Combined | ||||||||||
Average Net Production |
1,469 |
5,439 |
60,405 |
21,013 |
1,990 | |||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs |
Ethane ($/Bbl) |
Combined | |||||||||
Average realized price before settled derivatives |
$ |
3.05 |
$ |
39.18 |
$ |
25.22 |
$ |
9.36 |
$ |
3.22 | ||||
Settled derivatives |
1.38 |
¾ – |
0.38 |
¾ |
1.04 | |||||||||
Average realized price after settled derivatives |
$ |
4.43 |
$ |
39.18 |
$ |
25.60 |
$ |
9.36 |
$ |
4.26 | ||||
Nymex average price |
$ |
2.98 |
$ |
49.14 |
$ |
2.98 | ||||||||
Premium / (Differential) to Nymex |
$ |
1.45 |
$ |
(9.96) |
$ |
1.28 |
Marcellus Shale — Antero completed and placed on line 33 horizontal Marcellus wells during the fourth quarter of 2016 with an average lateral length of 9,900 feet. During the quarter, Antero drilled an average of 4,100 feet per day in its laterals while drilling and casing 29 wells. The Company's contracted completion crews averaged four stages per day in the Marcellus. All 33 wells completed in the fourth quarter of 2016 have been on line for more than 30 days and had an average 30-day rate of 18.8 MMcfe/d while rejecting ethane (26% liquids). In 2016, Antero completed 88 wells that have an average EUR of 21.5 Bcfe assuming ethane rejection, an average Btu of 1245 and an average lateral length of 9,200 feet. Approximately 80% of the 88 wells completed in 2016 in the Marcellus utilized advanced completion techniques. The Company is currently operating three drilling rigs and five completion crews in the Marcellus Shale play.
Current average well costs are $0.84 million per 1,000 feet of lateral in the Marcellus, which represents a 29% reduction from 2015 and a 2% reduction from the third quarter of 2016. The reduction in average well costs is primarily driven by continuing operational efficiencies. In the Marcellus, average drilling days from spud to final rig release declined to 12 days in the fourth quarter of 2016, a 50% reduction from 2015 and a 14% reduction from the third quarter of 2016.
One notable Marcellus pad that was completed in the fourth quarter had ten wells with an average lateral length of 10,500 feet and was completed with 1,750 pounds of proppant per foot. The average EUR for this pad is 2.1 Bcf/1,000 at the wellhead and 2.6 Bcfe/1,000' processed (ethane rejection), and the combined 30-day rate for the 10-well pad was 200 MMcfe/d, including 7,800 Bbl/d of C3+ NGLs and 2,300 Bbl/d of oil. The average cost per well on the pad was $7.9 million, or $0.75 million per 1,000 feet of lateral. This pad had an all-in development cost of $0.36 per Mcfe and is expected to deliver a cash on cash payout of 1.7 years. Antero plans to average nine wells per pad in the Marcellus in 2017.
Ohio Utica Shale — Antero completed and placed on line ten horizontal Ohio Utica wells during the fourth quarter of 2016 with an average lateral length of 8,600 feet. During the quarter, Antero drilled on average of 2,850 feet per day in its laterals while drilling and casing six wells during the quarter. The Company's contracted completion crews averaged six stages per day in the Utica, a record for the Company. All ten of the wells completed in the fourth quarter of 2016 have been on line for more than 30 days and had an average restricted 30-day rate of 17.5 MMcfe/d while rejecting ethane (26% liquids). Antero is currently operating three drilling rigs and one completion crew in the Utica Shale play.
Current average well costs are $0.99 million per 1,000 feet of lateral in the Utica, which represents a 27% reduction from 2015 and a 2% reduction from the third quarter of 2016. The reduction in average well costs is primarily driven by lower service costs and continued operational efficiencies. Drilling days from spud to final rig release declined to 13 days in the Utica in the fourth quarter of 2016, a 58% reduction from 2015.
The one Utica pad that was completed in the fourth quarter had ten wells with an average lateral length of 8,600 feet. The combined 30-day rate for the 10-well pad, was 178 MMcfe/d, flowing at a constrained rate, including 5,800 Bbl/d of C3+ NGLs and 1,400 Bbl/d of oil. The average cost per well on the pad was $8.4 million, or $0.97 million per 1,000 feet of lateral. Antero plans to average six wells per pad in the Utica in 2017 and plans to utilize existing pads for a portion of the planned wells.
Commenting on Antero's 2016 results and future development plan, Paul Rady, Chairman of the Board and CEO said, "In 2016, through strategic acreage consolidation, we increased our extensive core drilling inventory to over 3,400 locations. From 2017 through 2020, we are targeting the completion of just over 800 of these core locations, or less than 25% of our overall core inventory. This provides us with significant visibility around our long-term growth plans. Looking ahead, we are well positioned to achieve our production guidance of 20% to 25% in 2017 and our production targets of 20% to 22%, on a compounded annual basis through 2020. Importantly, the significant operational improvements resulting in increased EUR's and lower well costs now position us to achieve this production growth while driving down leverage and spending within operating cash flow."
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the fourth quarter of 2016 averaged 1,522 MMcf/d, a 35% increase from the fourth quarter of 2015 and a 6% increase sequentially from the third quarter of 2016. Compression volumes for the fourth quarter of 2016 averaged 920 MMcf/d, a 92% increase from the fourth quarter of 2015 and an 18% increase sequentially. High pressure gathering volumes for the fourth quarter of 2016 averaged 1,437 MMcf/d, a 20% increase from the fourth quarter of 2015 and a 6% increase sequentially. The increase in throughput volumes was driven by Antero's production growth in Antero Midstream's area of dedication. Fresh water delivery volumes averaged 149,682 Bbl/d during the quarter, a 25% increase compared to the prior year quarter and a 7% increase sequentially. The increase in volumes was driven by an increase in wells serviced by the fresh water delivery system and higher water intensity advanced completions.
For the three months ended December 31, 2016, Antero Midstream reported revenues of $167 million, comprised of $88 million from the Gathering and Processing segment and $79 million from the Water Handling and Treatment segment. Revenues increased 27% compared to the prior year quarter, primarily driven by growth in natural gas throughput volumes and fresh water delivery volumes. Gathering and Processing revenues included a $4 million gain on asset sale related to the divestiture of certain gathering and compression assets in Pennsylvania during the quarter. Water Handling and Treatment segment revenues include $28 million from fluid handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $8 million and $29 million, respectively, for a total of $37 million compared to $40 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $27 million from fluid handling and high rate water transfer services. The decrease in direct operating expenses was driven primarily by a reduction in fluid handling and high rate transfer expenses. General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the fourth quarter of 2015. General and administrative expenses excluding equity-based compensation were $8 million during the fourth quarter of 2016, in line with the fourth quarter of 2015. Total operating expenses were $83 million, including $26 million of depreciation, $7 million of equity-based compensation, and $6 million of accretion of contingent acquisition consideration.
The Board of Directors of Antero Resources Midstream Management LLC, the general partner of the Partnership, declared a cash distribution of $0.28 per unit ($1.12 per unit annualized) for the fourth quarter of 2016. The distribution represents a 27% increase compared to the prior year quarter and a 6% increase sequentially. The distribution is the Partnership's eighth consecutive quarterly distribution increase since its initial public offering in November 2014 and was paid on February 8, 2017 to unitholders of record as of February 1, 2017. Upon payment of this distribution, the 75,940,957 subordinated units owned by Antero Resources were converted into common units on a one-for-one basis under the terms of the Partnership agreement.
Fourth Quarter 2016 Capital Spending
Antero's drilling and completion capital expenditures for the three months ended December 31, 2016 were $318 million. In addition, the Company invested $47 million for land, excluding $74 million for leasehold and proved property acquisitions. Antero Midstream invested $77 million for gathering and compression systems and $51 million for water infrastructure projects, including $36 million for the Antero Clearwater Treatment Facility.
2016 Financial Results
Antero's net daily production for 2016 averaged 1,847 MMcfe/d, which was 3% above the previously increased 2016 guidance and included 78,002 Bbl/d of liquids (25%). Full year 2016 production represents an organic growth rate of 24% from the prior year. Full year 2016 C3+ NGL and oil production averaged 55,408 Bbl/d and 5,118 Bbl/d, which were 4% and 14% above 2016 guidance, respectively. Ethane (C2) production averaged 17,476 Bbl/d. Total liquids production for 2016 represents an organic growth rate of 62% over 2015 liquids production.
Antero's average natural gas price before hedging increased 5% from the prior year to $2.50 per Mcf, a $0.04 per Mcf premium to the average Nymex price for the period and at the high end of 2016 guidance of a $0.00 per Mcf to $0.05 per Mcf premium to Nymex. Approximately 99% of Antero's 2016 natural gas production was priced at favorable indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex. Antero's average realized natural gas price after hedging for 2016 was $4.39 per Mcf, a $1.93 premium to the Nymex average price for the period, which was a 6% increase as compared to 2015. During the year, Antero realized a cash settled natural gas hedge gain of $957 million, or $1.90 per Mcf.
The Company's average realized C3+ NGL price before hedging for 2016 was $18.74 per barrel, or 43% of the average Nymex WTI oil price, which represents a 9% increase as compared to the prior year and exceeds the 2016 guidance of 35% to 40% of WTI. Antero's realized C3+ NGL price including hedges was $21.03 per barrel, which was in line with 2015. Antero's average realized ethane price in 2016 was $0.20 per gallon, or $8.28 per barrel, a 34% increase as compared to the prior year. Antero's average realized oil price before hedging was $32.73 per barrel, a $10.42 differential to average Nymex WTI and a 4% decrease as compared to the prior year.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased 3% from the prior year to $2.60 per Mcfe, despite an 8% and 11% decrease in average Nymex Henry Hub natural gas and average Nymex WTI oil prices, respectively. The increase in natural gas equivalent price was driven by improved realized natural gas and NGL prices as a result of Antero selling at more favorably priced indices and contracting for a portion of its NGL production at tighter differentials to Mont Belvieu. Antero's average natural gas-equivalent price including NGLs, oil and hedge settlements was in line with the prior year at $4.08 per Mcfe. For 2016, Antero realized a total cash settled hedge gain on all products of $1.0 billion, or $1.48 per Mcfe.
Total operating revenue for 2016 was $1.7 billion as compared to $4.0 billion for the prior year. Operating revenue for 2016 included a $1.5 billion non-cash loss on unsettled hedges and a $98 million gain on the sale of assets, while 2015 included a $1.5 billion non-cash gain on unsettled hedges. For 2016, revenue excluding the unrealized hedge gain (loss) and gain on the sale of assets was $3.2 billion, a 30% increase compared to 2015. Liquids production contributed 28% of total product revenues before hedges in 2016, compared to 24% during 2015. For a reconciliation of revenue excluding the unrealized hedge loss and gain on sale of assets to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for 2016 was $393 million. Antero's marketing revenue was primarily associated with the sale of third-party gas purchased to utilize the Company's excess firm transportation capacity on the Rockies Express Pipeline, Columbia Gas Pipeline and Tennessee Gas Pipeline. Marketing expense for 2016 was $499 million. The largest components of marketing expense include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs. Net marketing expense for 2016 was $106 million, or $0.16 per Mcfe, which was at the low end of the Company's 2016 guidance of $0.15 to $0.20 per Mcfe.
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and ad valorem tax) for 2016 was $1.48 per Mcfe which is a 4% increase compared to $1.42 per Mcfe in the prior year and at the high end of 2016 guidance of $1.40 to $1.50 per Mcfe. The per unit cash production expense for 2016 included $0.07 per Mcfe for lease operating costs, $1.31 per Mcfe for gathering, compression and transportation costs and $0.10 per Mcfe for production and ad valorem taxes. The increase from the prior year was primarily due to higher transportation costs associated with Antero's increasing firm transportation, which in turn enabled the Company to sell its gas at more favorably priced indices. Per unit general and administrative expense for 2016, excluding non-cash equity based compensation expense, was $0.20 per Mcfe, a 20% decrease from 2015 and at the low end of Antero's 2016 guidance of $0.20 to $0.22 per Mcfe. The decrease was primarily driven by the significant increase in net production. Per unit depreciation, depletion and amortization expense decreased by 8% to $1.20 per Mcfe compared to 2015.
The Company reported a net loss from continuing operations attributable to common stockholders of $849 million (($2.88) per basic and diluted share) for 2016, including:
Excluding these items, the Company's results for 2016 were as follows:
Adjusted EBITDAX margin for 2016 was $2.27 per Mcfe, which was 1% higher than the prior year. For 2016, cash flow from operations before changes in working capital was $1.3 billion, 31% higher than the prior year, in line with drilling and completion capital expenditures of $1.3 billion.
For a description of Adjusted EBITDAX and EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income from continuing operations attributable to common stockholders and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
2016 Capital Spending
Antero's drilling and completion capital expenditures for the year ended December 31, 2016 were $1.3 billion, in line with guidance and a 21% decrease compared to the prior year. In addition, the Company invested $153 million for land, excluding $593 million for leasehold and proved property acquisitions. Antero Midstream invested $231 million for gathering and compression systems and $188 million for water infrastructure projects, including $149 million for the Antero Clearwater Treatment Facility.
Balance Sheet and Liquidity
As of December 31, 2016, Antero's consolidated net debt was $4.7 billion, of which $650 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two facilities is currently $5.4 billion(1). After deducting $710 million in letters of credit outstanding to support pipeline commitments, the Company had $4.0 billion in available consolidated liquidity as of December 31, 2016. At year-end, the Company's net debt to trailing twelve months adjusted EBITDAX ratio was 3.0-times. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures." For a description of adjusted EBITDAX to its nearest comparable GAAP measure, please read "Non-GAAP Financial Measures."
1. |
Liquidity calculation assumes Antero Midstream's borrowings under its credit facility limited to EBITDA covenant of 5.0x LTM EBITDA, less Senior Note Issuances as of December 31, 2016. |
Hedge Position
The Company's estimated natural gas production for 2017 is fully hedged at an average index price of $3.63 per MMBtu. Antero's target natural gas production for 2018 is also fully hedged at an average index price of $3.91 per MMBtu. Antero has hedged 3.4 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from January 1, 2017 through December 31, 2022 at an average index price of $3.63 per MMBtu. At December 31, 2016, the Company's estimated fair value of commodity derivative instruments was $1.6 billion.
The following table summarizes Antero's hedge position as of December 31, 2016:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | |||
1Q 2017: |
|||||||
Nymex Henry Hub |
1,370,000 |
$3.52 |
— |
— | |||
CGTLA |
420,000 |
$4.39 |
— |
— | |||
Chicago |
70,000 |
$4.76 |
— |
— | |||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.40 | |||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | |||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | |||
2Q 2017: |
|||||||
Nymex Henry Hub |
1,370,000 |
$3.26 |
— |
— | |||
CGTLA |
420,000 |
$4.13 |
— |
— | |||
Chicago |
70,000 |
$4.38 |
— |
— | |||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.38 | |||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | |||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | |||
3Q 2017: |
|||||||
Nymex Henry Hub |
1,370,000 |
$3.33 |
— |
— | |||
CGTLA |
420,000 |
$4.20 |
— |
— | |||
Chicago |
70,000 |
$4.45 |
— |
— | |||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.39 | |||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | |||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | |||
4Q 2017: |
|||||||
Nymex Henry Hub |
1,370,000 |
$3.46 |
— |
— | |||
CGTLA |
420,000 |
$4.37 |
— |
— | |||
Chicago |
70,000 |
$4.68 |
— |
— | |||
Propane MB ($/Gal) |
— |
— |
27,500 |
$0.40 | |||
Ethane MB ($/Gal) |
— |
— |
20,000 |
$0.25 | |||
Nymex WTI ($/Bbl) |
— |
— |
3,000 |
$54.75 | |||
2017 Total |
1,860,000 |
$3.63 |
50,500 |
N/A (1) | |||
2018: |
|||||||
Nymex Henry Hub |
2,002,500 |
$3.91 |
— |
— | |||
Propane MB ($/Gal) |
— |
— |
2,000 |
$0.65 | |||
2019: |
|||||||
Nymex Henry Hub |
2,330,000 |
$3.70 |
— |
— | |||
2020: |
|||||||
Nymex Henry Hub |
1,367,500 |
$3.66 |
— |
— | |||
2021: |
|||||||
Nymex Henry Hub |
660,000 |
$3.35 |
— |
— | |||
2022: |
|||||||
Nymex Henry Hub |
760,000 |
$3.20 |
— |
— | |||
(1) |
Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges. |
Conference Call
A conference call is scheduled on Wednesday, March 1, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, March 10, 2017 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10098004.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, March 10, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the March 1, 2017 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets as set forth in this release represents total operating revenue adjusted for non-cash gains (losses) on unsettled hedges and gain on sale of assets. Antero believes that revenue excluding unrealized hedge gains (losses) and gain on sale of assets is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains (losses) and gain on sale of assets is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (losses) and gain on sale of assets (in thousands):
Three months ended |
Years ended December 31, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Total operating revenue |
$ |
905,122 |
$ |
156,216 |
$ |
3,954,858 |
$ |
1,744,525 | ||||
Commodity derivative fair value (gains) losses |
(545,103) |
639,805 |
(2,381,501) |
514,181 | ||||||||
Cash receipts for settled hedges |
269,933 |
189,524 |
856,572 |
1,003,083 | ||||||||
Gain on sale of assets |
— |
(97,635) |
— |
(97,635) | ||||||||
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets |
$ |
629,952 |
$ |
887,910 |
$ |
2,429,929 |
$ |
3,164,154 |
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (in thousands):
Three months ended |
Years ended | |||||||||||
December 31, |
December 31, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Net income (loss) |
$ |
158,464 |
$ |
(485,772) |
$ |
941,364 |
$ |
(848,816) | ||||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
(275,170) |
829,329 |
(1,524,929) |
1,517,264 | ||||||||
Impairment of unproved properties |
60,651 |
115,712 |
104,321 |
162,935 | ||||||||
Equity-based compensation |
18,597 |
26,754 |
97,877 |
102,421 | ||||||||
Loss on early extinguishment of debt |
— |
16,956 |
— |
16,956 | ||||||||
Gain on sale of assets |
— |
(97,635) |
— |
(97,635) | ||||||||
Contract termination and rig stacking |
27,629 |
— |
38,531 |
— | ||||||||
Income tax effect of reconciling items |
63,938 |
(337,179) |
495,215 |
(643,977) | ||||||||
Adjusted net income |
$ |
54,109 |
$ |
68,165 |
$ |
152,379 |
$ |
209,148 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended |
Years ended December 31, | ||||||||||||||
2015 |
2016 |
2015 |
2016 | ||||||||||||
Net cash provided by operating activities |
$ |
174,658 |
$ |
335,559 |
$ |
1,015,812 |
$ |
1,241,256 | |||||||
Net change in working capital |
63,965 |
68,859 |
(39,498) |
32,920 | |||||||||||
Cash flow from operations before changes in working capital |
238,623 |
404,418 |
976,314 |
1,274,176 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, |
December 31, | ||||||
2015 |
2016 | ||||||
Bank credit facilities |
$ |
1,327,000 |
$ |
650,000 | |||
6.00% AR senior notes due 2020 |
525,000 |
— | |||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||||
5.375% AM senior notes due 2024 |
— |
650,000 | |||||
5.000% AR senior notes due 2025 |
— |
600,000 | |||||
Net unamortized premium |
6,513 |
1,749 | |||||
Net unamortized debt issuance costs |
(39,731) |
(47,776) | |||||
Consolidated total debt |
$ |
4,668,782 |
$ |
4,703,973 | |||
Less: Cash and cash equivalents |
23,473 |
31,610 | |||||
Consolidated net debt |
$ |
4,645,309 |
$ |
4,672,363 |
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income (loss) from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
Three months ended |
Years ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2016 |
2015 |
2016 | ||||||||
Net income (loss) from continuing operations including noncontrolling interest |
$ |
175,574 |
$ |
(452,804) |
$ |
979,996 |
$ |
(749,448) | |||
Commodity derivative fair value (gains) |
(545,103) |
639,805 |
(2,381,501) |
514,181 | |||||||
Gains on settled derivative instruments |
269,933 |
189,524 |
856,572 |
1,003,083 | |||||||
Gain on sale of assets |
— |
(97,635) |
— |
(97,635) | |||||||
Interest expense |
60,471 |
67,918 |
234,400 |
253,552 | |||||||
Loss on early extinguishment of debt |
— |
16,956 |
— |
16,956 | |||||||
Income tax expense (benefit) |
77,181 |
(265,621) |
575,890 |
(496,376) | |||||||
Depreciation, depletion, amortization, and accretion |
162,178 |
222,443 |
711,418 |
812,346 | |||||||
Impairment of unproved properties |
60,651 |
115,712 |
104,321 |
162,935 | |||||||
Exploration expense |
760 |
3,573 |
3,846 |
6,862 | |||||||
Equity-based compensation expense |
18,597 |
26,754 |
97,877 |
102,421 | |||||||
Equity in loss (earnings) of unconsolidated affiliate |
— |
1,542 |
— |
(485) | |||||||
Distributions from unconsolidated affiliate |
— |
7,702 |
— |
7,702 | |||||||
State franchise taxes |
(59) |
11 |
72 |
50 | |||||||
Contract termination and rig stacking |
27,629 |
— |
38,531 |
— | |||||||
Total Adjusted EBITDAX |
307,812 |
475,880 |
1,221,422 |
1,536,144 | |||||||
Interest expense |
(60,471) |
(67,918) |
(234,400) |
(253,552) | |||||||
Exploration expense |
(760) |
(3,573) |
(3,846) |
(6,862) | |||||||
Changes in current assets and liabilities |
(63,965) |
(68,859) |
39,498 |
(32,920) | |||||||
State franchise taxes |
59 |
(11) |
(72) |
(50) | |||||||
Other non-cash items |
(8,017) |
40 |
(6,790) |
(1,504) | |||||||
Net cash provided by operating activities |
$ |
174,658 |
$ |
335,559 |
$ |
1,015,812 |
$ |
1,241,256 | |||
Three months ended |
Years ended | ||||||||||
December 31, |
December 31, | ||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2015 |
2016 |
2015 |
2016 | |||||||
Realized price before cash receipts for settled hedges |
$ |
2.32 |
$ |
3.22 |
$ |
2.52 |
$ |
2.60 | |||
Gathering, compression, and water handling and treatment revenues |
0.05 |
0.01 |
0.04 |
0.02 | |||||||
Distributions from unconsolidated affiliate |
— |
0.04 |
— |
0.01 | |||||||
Lease operating expense |
(0.08) |
(0.07) |
(0.07) |
(0.07) | |||||||
Gathering, compression, processing and transportation costs |
(1.23) |
(1.27) |
(1.21) |
(1.31) | |||||||
Marketing, net |
(0.38) |
(0.08) |
(0.23) |
(0.16) | |||||||
Production and ad valorem taxes |
(0.15) |
(0.08) |
(0.14) |
(0.10) | |||||||
General and administrative(1) |
(0.26) |
(0.21) |
(0.24) |
(0.20) | |||||||
Adjusted EBITDAX margin before settled hedges |
0.27 |
1.56 |
0.67 |
0.79 | |||||||
Cash receipts for settled hedges |
1.96 |
1.04 |
1.57 |
1.48 | |||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.23 |
$ |
2.60 |
$ |
2.24 |
$ |
2.27 |
(1) |
Excludes equity-based stock compensation that is included in G&A |
Non-GAAP Disclosure
Certain selected financial information in this release is unaudited. Audited financial results are provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2016, which the Company filed with the SEC on February 28, 2017. In this release, Antero has provided a number of unaudited metrics, which include all-in finding and development cost per unit and drill bit only finding and development cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The finding and development costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the finding and development costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. The calculations for both all-in and drill bit only finding and development cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2016.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
This release provides a summary of Antero's reserves as of December 31, 2016, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Balance Sheets | |||||||
December 31, 2015 and December 31, 2016 | |||||||
(In thousands, except per share amounts) | |||||||
2015 |
2016 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
23,473 |
31,610 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016 |
79,404 |
29,682 |
|||||
Accrued revenue |
128,242 |
261,960 |
|||||
Derivative instruments |
1,009,030 |
73,022 |
|||||
Other current assets |
8,087 |
6,313 |
|||||
Total current assets |
1,248,236 |
402,587 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
1,996,081 |
2,331,173 |
|||||
Proved properties |
8,211,106 |
9,549,671 |
|||||
Water handling and treatment systems |
565,616 |
744,682 |
|||||
Gathering systems and facilities |
1,502,396 |
1,723,768 |
|||||
Other property and equipment |
46,415 |
41,231 |
|||||
12,321,614 |
14,390,525 |
||||||
Less accumulated depletion, depreciation, and amortization |
(1,589,372) |
(2,363,778) |
|||||
Property and equipment, net |
10,732,242 |
12,026,747 |
|||||
Derivative instruments |
2,108,450 |
1,731,063 |
|||||
Other assets |
26,565 |
95,153 |
|||||
Total assets |
$ |
14,115,493 |
14,255,550 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
69,911 |
38,627 |
||||
Accrued liabilities |
488,325 |
393,803 |
|||||
Revenue distributions payable |
129,949 |
163,989 |
|||||
Derivative instruments |
— |
203,635 |
|||||
Other current liabilities |
19,085 |
17,334 |
|||||
Total current liabilities |
707,270 |
817,388 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,668,782 |
4,703,973 |
|||||
Deferred income tax liability |
1,370,686 |
950,217 |
|||||
Derivative instruments |
— |
234 |
|||||
Other liabilities |
82,077 |
55,160 |
|||||
Total liabilities |
6,828,815 |
6,526,972 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 277,036 shares and 314,877 shares, respectively |
2,770 |
3,149 |
|||||
Additional paid-in capital |
4,122,811 |
5,299,481 |
|||||
Accumulated earnings |
1,808,811 |
959,995 |
|||||
Total stockholders' equity |
5,934,392 |
6,262,625 |
|||||
Noncontrolling interest in consolidated subsidiary |
1,352,286 |
1,465,953 |
|||||
Total equity |
7,286,678 |
7,728,578 |
|||||
Total liabilities and equity |
$ |
14,115,493 |
14,255,550 |
ANTERO RESOURCES CORPORATION | ||||||||||
Condensed Consolidated Statements of Operations and Comprehensive Income | ||||||||||
Years Ended December 31, 2014, 2015 and 2016 | ||||||||||
(In thousands, except per share amounts) | ||||||||||
2014 |
2015 |
2016 |
||||||||
Revenue and other: |
||||||||||
Natural gas sales |
$ |
1,301,349 |
1,039,892 |
1,260,750 |
||||||
Natural gas liquids sales |
328,323 |
264,483 |
432,992 |
|||||||
Oil sales |
107,080 |
70,753 |
61,319 |
|||||||
Gathering, compression, and water handling and treatment |
22,075 |
22,000 |
12,961 |
|||||||
Marketing |
53,604 |
176,229 |
393,049 |
|||||||
Commodity derivative fair value gains (losses) |
868,201 |
2,381,501 |
(514,181) |
|||||||
Gain on sale of assets |
40,000 |
— |
97,635 |
|||||||
Total revenue and other |
2,720,632 |
3,954,858 |
1,744,525 |
|||||||
Operating expenses: |
||||||||||
Lease operating |
29,341 |
36,011 |
50,090 |
|||||||
Gathering, compression, processing, and transportation |
461,413 |
659,361 |
882,838 |
|||||||
Production and ad valorem taxes |
87,918 |
78,325 |
66,588 |
|||||||
Marketing |
103,435 |
299,062 |
499,343 |
|||||||
Exploration |
27,893 |
3,846 |
6,862 |
|||||||
Impairment of unproved properties |
15,198 |
104,321 |
162,935 |
|||||||
Depletion, depreciation, and amortization |
477,896 |
709,763 |
809,873 |
|||||||
Accretion of asset retirement obligations |
1,271 |
1,655 |
2,473 |
|||||||
General and administrative (including equity-based compensation expense of $112,252, $97,877, and $102,421 in 2014, 2015, and 2016, respectively) |
216,533 |
233,697 |
239,324 |
|||||||
Contract termination and rig stacking |
— |
38,531 |
— |
|||||||
Total operating expenses |
1,420,898 |
2,164,572 |
2,720,326 |
|||||||
Operating income (loss) |
1,299,734 |
1,790,286 |
(975,801) |
|||||||
Other income (expenses): |
||||||||||
Equity in earnings of unconsolidated affiliate |
— |
— |
485 |
|||||||
Interest |
(160,051) |
(234,400) |
(253,552) |
|||||||
Loss on early extinguishment of debt |
(20,386) |
— |
(16,956) |
|||||||
Total other expenses |
(180,437) |
(234,400) |
(270,023) |
|||||||
Income (loss) before income taxes |
1,119,297 |
1,555,886 |
(1,245,824) |
|||||||
Provision for income tax (expense) benefit |
(445,672) |
(575,890) |
496,376 |
|||||||
Income (loss) from continuing operations |
673,625 |
979,996 |
(749,448) |
|||||||
Discontinued operations: |
||||||||||
Income from sale of discontinued operations, net of income tax expense of $1,354 in 2014 |
2,210 |
— |
— |
|||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
675,835 |
979,996 |
(749,448) |
|||||||
Net income and comprehensive income attributable to noncontrolling interest |
2,248 |
38,632 |
99,368 |
|||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
673,587 |
941,364 |
(848,816) |
||||||
Earnings (loss) per common share—basic: |
||||||||||
Continuing operations |
$ |
2.56 |
3.43 |
(2.88) |
||||||
Discontinued operations |
0.01 |
— |
— |
|||||||
Total |
$ |
2.57 |
3.43 |
(2.88) |
||||||
Earnings (loss) per common share—assuming dilution: |
||||||||||
Continuing operations |
$ |
2.56 |
3.43 |
(2.88) |
||||||
Discontinued operations |
0.01 |
— |
— |
|||||||
Total |
$ |
2.57 |
3.43 |
(2.88) |
||||||
Weighted average number of shares outstanding: |
||||||||||
Basic |
262,054 |
274,123 |
294,945 |
|||||||
Diluted |
262,068 |
274,143 |
294,945 |
ANTERO RESOURCES CORPORATION | ||||||||||
Condensed Consolidated Statements of Cash Flows | ||||||||||
Years Ended December 31, 2014, 2015 and 2016 | ||||||||||
(In thousands) | ||||||||||
Year Ended December 31, |
||||||||||
2014 |
2015 |
2016 |
||||||||
Cash flows from operating activities: |
||||||||||
Net income (loss) including noncontrolling interest |
$ |
675,835 |
979,996 |
(749,448) |
||||||
Adjustment to reconcile net income to net cash provided by operating activities: |
||||||||||
Depletion, depreciation, amortization, and accretion |
479,167 |
711,418 |
812,346 |
|||||||
Impairment of unproved properties |
15,198 |
104,321 |
162,935 |
|||||||
Derivative fair value (gains) losses |
(868,201) |
(2,381,501) |
514,181 |
|||||||
Gains on settled derivatives |
135,784 |
856,572 |
1,003,083 |
|||||||
Deferred income tax expense (benefit) |
445,672 |
575,890 |
(485,392) |
|||||||
Gain on sale of assets |
(40,000) |
— |
(97,635) |
|||||||
Equity-based compensation expense |
112,252 |
97,877 |
102,421 |
|||||||
Loss on early extinguishment of debt |
20,386 |
— |
16,956 |
|||||||
Gain on sale of discontinued operations |
(3,564) |
— |
— |
|||||||
Deferred income tax expense—discontinued operations |
1,354 |
— |
— |
|||||||
Equity in earnings of unconsolidated affiliate |
— |
— |
(485) |
|||||||
Distributions of earnings from unconsolidated affiliates |
— |
— |
7,702 |
|||||||
Other |
6,433 |
31,741 |
(12,488) |
|||||||
Changes in current assets and liabilities: |
||||||||||
Accounts receivable |
(45,593) |
(3,201) |
39,857 |
|||||||
Accrued revenue |
(94,733) |
63,316 |
(133,718) |
|||||||
Other current assets |
(2,891) |
(2,221) |
1,774 |
|||||||
Accounts payable |
(20,681) |
(8,536) |
7,365 |
|||||||
Accrued liabilities |
95,066 |
36,377 |
18,853 |
|||||||
Revenue distributions payable |
85,763 |
(52,403) |
34,040 |
|||||||
Other current liabilities |
1,016 |
6,166 |
(1,091) |
|||||||
Net cash provided by operating activities |
998,263 |
1,015,812 |
1,241,256 |
|||||||
Cash flows used in investing activities: |
||||||||||
Additions to proved properties |
(64,066) |
— |
(134,113) |
|||||||
Additions to unproved properties |
(777,422) |
(198,694) |
(611,631) |
|||||||
Drilling and completion costs |
(2,477,150) |
(1,651,282) |
(1,327,759) |
|||||||
Additions to water handling and treatment systems |
(196,675) |
(131,051) |
(188,188) |
|||||||
Additions to gathering systems and facilities |
(558,037) |
(360,287) |
(231,044) |
|||||||
Additions to other property and equipment |
(13,218) |
(6,595) |
(2,694) |
|||||||
Investment in unconsolidated affiliate |
— |
— |
(75,516) |
|||||||
Change in other assets |
(3,082) |
9,750 |
3,977 |
|||||||
Proceeds from asset sales |
— |
40,000 |
171,830 |
|||||||
Net cash used in investing activities |
(4,089,650) |
(2,298,159) |
(2,395,138) |
|||||||
Cash flows from financing activities: |
||||||||||
Issuance of common stock |
— |
537,832 |
1,012,431 |
|||||||
Issuance of common units by Antero Midstream Partners LP |
1,087,224 |
240,703 |
65,395 |
|||||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
— |
— |
178,000 |
|||||||
Issuance of senior notes |
1,102,500 |
750,000 |
1,250,000 |
|||||||
Repayment of senior notes |
(260,000) |
— |
(525,000) |
|||||||
Repayments on bank credit facilities, net |
1,442,000 |
(403,000) |
(677,000) |
|||||||
Make-whole premium on debt extinguished |
(17,383) |
— |
(15,750) |
|||||||
Payments of deferred financing costs |
(31,543) |
(17,293) |
(18,759) |
|||||||
Distributions to noncontrolling interest in consolidated subsidiary |
— |
(34,129) |
(75,082) |
|||||||
Employee tax withholding for settlement of equity compensation awards |
(142) |
(9,431) |
(26,895) |
|||||||
Other |
(2,777) |
(4,841) |
(5,321) |
|||||||
Net cash provided by financing activities |
3,319,879 |
1,059,841 |
1,162,019 |
|||||||
Net increase (decrease) in cash and cash equivalents |
228,492 |
(222,506) |
8,137 |
|||||||
Cash and cash equivalents, beginning of period |
17,487 |
245,979 |
23,473 |
|||||||
Cash and cash equivalents, end of period |
$ |
245,979 |
23,473 |
31,610 |
||||||
Supplemental disclosure of cash flow information: |
||||||||||
Cash paid during the period for interest |
$ |
163,055 |
219,945 |
239,369 |
||||||
Supplemental disclosure of noncash investing activities: |
||||||||||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment |
$ |
181,591 |
(169,783) |
(152,093) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended December 31, 2015 compared to the three months ended December 31, 2016:
Three Months Ended December 31, |
Amount of |
Percent |
||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
228,910 |
$ |
411,814 |
$ |
182,904 |
80 |
% | ||||
NGLs sales |
76,080 |
158,256 |
82,176 |
108 |
% | |||||||
Oil sales |
15,126 |
19,607 |
4,481 |
30 |
% | |||||||
Gathering, compression, and water handling and treatment |
6,916 |
2,854 |
(4,062) |
(59) |
% | |||||||
Marketing |
32,987 |
105,855 |
72,868 |
221 |
% | |||||||
Commodity derivative fair value gains (losses) |
545,103 |
(639,805) |
(1,184,908) |
* |
||||||||
Total operating revenues and other |
905,122 |
156,216 |
(748,906) |
(83) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
10,450 |
12,900 |
2,450 |
23 |
% | |||||||
Gathering, compression, processing, and transportation |
168,728 |
233,125 |
64,397 |
38 |
% | |||||||
Production and ad valorem taxes |
20,867 |
14,292 |
(6,575) |
(32) |
% | |||||||
Marketing |
84,861 |
120,822 |
35,961 |
42 |
% | |||||||
Exploration |
760 |
3,573 |
2,813 |
370 |
% | |||||||
Impairment of unproved properties |
60,651 |
115,712 |
55,061 |
91 |
% | |||||||
Depletion, depreciation, and amortization |
161,750 |
221,816 |
60,066 |
37 |
% | |||||||
Accretion of asset retirement obligations |
428 |
627 |
199 |
46 |
% | |||||||
General and administrative (before equity-based compensation) |
37,175 |
38,604 |
1,429 |
4 |
% | |||||||
Equity-based compensation |
18,597 |
26,754 |
8,157 |
44 |
% | |||||||
Contract termination and rig stacking |
27,629 |
— |
(27,629) |
* |
||||||||
Total operating expenses |
591,896 |
788,225 |
196,329 |
33 |
% | |||||||
Operating income (loss) |
313,226 |
(632,009) |
(945,235) |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
(1,542) |
(1,542) |
* |
||||||||
Interest expense |
(60,471) |
(67,918) |
(7,447) |
12 |
% | |||||||
Loss on early extinguishment of debt |
— |
(16,956) |
(16,956) |
* |
||||||||
Total other expenses |
(60,471) |
(86,416) |
(25,945) |
43 |
% | |||||||
Income before income taxes |
252,755 |
(718,425) |
(971,180) |
* |
||||||||
Income tax (expense) benefit |
(77,181) |
265,621 |
342,802 |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
175,574 |
(452,804) |
(628,378) |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
17,110 |
32,968 |
15,858 |
93 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
158,464 |
$ |
(485,772) |
$ |
(644,236) |
* |
|||||
Adjusted EBITDAX (1) |
$ |
307,812 |
$ |
475,880 |
$ |
168,068 |
55 |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
107 |
135 |
28 |
26 |
% | |||||||
C2 Ethane (MBbl) |
201 |
1,933 |
1,732 |
864 |
% | |||||||
C3+ NGLs (MBbl) |
4,308 |
5,557 |
1,249 |
29 |
% | |||||||
Oil (MBbl) |
529 |
500 |
(29) |
(5) |
% | |||||||
Combined (Bcfe) |
138 |
183 |
45 |
33 |
% | |||||||
Daily combined production (MMcfe/d) |
1,497 |
1,990 |
493 |
33 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.13 |
$ |
3.05 |
$ |
0.92 |
43 |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.17 |
$ |
9.36 |
$ |
3.19 |
52 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
17.37 |
$ |
25.22 |
$ |
7.85 |
45 |
% | ||||
Oil (per Bbl) |
$ |
28.59 |
$ |
39.18 |
$ |
10.59 |
37 |
% | ||||
Combined (per Mcfe) |
$ |
2.32 |
$ |
3.22 |
$ |
0.90 |
39 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.40 |
$ |
4.43 |
$ |
0.03 |
1 |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.17 |
$ |
9.36 |
$ |
3.19 |
52 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
21.85 |
$ |
25.60 |
$ |
3.75 |
17 |
% | ||||
Oil (per Bbl) |
$ |
40.85 |
$ |
39.18 |
$ |
(1.67) |
(4) |
% | ||||
Combined (per Mcfe) |
$ |
4.28 |
$ |
4.26 |
$ |
(0.02) |
— |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.07 |
$ |
(0.01) |
(13) |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.23 |
$ |
1.27 |
$ |
0.04 |
3 |
% | ||||
Production and ad valorem taxes |
$ |
0.15 |
$ |
0.08 |
$ |
(0.07) |
(47) |
% | ||||
Marketing, net |
$ |
0.38 |
$ |
0.08 |
$ |
(0.30) |
(79) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.18 |
$ |
1.22 |
$ |
0.04 |
3 |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.27 |
$ |
0.21 |
$ |
(0.06) |
(22) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
*Not meaningful or applicable |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the Year ended December 31, 2015 compared to the Year ended December 31, 2016:
Twelve Months Ended December 31, |
Amount of |
Percent |
||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||
Operating revenues and other: |
||||||||||||
Natural gas sales |
$ |
1,039,892 |
$ |
1,260,750 |
$ |
220,858 |
21 |
% | ||||
NGLs sales |
264,483 |
432,992 |
168,509 |
64 |
% | |||||||
Oil sales |
70,753 |
61,319 |
(9,434) |
(13) |
% | |||||||
Gathering, compression, and water handling and treatment |
22,000 |
12,961 |
(9,039) |
(41) |
% | |||||||
Marketing |
176,229 |
393,049 |
216,820 |
123 |
% | |||||||
Commodity derivative fair value gains (losses) |
2,381,501 |
(514,181) |
(2,895,682) |
* |
||||||||
Gain on sale of assets |
— |
97,635 |
97,635 |
* |
||||||||
Total operating revenues and other |
3,954,858 |
1,744,525 |
(2,210,333) |
(56) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
36,011 |
50,090 |
14,079 |
39 |
% | |||||||
Gathering, compression, processing, and transportation |
659,361 |
882,838 |
223,477 |
34 |
% | |||||||
Production and ad valorem taxes |
78,325 |
66,588 |
(11,737) |
(15) |
% | |||||||
Marketing |
299,062 |
499,343 |
200,281 |
67 |
% | |||||||
Exploration |
3,846 |
6,862 |
3,016 |
78 |
% | |||||||
Impairment of unproved properties |
104,321 |
162,935 |
58,614 |
56 |
% | |||||||
Depletion, depreciation, and amortization |
709,763 |
809,873 |
100,110 |
14 |
% | |||||||
Accretion of asset retirement obligations |
1,655 |
2,473 |
818 |
49 |
% | |||||||
General and administrative (before equity-based compensation) |
135,820 |
136,903 |
1,083 |
1 |
% | |||||||
Equity-based compensation |
97,877 |
102,421 |
4,544 |
5 |
% | |||||||
Contract termination and rig stacking |
38,531 |
— |
(38,531) |
* |
||||||||
Total operating expenses |
2,164,572 |
2,720,326 |
555,754 |
26 |
% | |||||||
Operating income (loss) |
1,790,286 |
(975,801) |
(2,766,087) |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
485 |
485 |
* |
||||||||
Interest expense |
(234,400) |
(253,552) |
(19,152) |
8 |
% | |||||||
Loss on early extinguishment of debt |
— |
(16,956) |
(16,956) |
* |
||||||||
Total other expenses |
(234,400) |
(270,023) |
(35,623) |
15 |
% | |||||||
Income (loss) before income taxes |
1,555,886 |
(1,245,824) |
(2,801,710) |
* |
||||||||
Income tax (expense) benefit |
(575,890) |
496,376 |
1,072,266 |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
979,996 |
(749,448) |
(1,729,444) |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
38,632 |
99,368 |
60,736 |
157 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
941,364 |
$ |
(848,816) |
$ |
(1,790,180) |
* |
|||||
Adjusted EBITDAX (1) |
$ |
1,221,422 |
$ |
1,536,144 |
$ |
314,722 |
26 |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
439 |
505 |
66 |
15 |
% | |||||||
C2 Ethane (MBbl) |
201 |
6,396 |
6,195 |
3,090 |
% | |||||||
C3+ NGLs (MBbl) |
15,350 |
20,279 |
4,929 |
32 |
% | |||||||
Oil (MBbl) |
2,078 |
1,873 |
(205) |
(10) |
% | |||||||
Combined (Bcfe) |
545 |
676 |
131 |
24 |
% | |||||||
Daily combined production (MMcfe/d) |
1,493 |
1,847 |
354 |
24 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.37 |
$ |
2.50 |
$ |
0.13 |
5 |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.17 |
$ |
8.28 |
$ |
2.11 |
34 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
17.15 |
$ |
18.74 |
$ |
1.59 |
9 |
% | ||||
Oil (per Bbl) |
$ |
34.05 |
$ |
32.73 |
$ |
(1.32) |
(4) |
% | ||||
Combined (per Mcfe) |
$ |
2.52 |
$ |
2.60 |
$ |
0.08 |
3 |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.15 |
$ |
4.39 |
$ |
0.24 |
6 |
% | ||||
C2 Ethane (per Bbl) |
$ |
6.17 |
$ |
8.28 |
$ |
2.11 |
34 |
% | ||||
C3+ NGLs (per Bbl) |
$ |
20.76 |
$ |
21.03 |
$ |
0.27 |
1 |
% | ||||
Oil (per Bbl) |
$ |
42.38 |
$ |
32.73 |
$ |
(9.65) |
(23) |
% | ||||
Combined (per Mcfe) |
$ |
4.10 |
$ |
4.08 |
$ |
(0.02) |
* |
|||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.07 |
$ |
0.07 |
$ |
— |
* |
|||||
Gathering, compression, processing, and transportation |
$ |
1.21 |
$ |
1.31 |
$ |
0.10 |
8 |
% | ||||
Production and ad valorem taxes |
$ |
0.14 |
$ |
0.10 |
$ |
(0.04) |
(29) |
% | ||||
Marketing, net |
$ |
0.23 |
$ |
0.16 |
$ |
(0.07) |
(30) |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.31 |
$ |
1.20 |
$ |
(0.11) |
(8) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.25 |
$ |
0.20 |
$ |
(0.05) |
(20) |
% |
(1) |
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX |
* Not meaningful or applicable. |
SOURCE Antero Resources Corporation
DENVER, Feb. 6, 2017 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced the formation of a joint venture to develop processing and fractionation assets in Appalachia (the "Joint Venture" or the "JV") with MarkWest Energy Partners, L.P. ("MarkWest"), a wholly owned subsidiary of MPLX, LP (NYSE: MPLX) ("MPLX"). Antero Midstream and MarkWest will each own a 50% interest in the Joint Venture and MarkWest will operate the Joint Venture assets. Antero Midstream also announced increased 2017 guidance.
Highlights Include:
Joint Venture
Antero Midstream and MarkWest will jointly develop processing assets at the Sherwood processing facility in Doddridge County, WV, and an additional still to be designated facility also located in West Virginia in the southwestern core of the Marcellus Shale. The assets are underpinned by long-term, fee-based agreements pursuant to which the Joint Venture will process Antero Resources Corporation's ("Antero Resources") (NYSE: AR) liquids-rich production from the Marcellus Shale. As part of the agreement, Antero Midstream will release to the Joint Venture its right to provide processing services on 195,000 gross acres held by Antero Resources in Ritchie, Tyler, and Wetzel Counties in West Virginia.
The Joint Venture participation will begin with the next three plants at the Sherwood processing facility, which are under development and scheduled to be placed into service during the first quarter of 2017, third quarter of 2017, and first quarter of 2018. The Joint Venture will not participate in the six existing Sherwood plants, which will continue to be owned and operated solely by MarkWest. The existing plants have the capacity to process over 1.2 Bcf per day of liquids-rich gas and are currently running at full capacity. The Joint Venture processing facilities, starting with the seventh plant, will be operated by MarkWest and have the potential to support an incremental eleven plants, or 2.2 Bcf per day of capacity, to facilitate liquids-rich production growth from Antero Resources.
In addition to the processing assets, the Joint Venture will own C3+ fractionation capacity at the Hopedale complex in Harrison County, Ohio supported by Antero Resources and other third party producers. The Hopedale complex, which is operated by MarkWest and its affiliates, currently includes three 60,000 Bbl/d fractionators that fractionate natural gas liquids from both the Marcellus and Ohio Utica Shales, and provides access to strategic liquids pipelines including Mariner East, Mariner West, TEPPCO, and Cornerstone. The Joint Venture will own a 33 1/3% interest in the recently commissioned third fractionator at the Hopedale complex. The Joint Venture will have the option to participate in additional fractionation capacity in the future, contingent on further C3+ NGL production growth.
Antero Midstream expects to invest up to $800 million through 2020, net to its 50% ownership interest in the joint venture. Approximately $155 million of the $800 million investment was made upon execution of the definitive agreements and represented capital related to the Sherwood processing plants and the Hopedale fractionation facility.
Paul Rady, Chairman and CEO of Antero Midstream said, "We are very excited about the opportunity to invest in the largest processing and fractionation footprint in the Northeast and support it with the largest core liquids-rich resource base in Appalachia. The accretive Joint Venture represents a big step towards executing Antero Midstream's full value chain organic growth strategy supporting Antero Resources."
Mr. Rady further added, "The joint venture capitalizes on the strong relationship between Antero and MarkWest, and now MPLX, and the long track record and deep expertise in developing processing and fractionation assets, particularly in the Northeast. This premier partnership will economically align a dominant resource and infrastructure footprint unparalleled in Appalachia."
Increased 2017 Guidance and Long-Term Targets
Driven by the Joint Venture, Antero Midstream is increasing its forecast for net income to $305 million to $345 million, adjusted EBITDA to $520 million to $560 million and distributable cash flow ("DCF") to $405 million to $445 million for 2017. Additionally, Antero Midstream's peer-leading distribution growth of 28% to 30% as compared to 2016 remains unchanged, resulting in an average DCF coverage ratio of 1.30x to 1.45x on an annual basis. Antero Midstream has also revised its 2017 capital expenditure budget to $800 million.
Below is a comparison of the 2017 updated guidance and long-term targets to previously provided 2017 guidance and long-term targets.
Previous Guidance |
Updated Guidance |
||||||||
2017 Financial Guidance |
Low |
High |
Low |
High |
% Change | ||||
Net Income ($MM) |
$295 |
— |
$335 |
$305 |
— |
$345 |
3% | ||
Adjusted EBITDA ($MM) |
$510 |
— |
$550 |
$520 |
— |
$560 |
2% | ||
Distributable Cash Flow ($MM) |
$395 |
— |
$435 |
$405 |
— |
$445 |
2% | ||
Year-Over-Year Distribution Growth |
28% |
— |
30% |
28% |
— |
30% |
— | ||
DCF Coverage Ratio |
1.30x |
— |
1.45x |
1.30x |
— |
1.45x |
— | ||
Capital Expenditures ($MM) |
$525 |
$800 |
52% | ||||||
2018 – 2020 Long-Term Targets |
Previous Target |
Updated Target |
% Change | ||||||
Annual Distribution Growth |
28% — 30% |
28% — 30% |
— | ||||||
DCF Coverage Ratio |
>1.20x |
>1.25x |
4% | ||||||
Leverage |
Low 2-times range |
Low 2-times range |
— |
Michael Kennedy, CFO of Antero Midstream said, "The visibility into Antero Resources' development plan allows Antero Midstream and MPLX to invest in attractive rate of return projects with 4-times to 6-times investment to buildout EBITDA multiples. Additionally, Antero Midstream is benefitting from investing in significant projects that will be placed in-service almost immediately, improving overall project returns and resulting in accretion to distributable cash flow. This attractive organic expansion opportunity allows Antero Midstream to target peer-leading compound annual distribution growth of 28% to 30% through 2020, while maintaining a healthy balance sheet and increasing its DCF coverage to over 1.25x in the corresponding period."
Presentation
An updated presentation will be posted to the Partnership's website. The presentation can be found at www.anteromidstream.com on the homepage. Information on the Partnership's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Antero Midstream views Adjusted EBITDA as an important indicator of the Partnership's performance. Antero Midstream defines Adjusted EBITDA as Net Income before equity-based compensation expense, interest expense, depreciation expense, accretion of contingent acquisition consideration, excluding pre-acquisition income and expenses attributable to the parent and equity in earnings of unconsolidated affiliate, and including cash distributions from unconsolidated affiliate.
Antero Midstream uses Adjusted EBITDA to assess:
The Partnership defines Distributable Cash Flow as Adjusted EBITDA less cash interest paid, income tax withholding payments and cash reserved for payments upon vesting of equity-based compensation awards and ongoing maintenance capital expenditures paid, excluding pre-acquisition amounts attributable to the parent plus cash distribution to be received from unconsolidated affiliate. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Antero Midstream does not provide guidance on equity earnings, among other items, that are reconciling items between forecasted Adjusted EBITDA and forecasted Net Income due to the uncertainty regarding timing and estimates of reconciling items. Antero Midstream provides a range for the forecasts of Net Income, Adjusted EBITDA, and Distributable Cash Flow to allow for the variability in timing and uncertainty of estimates of reconciling items between forecasted Adjusted EBITDA and forecasted Net Income. Therefore, the Partnership cannot reconcile Adjusted EBITDA to forecasted Net Income without unreasonable effort.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia and Ohio, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio.
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release and are based upon a number of assumptions. Although the Partnership believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that the assumptions underlying these forward-looking statements will be accurate or the plans, intentions or expectations expressed herein will be achieved. For example, future acquisitions, dispositions or other strategic transactions may materially impact the forecasted or targeted results described in this release. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Resources.
Antero Midstream cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership's control, incident to the gathering and compression and fresh water and waste water treatment business. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the quarter ended December 31, 2015.
For more information, contact Michael Kennedy – CFO of Antero Midstream at (303) 357-6782 or mkennedy@anteroresources.com.
SOURCE Antero Midstream Partners LP
DENVER, Feb. 1, 2017 /PRNewswire/ --Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced estimated reserves as of December 31, 2016.
Highlights:
Antero's estimated proved reserves at December 31, 2016 were 15.4 Tcfe, a 16% increase compared to estimated proved reserves at December 31, 2015. Proved, probable and possible ("3P") reserves at year-end 2016 totaled 46.4 Tcfe, which represents a 25% increase compared to the previous year. Both proved and 3P reserves as of December 31, 2016 account for 115 million barrels and 912 million barrels of ethane, respectively, as natural gas rather than liquids since this ethane is expected to remain in the natural gas stream until such time as pricing supports full ethane recovery.
Drill bit only finding and development cost, including price and performance revisions, was $0.39 per Mcfe for 2016. All-in finding and development cost for estimated proved reserve additions was $0.52 per Mcfe for 2016. The expected reserve life of the Company's estimated proved reserves is approximately 23 years.
Estimated Proved Reserves
As of December 31, 2016, the Company's 15.4 Tcfe of estimated proved reserves were comprised of 61% natural gas, 37% NGLs and 2% oil. The Marcellus Shale accounted for 87% of estimated proved reserves and the Ohio Utica Shale accounted for 13%. For 2016, Antero added 2.6 Tcfe of estimated proved reserves through the drill bit, which is reflective of longer laterals, operational efficiencies and the utilization of advanced completion techniques. Included in the 2016 audited reserves are 61 producing wells and 81 proved undeveloped locations, or 21% of the total proved undeveloped locations in the Marcellus, booked at a 2.0 Bcf/1,000' type curve. The remaining Marcellus proved undeveloped locations are booked at a 1.7 Bcf/1,000' type curve. The primary driver behind the increased type curve on certain locations was improved performance from nearby wells following the implementation of advanced completions.
At year-end 2016, estimated proved reserves included 553 million barrels or 2.4 Tcfe of ethane reserves, net of shrink, in the Marcellus Shale, an increase of 1.4 Tcfe from year-end 2015 reserves. The increase in expected ethane recoveries is primarily driven by Antero's ethane sales contract associated with the Shell ethane cracker in Pennsylvania which is expected to be placed in service in 2021. The remaining Marcellus ethane reserves, as well as the Ohio Utica ethane reserves, continue to be carried as natural gas reserves as it is assumed that these ethane reserves will be sold on an energy equivalent basis in the natural gas stream until prices support full ethane recovery.
Approximately 29% of Antero's combined 616,000 net acre leasehold position was classified as proved at December 31, 2016. Based on Antero's successful drilling results to date, as well as those of other operators in the vicinity of Antero's leasehold, the Company believes that a substantial portion of its Marcellus and Ohio Utica Shale undeveloped acreage will be classified as proved over time as more wells are drilled. No West Virginia Utica dry gas locations were classified as 3P reserves at year-end 2016, with the exception of one proved developed producing location, due to the early stage of drilling and production in the play.
Estimated proved developed reserves increased by 18% from year-end 2015 to 6.9 Tcfe at December 31, 2016. The Company added 94 Marcellus and 30 Ohio Utica wells to estimated proved developed reserves in 2016. The percentage of estimated proved reserves classified as proved developed increased to 45% at December 31, 2016. Estimated proved undeveloped reserves increased by 15% primarily as a result of continued development in the Marcellus and Utica Shale plays and an increase in ethane expected to be recovered and sold as a liquid. The average heating content of the Marcellus and Utica proved undeveloped locations is 1250 BTU and 1200 BTU, respectively, and the average lateral lengths for each are 9,000 feet.
Under the Securities and Exchange Commission ("SEC") reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2.5 Tcfe of proved undeveloped reserves to the probable category in 2016 to comply with the SEC five-year development rule. The reclassified proved undeveloped locations were displaced by locations that are more liquids-rich with better economics. Antero's 8.5 Tcfe of estimated proved undeveloped reserves will require an estimated $3.8 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.45 per Mcfe. The future development capital is based on current contracted rates combined with spot market rates based on today's market pricing.
Antero incurred estimated 2016 capital costs of approximately $2.1 billion, including drilling and completion costs of $1.3 billion, unproved leasehold acquisition costs of $459 million, proved property acquisitions of $134 million and leasehold additions of $153 million. Assuming the $2.1 billion estimate of capital costs, preliminary 2016 all-in finding and development cost for proved reserve additions from all sources, including performance and price revisions, was $0.52 per Mcfe. The 2016 capital costs are unaudited and preliminary. Final capital costs will be provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2016.
Summary of Changes in Estimated Proved Reserves (in Tcfe) |
||
Balance at December 31, 2015 |
13.2 | |
Extensions, discoveries and additions |
2.6 | |
Purchases of estimated proved reserves |
0.6 | |
Performance and price revisions |
0.7 | |
Partial ethane recovery |
1.4 | |
Reclassification to probable due to SEC 5-year development rule |
(2.5) | |
Production |
(0.7) | |
Balance at December 31, 2016 |
15.4 | |
Costs Incurred ($ MM) |
|||
Leasehold Acquisitions: |
|||
Proved.............................................................................. |
$134 | ||
Unproved......................................................................... |
459 | ||
Leasehold additions........................................................... |
153 | ||
Drilling and Completion.................................................... |
1,328 | ||
Total costs incurred......................................................... |
$2,074 | ||
Finding and Development Costs ($/ Mcfe) |
||
All-in F&D cost for proved reserve additions(1)............. |
$0.52 | |
Drill bit only F&D cost(2).................................................... |
$0.39 | |
1) |
Total costs incurred divided by the summation of 2,637 Bcfe for extensions, discoveries and additions, 624 Bcfe for purchases of estimated proved reserves and 736 Bcfe for performance and price revisions. |
2) |
Drilling and completion costs divided by the summation of 2,637 Bcfe for extensions, discoveries and additions and 736 Bcfe for performance and price revisions. |
The table below summarizes both SEC and strip pricing as of December 31, 2016 and the associated PV-10 for estimated proved reserves and hedge values:
2016 Year-End |
|||||||
Benchmark Pricing: |
SEC Pricing |
Strip Pricing(1) |
Variance |
% Variance | |||
WTI Oil Price ($/Bbl) |
$42.68 |
$57.29 |
$14.61 |
34% | |||
Nymex Natural Gas Price ($/MMBtu) |
$2.46 |
$3.13 |
$0.67 |
27% | |||
C2+ Natural Gas Liquids ($/Bbl)(2) |
$13.58 |
$19.42 |
$5.84 |
43% | |||
PV-10 Values ($ Billions): |
|||||||
Estimated proved reserves PV-10......................... |
$3.7 |
$8.5 |
$4.8 |
130% | |||
Hedge PV-10 (3) ....................................................... |
3.0 |
1.3 |
(1.7) |
(57)% | |||
Total PV-10.............................................................. |
$6.7 |
$9.8 |
$3.1 |
46% |
1) |
Strip pricing as of December 31, 2016 for each of the first ten years and flat thereafter. |
2) |
Represents realized NGL price including regional market differentials. C3+ NGL SEC and Strip prices were $21.33/Bbl and $31.09/Bbl, respectively. |
3) |
Hedge PV-10 at strip pricing differs from year-end 2016 mark-to-market value of $1.6 billion due to the application of a higher discount rate. |
SEC prices for estimated proved reserves, calculated as of December 31, 2016 on a weighted average Appalachian index basis related to company-specific sales points, were $32.63 per barrel for oil and $2.31 per MMBtu for natural gas. Assuming SEC prices, which are not necessarily predictive of forward strip prices, the pre-tax present value discounted at 10% ("pre-tax PV–10") of the December 31, 2016 estimated proved reserves was $3.7 billion, a 1% increase from year-end 2015. Including Antero's hedges as of December 31, 2016 assuming SEC prices, the pre-tax PV–10 value of estimated proved reserves was $6.7 billion, which was in line with year-end 2015 PV-10 values. The GAAP standardized measure is based on SEC pricing, after tax, and does not include hedge values. For further discussion on pre-tax PV-10 values, please read "Non-Gap Disclosure."
Assuming future strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing as of December 31, 2016, the pre-tax PV–10 value of the same year-end 2016 estimated proved reserves was $8.5 billion which represents a 130% increase over the corresponding SEC reserve based pre-tax PV–10, before hedges. Including Antero's hedges, the pre-tax PV–10 value of estimated proved reserves was $9.8 billion assuming strip pricing, a 20% increase compared to the prior year.
Assuming SEC prices, the pre-tax PV–10 of the December 31, 2016 estimated proved developed reserves was $2.9 billion.
Assuming future strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing as of December 31, 2016, the pre-tax PV–10 value of the estimated proved developed reserves was $5.2 billion, an 80% increase over the corresponding SEC reserve based pre-tax PV-10, before hedges.
Proved, Probable and Possible Reserves
Antero estimates that it had year-end 2016 3P reserves of 46.4 Tcfe, a 25% increase from year-end 2015. The 25% increase in 3P reserves was driven by a combination of 2016 leasehold acquisitions, an increase in ethane volumes and the continued improvement in wellhead recoveries achieved through advanced completions. As of December 31, 2016, the Company's 46.4 Tcfe of 3P reserves were comprised of 71% natural gas, 27% NGLs and 2% oil. The Marcellus and Ohio Utica Shale comprised 39.6 Tcfe and 6.8 Tcfe of the 3P reserves, respectively.
Importantly, 38.0 Tcfe of Antero's 39.6 Tcfe of estimated 3P reserves in the Marcellus, or 96%, were classified as proved and probable reserves ("2P"), reflecting the low risk and statistically repeatable nature of Antero's Marcellus drilling. Further, 6.4 Tcfe of Antero's 6.8 Tcfe of estimated 3P reserves in the Ohio Utica, or 94%, were classified as 2P.
The tables below summarize Antero's estimated 3P reserve volumes as of December 31, 2016 using SEC pricing, categorized by operating area as well as PV-10 values of Antero's 3P reserve volumes using both SEC and Strip pricing:
Marcellus Shale |
Ohio Utica Shale |
||||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
||||||||||||||||
Proved |
7,790 |
928 |
13,355 |
933 |
1,624 |
68 |
2,031 |
278 |
|||||||||||||||
Probable |
18,195 |
1,078 |
24,667 |
2,344 |
3,875 |
89 |
4,409 |
528 |
|||||||||||||||
Possible |
1,227 |
59 |
1,579 |
188 |
303 |
7 |
345 |
57 |
|||||||||||||||
Total 3P |
27,212 |
2,065 |
39,601 |
3,465 |
5,802 |
164 |
6,785 |
863 |
|||||||||||||||
% Liquids(1) |
31% |
14% |
|||||||||||||||||||||
Combined 3P Reserves |
|||||||||||||||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
||||||||||||||||||||
Proved(2) |
9,414 |
995 |
15,386 |
1,211 |
|||||||||||||||||||
Probable |
22,069 |
1,168 |
29,076 |
2,872 |
|||||||||||||||||||
Possible |
1,531 |
66 |
1,924 |
245 |
|||||||||||||||||||
Total 3P |
33,014 |
2,229 |
46,386 |
4,328 |
|||||||||||||||||||
% Liquids(1) |
29% |
||||||||||||||||||||||
1) |
Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 2,104 million barrels of NGLs and 124 million barrels of oil. | ||||||||||||||||||||||
2) |
513 of the 1,211 proved locations were undeveloped locations. | ||||||||||||||||||||||
3P PV-10 Values ($ Billion): |
SEC Pricing |
Strip Pricing(1) |
Variance |
% Variance |
|||||||||||||||||||
3P Reserves PV-10................................... |
$3.7 |
$15.4 |
$11.7 |
316% |
|||||||||||||||||||
Hedge PV-10 (2)........................................ |
3.0 |
1.3 |
(1.7) |
(57)% |
|||||||||||||||||||
Total PV-10............................................... |
$6.7 |
$16.7 |
$10.0 |
149% |
|||||||||||||||||||
1) |
Strip pricing as of December 31, 2016 for each of the first ten years and flat thereafter. | ||||||||||||||||||||||
2) |
Hedge PV-10 at strip pricing differs from year-end 2016 mark-to-market value of $1.6 billion due to the application of a higher discount rate. |
Assuming SEC prices, the pre-tax PV–10 of the December 31, 2016 3P reserves was $3.7 billion before hedges and $6.7 billion including hedges. Assuming year-end future strip pricing, with adjustments similar to SEC pricing, the pre-tax PV–10 of the same year-end 2016 3P reserves was $15.4 billion which represents a 316% increase over the corresponding SEC reserve based pre-tax PV–10, before hedges. Including Antero's hedges, the pre-tax PV–10 value of estimated 3P reserves was $16.7 billion assuming strip pricing, a 22% increase compared to the prior year. For further discussion on pre-tax PV-10 values, please read "Non-Gap Disclosure."
Antero's estimated proved and 3P reserves at December 31, 2016 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton ("D&M"). D&M's reserve audit covered properties representing 100% of Antero's total 3P reserves at December 31, 2016.
Non-GAAP Disclosure
Certain selected financial information in this release is unaudited. Audited financial results will be provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2016, which the Company intends to file with the SEC on February 28, 2017. In this release, Antero has provided a number of unaudited metrics, which include all-in finding and development cost per unit and drill bit only finding and development cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The finding and development costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the finding and development costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies.
Calculations for all-in and drill bit only finding and development cost per unit are based on estimated and unaudited costs incurred in 2016 and can be found in the footnotes to the table on page three of this release. The calculations for both all-in and drill bit only finding and development cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Year-end pre-tax PV–10 value and pre-tax PV-10 value including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV–10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV–10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV–10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV–10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). Antero is not yet able to provide a reconciliation of pre-tax PV–10 to Standardized Measure because the discounted future income taxes associated with the Company's reserves is not yet calculable. The Company expects to include a full reconciliation of pre-tax PV–10 to Standardized Measure in its Annual Report on Form 10-K for the year ended December 31, 2016.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future development costs, future capital spending plans, expected drilling and development plans, plans with respect to the rejection of ethane and the prices we will receive for future production as well as future production volumes are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
This release provides a summary of Antero's reserves as of December 31, 2016, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
SOURCE Antero Resources Corporation
DENVER, Jan. 11, 2017 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its fourth quarter and full-year 2016 earnings release on Tuesday, February 28, 2017 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Wednesday, March 1, 2017 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, March 10, 2017 at 9:00 am MT at 1-877-870-5176 (U.S.) or 1-858-384-5517 (International) using the passcode 10098004.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, March 10, 2017 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
SOURCE Antero Resources
DENVER, Jan. 4, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced its 2017 capital budget and guidance and provided a long-term outlook through 2020.
Highlights Include:
2017 Capital Budget
Antero's capital budget for 2017 is $1.5 billion, including $1.3 billion for drilling and completion and $200 million for core leasehold additions and extensions. Net production is expected to average 2,160 to 2,250 MMcfe/d in 2017, representing year-over-year growth of 20% to 25% relative to 2016 guidance. Approximately 70% of the drilling and completion budget for 2017 is allocated to the Marcellus Shale and the remaining 30% is allocated to the Ohio Utica Shale.
Antero's 2017 capital budget excludes Antero Midstream's (NYSE: AM) $525 million capital budget relating to low and high pressure gathering pipelines, compressor stations, fresh water and advanced wastewater treatment infrastructure. Antero Midstream announced its 2017 capital budget and guidance today in a separate news release, which can be found at www.anteromidstream.com.
Antero plans to operate an average of four drilling rigs in the Marcellus Shale in West Virginia in 2017 and expects to complete 135 wells with an average lateral length of 9,200 feet. Forty of the 135 completions are previously drilled but uncompleted wells carried over from 2016. The development plan in the Marcellus averages nine wells per pad in 2017, up from six wells per pad in 2016, as the Company continues to drive well efficiencies. Antero is currently drilling and completing wells at an average budgeted cost of $0.84 million per 1,000' of lateral in the Marcellus, a 30% decrease from 2015 completed well costs. During the fourth quarter of 2016, Antero averaged 12 drilling days per well in the Marcellus, a 52% improvement compared to the average drilling days per well for the 2015 development program. Additionally, Antero averaged 4.0 completion stages per day in the fourth quarter of 2016, a 15% increase over the 2015 completion program average while increasing proppant concentration per stage. The significant drilling improvements were driven by multiple enhancements, including rotary steerable drilling and increased mud pump circulation rates. Additionally, completion improvements were the result of more efficient completion stage sequencing ("zipper fracs") and proppant placement.
Antero plans to operate an average of three drilling rigs in the Ohio Utica Shale in 2017 and expects to complete 35 wells with an average lateral length of 9,700 feet. The development plan in the Utica averages six wells per pad in 2017. Antero is currently drilling and completing wells at an average budgeted cost of $0.99 million per 1,000' of lateral in the Utica, a 28% improvement over 2015 well costs. During the fourth quarter of 2016, Antero averaged 13 drilling days per well, a 58% improvement compared to the average drilling days per well of the 2015 development program. Additionally, Antero averaged 6.0 completion stages per day during the fourth quarter of 2016, a 62% increase over the 2015 completion program average while increasing proppant concentration per stage. The Marcellus operational improvements have also been applied in the Ohio Utica Shale, generating similar efficiency gains. Antero expects further improvements in drilling and completion efficiencies in the Ohio Utica in 2017 as Antero plans to be more active in the play than it was in 2016. The Company's activity in the Ohio Utica is contingent on the construction timetable for the Rover Pipeline for which Antero is an anchor shipper. If the Rover Pipeline project is delayed beyond the second half of 2017 planned in-service date, Antero intends to shift the appropriate amount of budgeted drilling and completion activity from the Ohio Utica to the Marcellus. The Company has additional firm transportation capacity to current favorably priced markets in the Marcellus beyond the 2017 forecasted growth.
Commenting on the 2017 capital budget and guidance, Glen Warren, Antero's President and CFO, said, "While we plan to live within cash flow from a drilling and completion capital standpoint in 2017, we are forecasting a more than 50% increase in consolidated cash flow from operations in 2018. This significant cash flow step-up is driven by targeted production growth in 2018 of 20% to 22%, assuming current strip pricing, with over 70% of production hedged in 2018 at $3.91 per MMBtu. Combined with an expected moderate increase in drilling and completion capital spend in 2018, we forecast a significant decrease in leverage ratios to the mid 2.0-times net debt to EBITDAX on both a stand-alone and a consolidated basis by year-end 2018."
As a follow-up to the material expansion of our Marcellus footprint in 2016, Antero plans to continue consolidating acreage in the core of its Marcellus and Ohio Utica leasehold positions in 2017. Antero has budgeted $200 million for core leasehold additions and extensions. Consistent with historical practices, the Company does not budget for acquisitions.
The following is a comparison of the 2017 capital budget to 2016 guidance.
($ in MM) |
Year Ended December 31, | |||||||||
Capital Comparison |
2016 |
2017 |
% Change | |||||||
Drilling & Completion |
$1,300 |
$1,300 |
0% | |||||||
Land |
100 |
200 |
100% | |||||||
Total Capital |
$1,400 |
$1,500 |
7% | |||||||
Average Operated Drilling Rigs |
7 |
7 |
0% | |||||||
Operated Wells Completed(1) |
140 |
170 |
22% | |||||||
Deferred Completions at Year End(1) |
40 |
30 |
(25)% | |||||||
1) Adjusted for 2016 actuals. |
The 2017 capital budget is expected to be fully funded through cash flow from operations and available borrowing capacity within Antero's bank credit facility. As of September 30, 2016, Antero had $4.1 billion of available consolidated liquidity, pro forma for the October 2016 private placement of common stock which raised $175 million and the $170 million non-core acreage divestiture which closed on December 16, 2016.
2017 Guidance
Antero's 2017 net daily production, including liquids, is forecast to grow 20% to 25% as compared to 2016 guidance of 1.8 Bcfe/d. Net liquids production is forecast to increase approximately 27% to an average of 92,500 Bbl/d in 2017, including 67,500 Bbl/d of C3+ NGLs, 19,000 Bbl/d of ethane and 6,000 Bbl/d of condensate at the midpoint of 2017 guidance. Antero expects to recover 19,000 Bbl/d of ethane, 11,500 Bbl/d of which will service an ethane sales agreement with Borealis once Mariner East 2 is in service, which is currently expected in the fourth quarter of 2017.
Price Realizations and Cash Costs
Antero projects that substantially all natural gas production in 2017 will be sold at current favorably priced indices, resulting in natural gas price realizations at a premium compared to Nymex. Driven by improved local differentials, Antero is forecasting an average realized price for C3+ NGLs of 45% to 50% of WTI oil prices in 2017 compared to a 40% of WTI oil price realization for the first nine months of 2016. Once the Mariner East 2 pipeline is placed in service, Antero will have the ability to market 61,500 Bbl/d of ethane, propane and normal butane volumes to international buyers at netback prices that are currently superior to the aforementioned 2017 guidance, based on today's strip pricing and international shipping rates. Antero is also forecasting an improvement to its oil price realizations, from approximately a $10.00 differential to WTI oil in 2016 to a $7.00 to $9.00 differential to WTI oil in 2017. Combining the expected improvement in pricing for NGLs and oil results in an overall increase in expected EBITDA of approximately $85 million in 2017, before the impact of hedging.
Antero expects a modest increase in cash production expense entirely driven by an increase in expected production taxes and fuel costs due to higher commodity prices. Net marketing expense is expected to decline to $0.075 to $0.125 per Mcfe due to a reduction in unutilized firm transportation capacity in 2017.
The Company is using the following key assumptions in its projections for 2017:
Guidance |
2017 | |||
Low |
High | |||
Production |
||||
Net Daily Production (MMcfe/d) |
2,160 |
2,250 | ||
Net Daily Residue Natural Gas Production (MMcf/d) |
1,625 |
1,675 | ||
Net Daily Liquids Production (Bbl/d) |
88,500 |
96,500 | ||
Net Daily C3+ NGL Production (Bbl/d) |
65,000 |
70,000 | ||
Net Daily Ethane Production (Bbl/d) |
18,000 |
20,000 | ||
Net Daily Oil Production (Bbl/d) |
5,500 |
6,500 | ||
Realized Pricing |
||||
Natural Gas Realized Price Premium to Nymex Henry Hub Before Hedging ($/Mcf)(1)(2) |
$0.00 |
$0.10 | ||
Oil Realized Price Differential to Nymex WTI Oil Before Hedging ($/Bbl) |
$(7.00) |
$(9.00) | ||
C3+ NGL Realized Price Before Hedging (% of Nymex WTI) (1) |
45% |
50% | ||
Ethane Realized Price Before Hedging (Differential to Mont Belvieu) ($/Gal) |
$0.00 |
$0.00 | ||
Cash Expenses |
||||
Cash Production Expense ($/Mcfe)(3) |
$1.55 |
$1.65 | ||
Marketing Expense, Net of Marketing Revenue ($/Mcfe) |
$0.075 |
$0.125 | ||
G&A Expense ($/Mcfe) |
$0.15 |
$0.20 |
(1) |
Based on strip pricing as of December 30, 2016 |
(2) |
Includes Btu upgrade as Antero's processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average |
(3) |
Includes lease operating expenses, gathering, compression, transportation expenses and production taxes |
Long-Term Outlook
As a result of materially improved capital efficiency and expected well recoveries, favorable price realizations due to firm transportation arrangements, significant production sold forward at attractively hedged prices, and Appalachian-leading core drilling inventory, Antero is targeting 20% to 22% compound annual growth in net gas equivalent production for the years 2018 through 2020. This growth rate includes liquids contribution to overall equivalent production ranging from 24% to 26%. Antero plans to deliver this long-term growth while keeping its aggregate drilling and completion budget within consolidated cash flow from operations, resulting in a declining leverage profile through 2020. Antero's long-term targets exclude the impact of any future acquisitions or divestitures, consistent with historical practices.
Additionally, Antero's firm transportation portfolio, which is contracted to grow to 4.85 Bcf/d by year-end 2018, allows the Company to transport and sell virtually all of its natural gas production at current favorably priced indices, including TCO, Chicago, MichCon and Gulf Coast hubs. Antero forecasts the percentage of natural gas production sold at current favorably priced indices through 2020 to remain in line with 2017 guidance resulting in natural gas price realizations, before hedges, at a $0.05 to $0.15 per Mcf premium to Nymex. Further enhancing price realizations, Antero has hedged approximately 66% of production targets for the years 2017 through 2020 at an average hedged price of $3.68 per MMBtu. The Company now has 3.5 Tcfe hedged through 2022.
Antero has an inventory of approximately 4,100 undrilled economic 3P locations including over 2,400 locations that deliver breakeven economics defined as a pre-tax rate of return of 20% at below $3.00 per MMBtu Nymex prices. The 2,400 highly economic locations have an average lateral length of 8,600 feet and represent a 14 year drilling inventory assuming the 2017 rate of completions.
Supported by Antero Resources' long-term production growth target, Antero Midstream today announced a long-term distribution growth target of 28% to 30% per year through 2020. As of December 31, 2016, Antero Resources owned approximately 61% of Antero Midstream.
Commenting on Antero's long-term targets, Paul Rady, Chairman and CEO, said, "Based on current strip prices, we are targeting 20% to 22% compound annual production growth from 2018 through 2020. This is driven by a modest annual increase in drilling and completion capital beginning in 2018, while maintaining significant liquidity and a declining leverage profile. Antero's ability to target top-tier production growth speaks to our high quality drilling inventory, the magnitude of our hedge book and the cash flow protection it provides, and our ability to consistently deliver peer leading EBITDAX margins. In addition, our development plan benefits from the flexibility to adjust to in-service dates of future firm transportation projects by modifying development between our two world-class plays, which enhances our ability to achieve 2017 guidance as well as our long-term targets."
Presentation
An updated presentation including details regarding Antero's 4,100 economic locations and over 2,400 locations delivering 20% rates of return at below $3.00 per MMBtu Nymex prices has been posted to the Company's website, which can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, drilling inventory and estimated rates of return, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, Antero's ability to meet development and drilling plans, Antero's ability to implement its hedge strategy and results, risks regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
SOURCE Antero Resources Corporation
DENVER, Jan. 4, 2017 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced its 2017 capital budget and guidance and provided a long-term outlook through 2020.
Highlights Include:
2017 Capital Budget
During 2017, Antero Midstream plans to expand its existing Marcellus and Ohio Utica Shale gathering, compression, fresh water and advanced wastewater treatment infrastructure to accommodate Antero Resources Corporation's (NYSE: AR) ("Antero Resources") development plans. Today in a separate news release, Antero Resources announced its 2017 drilling and completion capital budget of $1.3 billion, which is forecast to generate production growth of 20% to 25% over 2016 guided production, and that it is targeting a 20% to 22% compound annual growth rate for net production for the years 2018 through 2020. For 2017, Antero Resources plans to operate an average of four drilling rigs in the Marcellus Shale and three drilling rigs in the Ohio Utica Shale. Antero Resources plans to complete 135 wells in the Marcellus Shale and 35 wells in the Ohio Utica Shale utilizing advanced completion designs. Antero Resources' release can be found at www.anteroresources.com.
Commenting on the Antero Resources 2017 capital budget and guidance and long-term production growth targets, along with its impact on Antero Midstream's growth, Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream, said, "In addition to the 20% to 25% expected production growth in 2017, Antero Resources is targeting 20% to 22% compound annual production growth for 2018 through 2020, which in turn supports Antero Midstream throughput growth and a best-in-class distribution growth target of 28% to 30% annually through 2020. We believe that we can achieve this long-term distribution growth target strictly through the organic buildout of infrastructure to support Antero Resources. Importantly, we do not anticipate that this organic infrastructure buildout will require any external financing beyond our current ATM program and we expect to maintain debt to adjusted EBITDA in the 2.0-times range. Antero Resources' increased capital efficiency, premium price realizations driven by its firm transportation portfolio, production sold forward at attractively hedged prices, and more than 14 years of highly economic core drilling inventory at the 2017 completion pace, all contribute to the ability to deliver strong long-term growth which will benefit Antero Midstream."
The Partnership has budgeted an investment of $460 million and $65 million in expansion and maintenance capital, respectively, resulting in a total Antero Midstream capital budget of $525 million in 2017. This capital budget includes $350 million of capital for gathering and compression infrastructure, resulting in 490 MMcf/d of incremental compression capacity and over 35 miles of gathering pipelines in the Marcellus and Ohio Utica Shales combined. Approximately 75% of the gathering and compression capital is planned to be invested in the Marcellus Shale and the remaining 25% invested in the Ohio Utica Shale. This mix is driven by Antero Resources' focus on Marcellus Shale drilling and completions in the first half of 2017 until incremental firm transportation to favorable markets in the Ohio Utica Shale is placed into service, which is expected in the second half of 2017. Antero Midstream has the ability to adjust its investments based on Antero Resources' development plan which has the flexibility to shift focus between the Marcellus Shale and Ohio Utica Shale due to firm transportation constraints.
In addition to capital expenditures for gathering and compression, Antero Midstream has budgeted investment of $75 million for water infrastructure to construct four fresh water storage impoundments as well as 37 miles of additional fresh water trunklines and surface pipelines to support Antero's completion activities. Approximately 67% of the water infrastructure budget will be allocated to the Marcellus Shale and the remaining 33% will be allocated to the Ohio Utica Shale. This excludes $100 million of capital to be invested in the construction of the Antero Clearwater Facility, which at 60,000 Bbl/d is expected to be the largest advanced wastewater treatment facility in the world for oil and gas operations. The Antero Clearwater Facility is expected to be placed into service in the fourth quarter of 2017.
The year-over-year increase to $65 million in maintenance capital is primarily driven by an increase in low pressure gathering and surface water pipeline investment as compared to 2016.
Antero Midstream expects to fund all 2017 capital expenditures through cash flow from operations, available borrowing capacity within Antero Midstream's existing $1.5 billion bank credit facility, and proceeds from its at-the-market unit offering program. As of September 30, 2016, Antero Midstream had approximately $1.0 billion of liquidity to fund organic growth opportunities.
Below is a comparison of the 2017 capital budget to 2016 guidance.
Year Ended December 31, |
||||||
Capital Comparison ($MM) |
2016 |
2017 |
% Change | |||
Gathering and Compression Infrastructure |
$255 |
$350 |
37% | |||
Fresh Water Infrastructure |
50 |
75 |
50% | |||
Advanced Wastewater Treatment Facility |
130 |
100 |
(23)% | |||
Stonewall Gathering Pipeline |
45 |
— |
(100)% | |||
Total Capital |
$480 |
$525 |
9% | |||
Expansion Capital |
$455 |
$460 |
1% | |||
Maintenance Capital |
25 |
65 |
160% | |||
Total Capital |
$480 |
$525 |
9% |
2017 Guidance
Antero Midstream is forecasting net income of $295 million to $335 million, adjusted EBITDA of $510 million to $550 million and distributable cash flow ("DCF") of $395 million to $435 million for 2017. Additionally, Antero Midstream is forecasting annual distribution growth of 28% to 30% as compared to 2016, resulting in an average DCF coverage ratio of 1.30x to 1.45x on an annual basis. Antero Midstream's 2017 guidance excludes any impact from potential third party volumes or transactions.
Below is a comparison of the 2017 guidance to 2016 guidance.
2016 |
2017 |
|||||||||
Low |
High |
Low |
High |
% Change | ||||||
Net Income ($MM) |
$205 |
— |
$225 |
$295 |
— |
$335 |
47% | |||
Adjusted EBITDA ($MM) |
$365 |
— |
$385 |
$510 |
— |
$550 |
41% | |||
Distributable Cash Flow ($MM) |
$315 |
— |
$335 |
$395 |
— |
$435 |
28% | |||
Year-Over-Year Distribution Growth |
30% |
28% |
— |
30% |
(3)% | |||||
DCF Coverage Ratio |
1.55x |
— |
1.65x |
1.30x |
— |
1.45x |
(14)% | |||
Long-Term Growth Targets
Antero Midstream is targeting compound annual distribution growth of 28% to 30% through 2020 based on Antero Resources' corresponding 2017 guidance of 20% to 25% production growth and 20% to 22% compound annual production growth target from 2018 through 2020. Additionally, Antero Midstream expects DCF coverage in excess of 1.2x over the corresponding period. Antero Midstream's distribution growth target excludes the impact of any third party service revenues and any future acquisitions or divestitures, consistent with historical practice.
Commenting on the Antero Midstream 2017 capital budget and guidance, Michael Kennedy, Antero Midstream's CFO, said, "Antero Midstream's ability to provide best-in-class distribution growth guidance and targets through 2020, while maintaining DCF coverage in excess of 1.2-times, speaks to the superior visibility into Antero Resources' development plan and Antero Midstream's return on invested capital. Looking forward, Antero Midstream has over $2.4 billion in organic growth opportunities from 2016 through 2020, providing an extended runway for long-term growth and infrastructure development, ultimately benefiting our unitholders."
Presentation
An updated presentation will be posted to the Partnership's website. The presentation can be found at www.anteromidstream.com on the homepage. Information on the Partnership's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Antero Midstream views Adjusted EBITDA as an important indicator of the Partnership's performance. Antero Midstream defines Adjusted EBITDA as Net Income before equity-based compensation expense, interest expense, depreciation expense, accretion of contingent acquisition consideration, excluding pre-acquisition income and expenses attributable to the parent and equity in earnings of unconsolidated affiliate, and including cash distributions from unconsolidated affiliate.
Antero Midstream uses Adjusted EBITDA to assess:
The Partnership defines Distributable Cash Flow as Adjusted EBITDA less cash interest paid, income tax withholding payments and cash reserved for payments upon vesting of equity-based compensation awards and ongoing maintenance capital expenditures paid, excluding pre-acquisition amounts attributable to the parent plus cash distribution to be received from unconsolidated affiliate. Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of the Partnership from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders. Distributable Cash Flow does not reflect changes in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures. The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income. The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income. Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA. You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP. Antero Midstream's definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.
Antero Midstream does not provide guidance on equity earnings, among other items, that are reconciling items between forecasted Adjusted EBITDA and forecasted Net Income due to the uncertainty regarding timing and estimates of reconciling items. Antero Midstream provides a range for the forecasts of Net Income, Adjusted EBITDA, and Distributable Cash Flow to allow for the variability in timing and uncertainty of estimates of reconciling items between forecasted Adjusted EBITDA and forecasted Net Income. Therefore, the Partnership cannot reconcile Adjusted EBITDA to forecasted Net Income without unreasonable effort.
Antero Midstream is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia and Ohio, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio.
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release and are based upon a number of assumptions. Although the Partnership believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that the assumptions underlying these forward-looking statements will be accurate or the plans, intentions or expectations expressed herein will be achieved. For example, future acquisitions, dispositions or other strategic transactions may materially impact the forecasted or targeted results described in this release. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Resources.
Antero Midstream cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Partnership's control, incident to the gathering and compression and fresh water and waste water treatment business. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the quarter ended December 31, 2015.
For more information, contact Michael Kennedy – CFO of Antero Midstream at (303) 357-6782 or mkennedy@anteroresources.com.
SOURCE Antero Midstream Partners LP
DENVER, Dec. 7, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") announced today the pricing of its private placement to eligible purchasers of $600 million in aggregate principal amount of 5.0% senior unsecured notes due March 2025 at par. The offering is expected to close on December 21, 2016, subject to customary closing conditions.
Antero estimates that it will receive net proceeds of approximately $593 million, after deducting the initial purchasers' discounts and estimated expenses, of which it intends to finance the redemption of its $525 million of outstanding 6.0% Senior Notes due 2020 and use the remaining net proceeds for general corporate purposes.
The securities to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws; and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The notes are expected to be eligible for trading by qualified institutional buyers in the United States under Rule 144A and outside the United States pursuant to Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio.
Cautionary Statements
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this press release is intended to constitute guidance with respect to Antero Midstream.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, Antero's ability to meet development and drilling plans, the Company's ability to implement its hedge strategy and results, risk regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas, NGL and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, Dec. 7, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") announced today that, subject to market conditions, it intends to offer $550 million in aggregate principal amount of senior unsecured notes due 2025 in a private placement to eligible purchasers.
Antero intends to use a portion of the net proceeds of the offering to finance the redemption of its $525 million of outstanding 6.0% Senior Notes due 2020 and intends to use the remaining net proceeds for general corporate purposes.
The securities to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws; and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The notes are expected to be eligible for trading by qualified institutional buyers under Rule 144A and outside the United States pursuant to Regulation S.
This press release is being issued pursuant to Rule 135c under the Securities Act and is neither an offer to sell nor a solicitation of an offer to buy the notes or any other securities and shall not constitute an offer to sell or a solicitation of an offer to buy, or a sale of, the notes or any other securities in any jurisdiction in which such offer, solicitation or sale is unlawful.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio.
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SOURCE Antero Resources Corporation
DENVER, Oct. 26, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its third quarter 2016 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, which has been filed with the Securities and Exchange Commission.
Third Quarter Highlights Include:
Recent Developments
On October 25th, 2016, Antero signed a definitive agreement for the sale of approximately 17,000 net acres primarily located in Washington and Westmoreland Counties, Pennsylvania for $170 million. The transaction monetizes acreage that is outside of Antero's infrastructure build-out and beyond its five year drilling plan. It is expected to close in the fourth quarter of 2016. Tudor, Pickering, Holt & Co. acted as financial advisor to Antero in connection with the transaction.
On October 24th, 2016, Antero's borrowing base under its credit facility was increased to $4.75 billion, a $250 million increase over the Company's previous borrowing base of $4.5 billion. Lender commitments under the facility remain at $4.0 billion. The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., is currently comprised of 29 banks.
On October 7th, 2016, Antero completed a private placement of 6,730,769 shares of common stock at a price of $26.00 per share, resulting in $175 million of net proceeds. Pro forma for the proceeds from the Pennsylvania divestiture and the private placement, Antero's September 30, 2016 consolidated net debt to trailing twelve months EBITDAX was 3.2 times and consolidated liquidity was $4.0 billion.
Commenting on recent activity, Paul Rady, Chairman of the Board and CEO said, "We are pleased to be in a position to continue to organically grow production at 20% to 25% annually, while de-leveraging the balance sheet. Since year-end 2015, we have reduced our trailing twelve months leverage by a half a turn to 3.2 times today, while growing production by over 350 MMcfe/d and adding 65,000 net acres in the high-graded core of the Marcellus for long-term development. Virtually all of this acreage has now been dedicated to Antero Midstream for infrastructure build-out. We are an industry leader in the Marcellus and Utica Shale plays due to our differentiated strategy and that is evident today in our results."
Third Quarter 2016 Financial Results
As of September 30, 2016, Antero owned a 62% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated with Antero's results.
For the three months ended September 30, 2016, the Company reported GAAP net income of $238 million, or $0.78 per basic share and $0.77 per diluted share, compared to GAAP net income of $534 million, or $1.93 per basic and diluted share, in the third quarter of 2015. The GAAP net income for the third quarter of 2016 included the following items:
The Company's results for the third quarter of 2016 were as follows:
For a description of adjusted net income and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the third quarter of 2016 averaged 1,875 MMcfe/d, including 81,460 Bbl/d of liquids (26% liquids). Third quarter 2016 production represents an organic production growth rate of 25% from the third quarter of 2015 and a 6% increase compared to the second quarter of 2016. Third quarter 2016 C3+ natural gas liquids ("NGLs") and oil production averaged 57,286 Bbl/d and 4,603 Bbl/d, respectively, while ethane (C2) production averaged 19,572 Bbl/d. Total liquids production for the third quarter of 2016 represents an organic production growth rate of 56% and 9% from the third quarter of 2015 and second quarter of 2016, respectively.
Antero's average natural gas price before hedging increased 23% from the prior year quarter to $2.86 per Mcf, a $0.05 per Mcf premium to the average Nymex price for the period. Virtually all of Antero's third quarter 2016 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, Tennessee Gulf and Nymex. Antero's average realized natural gas price after hedging for the third quarter of 2016 was $4.30 per Mcf, a $1.49 premium to the Nymex average price for the period. This represents an 8% increase compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $184 million, or $1.44 per Mcf.
The Company's average realized C3+ NGL price before hedging for the third quarter of 2016 was $17.56 per barrel, or 39% of the Nymex WTI oil price, which represents a 45% increase as compared to the prior year quarter. Antero's average realized C3+ NGL price including hedges was $19.96 per barrel, a 21% increase compared to the third quarter of 2015. Antero's average realized ethane price for the third quarter of 2016 was $0.19 per gallon, or $8.00 per barrel. The average realized oil price was $34.93 per barrel, a $9.92 differential to Nymex WTI and a 15% increase as compared to the third quarter of 2015.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by 21% to $2.82 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, increased by 3% to $3.96 per Mcfe compared to the prior year quarter. For the third quarter of 2016, Antero realized a total cash settled hedge gain on all products of $197 million, or $1.14 per Mcfe.
Commenting on realized pricing, Glen Warren, President and CFO, said, "For the third quarter, we realized a $0.05 premium to Nymex on natural gas sales, before hedges, which is at the top end of our full year guidance. Additionally, while many of our peers were forced to shut in production in September due to the widening of Dominion South and TETCO M2 differentials to $1.96 per Mcf back of Nymex, we were able to realize an $0.08 premium to Nymex for the month, or a $2.04 per Mcf premium to these local indices. This once again highlights the significant value of our firm transport portfolio where we can physically move our gas to more healthy indices. This demonstrates our ability to mitigate Northeast basis risk, which in turn results in significant visibility for our continued growth plans."
Total operating revenue for the third quarter of 2016 was $1.1 billion as compared to $1.4 billion for the third quarter of 2015. Operating revenue for the third quarter of 2016 included a $334 million non-cash gain on unsettled hedges, while the third quarter of 2015 included an $873 million non-cash gain on unsettled hedges. In both periods, the non-cash gain on unsettled hedges was driven by decreasing natural gas prices during the period. Adjusted non-GAAP revenue excluding the unrealized hedge gain was $783 million, a 37% increase compared to the third quarter of 2015. Liquids production contributed 25% of total product revenues before hedges in the third quarter of 2016, as compared to a 22% contribution for the prior year quarter. For a reconciliation of revenue excluding unrealized hedge gains to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the third quarter of 2016 was $97 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee and Columbia Gas Pipelines. Marketing expense for the third quarter of 2016 was $115 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $18 million, or $0.10 per Mcfe, for the third quarter of 2016, representing a 55%, or $0.12 per Mcfe decrease from the second quarter of 2016. The significant decrease in net marketing expense from the prior quarter is primarily attributable to a third party contractual commitment that commenced on July 1, 2016, in which Antero released certain unutilized firm transportation capacity and the costs associated with the unutilized capacity. Additionally, Antero achieved a higher spread on its marketed volumes due to the widening of local northeast indices relative to the end market indices reached through Antero's firm transportation capacity.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem tax) for the third quarter of 2016 was $1.53 per Mcfe, a 16% increase compared to $1.32 per Mcfe in the prior year quarter. The increase is primarily due to higher transportation costs incurred on new pipelines that were placed in service in late 2015, which deliver gas to better price indices resulting in higher realized gas prices for the period. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.36 per Mcfe for gathering, compression, processing and transportation costs and $0.09 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the third quarter of 2016, excluding non-cash equity-based compensation expense was $0.18 per Mcfe, a 31% decrease from the third quarter of 2015. The significant per unit decrease in general and administrative expenses was primarily driven by the increase in production while general and administrative expense remained relatively flat. Per unit depreciation, depletion and amortization expense decreased 15% from the prior year quarter to $1.16 per Mcfe, primarily driven by lower development costs.
Adjusted EBITDAX of $373 million for the third quarter of 2016 represents a record for Antero and a 28% increase compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $2.16 per Mcfe, representing a 3% increase from the prior year quarter. For the third quarter of 2016, cash flow from operations before changes in working capital was $310 million, a 31% increase from the prior year quarter.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended September 30, 2016:
Three Months Ended September 30, 2016 | ||||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||||
Average Net Production |
1,386 |
4,603 |
57,286 |
19,572 |
1,875 | |||||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs |
Ethane |
Combined | |||||||||||
Average realized price before settled derivatives |
$ |
2.86 |
$ |
34.93 |
$ |
17.56 |
$ 8.00 |
$ |
2.82 | |||||||
Settled derivatives |
1.44 |
– |
2.40 |
– |
1.14 | |||||||||||
Average realized price after settled derivatives |
$ |
4.30 |
$ |
34.93 |
$ |
19.96 |
$ 8.00 |
$ |
3.96 | |||||||
Nymex average price |
$ |
2.81 |
$ |
44.85 |
$ |
2.81 | ||||||||||
Premium / (Differential) to Nymex |
$ |
1.49 |
$ |
(9.92) |
$ |
1.15 | ||||||||||
Marcellus Shale — Antero completed and placed on line 14 horizontal Marcellus wells during the third quarter of 2016 with an average lateral length of 9,033 feet. During the quarter, Antero drilled on average approximately 4,000 feet per day in its laterals while drilling and casing 28 wells during the quarter. The Company's contracted completion crews averaged 4.5 stages per day in the Marcellus, a record for the Company. The increase in stages per day was a result of the implementation of zipper fracs on select pads during the quarter. Antero plans to utilize zipper fracs on virtually all newly constructed pads going forward. Year-to-date in the Marcellus, Antero has completed 69 wells that have at least 90 days of production history. The 69 wells have an average EUR of 20.6 Bcfe at 1,245 Btu gas and assuming ethane rejection, an average lateral length of 9,000' and an average all-in development cost of $0.53 per Mcfe. The Company is currently operating four drilling rigs and five completion crews in the Marcellus Shale play.
Year-to-date, Antero has completed 33 wells using advanced completions, defined as completions using more than 1,300 pounds per foot of proppant. The preliminary EURs associated with these 33 wells are currently trending to approximately 2.0 Bcf/1,000 or 17% above Antero's 1.7 Bcf/1,000 type curve.
Current well costs are $0.86 million per 1,000 feet of lateral in the Marcellus, which represents a 27% reduction from 2015 and a 4% reduction from the second quarter of 2016. The reduction in well costs continues to be driven both by reduced service costs through long-term contracts rolling off, resulting in a greater proportion of rigs and completion crews operating at market prices and continuing operational efficiencies. In the Marcellus, average drilling days from spud to final rig release declined to 14 days in the third quarter of 2016, a 42% reduction from 2015 and a 7% reduction from the second quarter of 2016.
Ohio Utica Shale — Antero completed and placed on line eight horizontal Ohio Utica wells during the third quarter of 2016 with an average lateral length of 8,540 feet. During the quarter, Antero drilled on average approximately 2,700 feet per day in its laterals while drilling and casing five wells during the quarter. The Company's contracted completion crews averaged 5.0 stages per day in the Utica, a record for the Company. Additionally, the Company has averaged 6.3 stages per day in 2016 when utilizing zipper fracs in the Utica. Four of the eight wells completed in the third quarter of 2016 have been on line for more than 30 days and had an average restricted 30-day rate of 17.0 MMcfe/d while rejecting ethane (14% liquids). Antero is currently operating one drilling rig and one completion crew in the Utica Shale play.
Current well costs are $1.01 million per 1,000 feet of lateral in the Utica, which represents a 26% reduction from 2015 and a 3% reduction from the second quarter of 2016. The reduction in well costs is primarily driven by lower service costs and continued operational efficiencies. Drilling days from spud to final rig release declined to 16 days in the Utica in the third quarter of 2016, a 49% reduction from 2015.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the third quarter of 2016 averaged 1,431 MMcf/d, a 38% increase from the third quarter of 2015 and a 6% increase sequentially. High pressure gathering volumes for the third quarter of 2016 averaged 1,351 MMcf/d, an 11% increase from the third quarter of 2015 and an 8% increase sequentially. Compression volumes for the third quarter of 2016 averaged 777 MMcf/d, a 78% increase from the third quarter of 2015 and an 18% increase sequentially. The increase in gathering and compression volumes was due to production growth from Antero Resources in Antero Midstream's area of dedication. Condensate gathering volumes averaged 521 Bbl/d during the quarter, an 82% decrease compared to the prior year quarter and a 74% decrease sequentially. The sequential decrease in condensate gathering volumes was primarily driven by Antero shifting its Ohio Utica Shale development from its Highly-Rich Gas/Condensate area to currently higher rate of return drilling in the Highly-Rich Gas areas. Fresh water delivery volumes averaged 140,162 Bbl/d during the quarter, a 109% increase compared to the prior year quarter and a 33% increase sequentially. The increase in volumes was driven by an increase in the average water used per foot in Marcellus completions to 43 barrels per foot, a 35% increase as compared to 2015 and a 5% increase compared to the second quarter of 2016 as Antero piloted higher water and sand concentration completions.
For the three months ended September 30, 2016, the Partnership reported revenues of $150 million, comprised of $78 million from the Gathering and Compression segment and $72 million from the Water Handling and Treatment segment. Revenues increased 84% compared to the prior year quarter, primarily driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $25 million from produced water handling and high rate water transfer services. Direct operating expenses for the Gathering and Compression and Water Handling and Treatment segments were $5 million and $28 million, respectively, for a total of $33 million compared to $2 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $24 million from produced water handling and high rate water transfer services. The increase in direct operating expenses was driven primarily by the inclusion of produced water handling and high rate water transfer services, as well as the expansion of the Partnership's gathering and compression and fresh water delivery systems to support the production growth of Antero Resources. General and administrative expenses including equity-based compensation was $13 million, a $0.5 million decrease compared to the third quarter of 2015. General and administrative expenses excluding equity-based compensation were $7 million during the third quarter of 2016, a 22% decrease compared to the third quarter of 2015, which included additional expenses from the integrated water business drop-down transaction. Total operating expenses were $76 million, including $26 million of depreciation, $7 million of equity-based compensation, and $4 million of accretion of contingent acquisition consideration.
The Board of Directors of Antero Resources Midstream Management LLC, the general partner of the Partnership, declared a cash distribution of $0.265 per unit ($1.06 per unit annualized) for the third quarter of 2016. The distribution represents a 29% increase compared to the prior year quarter and a 6% increase sequentially. The distribution is the Partnership's seventh consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on November 24, 2016 to unitholders of record as of November 10, 2016.
Balance Sheet and Liquidity
As of September 30, 2016, Antero's consolidated net debt was $4.7 billion, of which $775 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two facilities are currently $5.2 billion(1). Including $709 million in letters of credit outstanding, the company had $3.7 billion in available consolidated liquidity as of September 30, 2016. Pro forma for the $175 million private placement of common stock and the $170 million of proceeds from the Pennsylvania divestiture expected to close in the fourth quarter of 2016, Antero's September 30, 2016 consolidated pro forma net debt to trailing twelve months EBITDAX was 3.2 times. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures." For a description of adjusted EBITDAX to its nearest comparable GAAP measure, please read "Non-GAAP Financial Measures."
1) |
Liquidity calculation assumes Antero Midstream's borrowings under its credit facility limited to EBITDA covenant of 5.0x LTM EBITDA, less Senior Note Issuances as of September 30, 2016. |
Third Quarter 2016 Capital Spending
Antero's drilling and completion costs for the three months ended September 30, 2016 were $300 million. In addition, the Company invested $48 million for land, excluding acquisitions. Antero Midstream invested $56 million for gathering and compression systems and $59 million for water infrastructure projects including $52 million on the Antero Clearwater Treatment Facility.
Hedge Position
Antero currently has hedged 3.5 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2016 through December 31, 2022 at an average index price of $3.65 per MMBtu. At September 30, 2016, the Company's estimated fair value of commodity derivative instruments was $2.4 billion.
The following table summarizes Antero's hedge position as of September 30, 2016:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
4Q 2016: |
||||||
Nymex HH |
1,110,000 |
$3.57 |
— |
— | ||
Dom South |
272,500 |
$5.47 |
— |
— | ||
CGTLA |
170,000 |
$4.20 |
— |
— | ||
TCO |
60,000 |
$5.01 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.61 | ||
4Q 2016 Total |
1,612,500 |
$4.01 |
30,000 |
$0.61 | ||
2017: |
||||||
Nymex HH |
1,370,000 |
$3.39 |
— |
— | ||
CGTLA |
420,000 |
$4.27 |
— |
— | ||
Chicago |
70,000 |
$4.57 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
27,500 |
$0.39 | ||
Ethane MB ($/Gallon) |
— |
— |
20,000 |
$0.25 | ||
Nymex WTI ($/Bbl) |
— |
— |
1,000 |
$51.90 | ||
2017 Total |
1,860,000 |
$3.63 |
48,500 |
N/A (1) | ||
2018 Nymex HH |
2,002,500 |
$3.91 |
2,000(2) |
$0.65 | ||
2019 Nymex HH |
2,330,000 |
$3.70 |
— |
— | ||
2020 Nymex HH |
1,377,500 |
$3.66 |
— |
— | ||
2021 Nymex HH |
660,000 |
$3.35 |
— |
— | ||
2022 Nymex HH |
470,000 |
$3.26 |
— |
— |
(1) |
Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges. |
(2) |
Represents 2,000 Bbl/d of propane hedged at Mont Belvieu. |
Conference Call
A conference call is scheduled on Thursday, October 27, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, November 4, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10091479.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, November 4, 2016 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the October 27, 2016 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge gains as set forth in this release represents total operating revenue adjusted for unsettled hedge gains. Antero believes that revenue excluding unrealized hedge gains is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge gains is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (in thousands):
Three months ended |
Nine months ended September 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Total operating revenue |
$ |
1,443,335 |
$ |
1,116,503 |
$ |
3,049,736 |
$ |
1,588,309 | ||||
Commodity derivative fair value (gains) |
(1,079,071) |
(530,334) |
(1,836,398) |
(125,624) | ||||||||
Cash receipts for settled hedges |
205,919 |
196,712 |
586,639 |
813,559 | ||||||||
Revenue excluding unrealized hedge gains |
$ |
570,183 |
$ |
782,881 |
$ |
1,799,977 |
$ |
2,276,244 |
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (in thousands):
Three months ended |
Nine months ended | |||||||||||
September 30, |
September 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Net income (loss) |
$ |
533,842 |
$ |
238,255 |
$ |
782,900 |
$ |
(363,044) | ||||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
(873,152) |
(333,622) |
(1,249,759) |
687,935 | ||||||||
Impairment of unproved properties |
8,754 |
11,753 |
43,670 |
47,223 | ||||||||
Equity-based compensation |
23,915 |
26,381 |
79,280 |
75,667 | ||||||||
Contract termination and rig stacking |
— |
— |
10,902 |
— | ||||||||
Income tax effect of reconciling items |
320,711 |
112,490 |
435,033 |
(308,675) | ||||||||
Adjusted net income |
$ |
14,070 |
$ |
55,257 |
$ |
102,026 |
$ |
139,106 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended |
Nine months ended September 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Net cash provided by operating activities |
$ |
246,046 |
$ |
326,991 |
$ |
841,154 |
$ |
905,697 | ||||
Net change in working capital |
(9,119) |
(17,327) |
(103,463) |
(35,939) | ||||||||
Cash flow from operations before changes in working capital |
$ |
236,927 |
$ |
309,664 |
$ |
737,691 |
$ |
869,758 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, |
September 30, | ||||||
2015 |
2016 | ||||||
Bank credit facilities |
$ |
1,327,000 |
$ |
775,000 | |||
6.00% AR senior notes due 2020 |
525,000 |
525,000 | |||||
5.375% AR senior notes due 2021 |
1,000,000 |
1,000,000 | |||||
5.125% AR senior notes due 2022 |
1,100,000 |
1,100,000 | |||||
5.625% AR senior notes due 2023 |
750,000 |
750,000 | |||||
5.375% AM senior notes due 2024 |
— |
650,000 | |||||
Net unamortized premium |
6,513 |
5,698 | |||||
Net unamortized debt issuance costs |
(39,731) |
(45,794) | |||||
Consolidated total debt |
$ |
4,668,782 |
$ |
4,759,904 | |||
Cash and cash equivalents |
23,473 |
18,512 | |||||
Consolidated net debt |
$ |
4,645,309 |
$ |
4,741,392 | |||
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income (loss) from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
Three months ended |
Nine months ended | ||||||||||||||||||||
September 30, |
September 30, | ||||||||||||||||||||
2015 |
2016 |
2015 |
2016 | ||||||||||||||||||
Net income (loss) from continuing operations including noncontrolling interest |
$ |
544,734 |
$ |
268,196 |
$ |
804,422 |
$ |
(296,644) | |||||||||||||
Commodity derivative fair value (gains) |
(1,079,071) |
(530,334) |
(1,836,398) |
(125,624) | |||||||||||||||||
Gains on settled derivative instruments |
205,919 |
196,712 |
586,639 |
813,559 | |||||||||||||||||
Interest expense |
60,921 |
59,755 |
173,929 |
185,634 | |||||||||||||||||
Income tax expense (benefit) |
335,460 |
140,924 |
498,709 |
(230,755) | |||||||||||||||||
Depreciation, depletion, amortization, and accretion |
189,086 |
199,741 |
549,240 |
589,903 | |||||||||||||||||
Impairment of unproved properties |
8,754 |
11,753 |
43,670 |
47,223 | |||||||||||||||||
Exploration expense |
1,087 |
1,166 |
3,086 |
3,289 | |||||||||||||||||
Equity-based compensation expense |
23,915 |
26,381 |
79,280 |
75,667 | |||||||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
(1,543) |
— |
(2,027) | |||||||||||||||||
State franchise taxes |
2 |
— |
131 |
39 | |||||||||||||||||
Contract termination and rig stacking |
— |
— |
10,902 |
— | |||||||||||||||||
Total Adjusted EBITDAX |
290,807 |
372,751 |
913,610 |
1,060,264 | |||||||||||||||||
Interest expense |
(60,921) |
(59,755) |
(173,929) |
(185,634) | |||||||||||||||||
Exploration expense |
(1,087) |
(1,166) |
(3,086) |
(3,289) | |||||||||||||||||
Changes in current assets and liabilities |
9,119 |
17,327 |
103,463 |
35,939 | |||||||||||||||||
State franchise taxes |
(2) |
— |
(131) |
(39) | |||||||||||||||||
Other non-cash items |
8,130 |
(2,166) |
1,227 |
(1,544) | |||||||||||||||||
Net cash provided by operating activities |
$ |
246,046 |
$ |
326,991 |
$ |
841,154 |
$ |
905,697 | |||||||||||||
Three months ended |
Nine months ended |
||||||||||||||||||||
September 30, |
September 30, |
||||||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2015 |
2016 |
2015 |
2016 |
|||||||||||||||||
Realized price before cash receipts for settled hedges |
$ |
2.34 |
$ |
2.82 |
$ |
2.59 |
$ |
2.36 |
|||||||||||||
Gathering, compression, and water handling and treatment revenues |
0.04 |
0.01 |
0.02 |
0.03 |
|||||||||||||||||
Lease operating expense |
(0.08) |
(0.08) |
(0.06) |
(0.08) |
|||||||||||||||||
Gathering, compression, processing and transportation costs |
(1.16) |
(1.36) |
(1.20) |
(1.32) |
|||||||||||||||||
Marketing, net |
(0.19) |
(0.10) |
(0.17) |
(0.19) |
|||||||||||||||||
Production and ad valorem taxes |
(0.08) |
(0.09) |
(0.14) |
(0.11) |
|||||||||||||||||
General and administrative(1) |
(0.26) |
(0.18) |
(0.24) |
(0.20) |
|||||||||||||||||
Adjusted EBITDAX margin before settled hedges |
0.61 |
1.02 |
0.80 |
0.49 |
|||||||||||||||||
Cash receipts for settled hedges |
1.49 |
1.14 |
1.44 |
1.66 |
|||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.10 |
$ |
2.16 |
$ |
2.24 |
$ |
2.15 |
|||||||||||||
(1) Excludes equity-based stock compensation that is included in G&A |
|||||||||||||||||||||
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Balance Sheets | ||||||
December 31, 2015 and September 30, 2016 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
December 31, 2015 |
September 30, 2016 | |||||
Assets | ||||||
Current assets: |
||||||
Cash and cash equivalents |
$ |
23,473 |
18,512 | |||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016 |
79,404 |
59,462 | ||||
Accrued revenue |
128,242 |
196,490 | ||||
Derivative instruments |
1,009,030 |
417,605 | ||||
Other current assets |
8,087 |
3,402 | ||||
Total current assets |
1,248,236 |
695,471 | ||||
Property and equipment: |
||||||
Natural gas properties, at cost (successful efforts method): |
||||||
Unproved properties |
1,996,081 |
2,449,995 | ||||
Proved properties |
8,211,106 |
9,180,705 | ||||
Water handling and treatment systems |
565,616 |
681,062 | ||||
Gathering systems and facilities |
1,502,396 |
1,656,676 | ||||
Other property and equipment |
46,415 |
45,571 | ||||
12,321,614 |
14,014,009 | |||||
Less accumulated depletion, depreciation, and amortization |
(1,589,372) |
(2,176,793) | ||||
Property and equipment, net |
10,732,242 |
11,837,216 | ||||
Derivative instruments |
2,108,450 |
2,015,090 | ||||
Other assets |
26,565 |
81,476 | ||||
Total assets |
$ |
14,115,493 |
14,629,253 | |||
Liabilities and Equity | ||||||
Current liabilities: |
||||||
Accounts payable |
$ |
364,160 |
172,293 | |||
Accrued liabilities |
194,076 |
245,174 | ||||
Revenue distributions payable |
129,949 |
172,202 | ||||
Derivative instruments |
— |
3,110 | ||||
Other current liabilities |
19,085 |
19,125 | ||||
Total current liabilities |
707,270 |
611,904 | ||||
Long-term liabilities: |
||||||
Long-term debt |
4,668,782 |
4,759,904 | ||||
Deferred income tax liability |
1,370,686 |
1,215,240 | ||||
Derivative instruments |
— |
40 | ||||
Other liabilities |
82,077 |
61,883 | ||||
Total liabilities |
6,828,815 |
6,648,971 | ||||
Commitments and contingencies |
||||||
Equity: |
||||||
Stockholders' equity: |
||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 277,036 shares and 307,188 shares, respectively |
2,770 |
3,072 | ||||
Additional paid-in capital |
4,122,811 |
5,131,909 | ||||
Accumulated earnings |
1,808,811 |
1,445,767 | ||||
Total stockholders' equity |
5,934,392 |
6,580,748 | ||||
Noncontrolling interest in consolidated subsidiary |
1,352,286 |
1,399,534 | ||||
Total equity |
7,286,678 |
7,980,282 | ||||
Total liabilities and equity |
$ |
14,115,493 |
14,629,253 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Operations and Comprehensive Income | ||||||
Three Months Ended September 30, 2015 and 2016 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
Three Months Ended September 30, | ||||||
2015 |
2016 | |||||
Revenue: |
||||||
Natural gas sales |
$ |
253,975 |
364,373 | |||
Natural gas liquids sales |
50,092 |
106,958 | ||||
Oil sales |
20,138 |
14,793 | ||||
Gathering, compression, and water handling and treatment |
4,426 |
2,969 | ||||
Marketing |
35,633 |
97,076 | ||||
Commodity derivative fair value gains |
1,079,071 |
530,334 | ||||
Total revenue |
1,443,335 |
1,116,503 | ||||
Operating expenses: |
||||||
Lease operating |
10,786 |
13,854 | ||||
Gathering, compression, processing, and transportation |
160,302 |
234,915 | ||||
Production and ad valorem taxes |
10,721 |
15,554 | ||||
Marketing |
61,799 |
114,611 | ||||
Exploration |
1,087 |
1,166 | ||||
Impairment of unproved properties |
8,754 |
11,753 | ||||
Depletion, depreciation, and amortization |
188,667 |
199,113 | ||||
Accretion of asset retirement obligations |
419 |
628 | ||||
General and administrative (including equity-based compensation expense of $23,915 and $26,381 in 2015 and 2016, respectively) |
59,685 |
57,577 | ||||
Total operating expenses |
502,220 |
649,171 | ||||
Operating income |
941,115 |
467,332 | ||||
Other income (expenses): |
||||||
Equity in earnings of unconsolidated affiliate |
— |
1,543 | ||||
Interest |
(60,921) |
(59,755) | ||||
Total other expenses |
(60,921) |
(58,212) | ||||
Income before income taxes |
880,194 |
409,120 | ||||
Provision for income tax expense |
(335,460) |
(140,924) | ||||
Net income and comprehensive income including noncontrolling interest |
544,734 |
268,196 | ||||
Net income and comprehensive income attributable to noncontrolling interest |
10,892 |
29,941 | ||||
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
533,842 |
238,255 | |||
Earnings per common share—basic |
$ |
1.93 |
0.78 | |||
Earnings per common share—assuming dilution |
$ |
1.93 |
0.77 | |||
Weighted average number of shares outstanding: |
||||||
Basic |
277,007 |
306,785 | ||||
Diluted |
277,015 |
308,657 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | ||||||
Nine Months Ended September 30, 2015 and 2016 | ||||||
(unaudited) | ||||||
(In thousands, except per share amounts) | ||||||
Nine Months Ended September 30, | ||||||
2015 |
2016 | |||||
Revenue: |
||||||
Natural gas sales |
$ |
810,982 |
848,936 | |||
Natural gas liquids sales |
188,403 |
274,736 | ||||
Oil sales |
55,627 |
41,712 | ||||
Gathering, compression, and water handling and treatment |
15,084 |
10,107 | ||||
Marketing |
143,242 |
287,194 | ||||
Commodity derivative fair value gains |
1,836,398 |
125,624 | ||||
Total revenue |
3,049,736 |
1,588,309 | ||||
Operating expenses: |
||||||
Lease operating |
25,561 |
37,190 | ||||
Gathering, compression, processing, and transportation |
490,633 |
649,713 | ||||
Production and ad valorem taxes |
57,458 |
52,296 | ||||
Marketing |
214,201 |
378,521 | ||||
Exploration |
3,086 |
3,289 | ||||
Impairment of unproved properties |
43,670 |
47,223 | ||||
Depletion, depreciation, and amortization |
548,013 |
588,057 | ||||
Accretion of asset retirement obligations |
1,227 |
1,846 | ||||
General and administrative (including equity-based compensation expense of $79,280 and $75,667 in 2015 and 2016, respectively) |
177,925 |
173,966 | ||||
Contract termination and rig stacking |
10,902 |
— | ||||
Total operating expenses |
1,572,676 |
1,932,101 | ||||
Operating income (loss) |
1,477,060 |
(343,792) | ||||
Other income (expenses): |
||||||
Equity in earnings of unconsolidated affiliate |
— |
2,027 | ||||
Interest |
(173,929) |
(185,634) | ||||
Total other expenses |
(173,929) |
(183,607) | ||||
Income (loss) before income taxes |
1,303,131 |
(527,399) | ||||
Provision for income tax (expense) benefit |
(498,709) |
230,755 | ||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
804,422 |
(296,644) | ||||
Net income and comprehensive income attributable to noncontrolling interest |
21,522 |
66,400 | ||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
782,900 |
(363,044) | |||
Earnings (loss) per common share—basic |
$ |
2.87 |
(1.26) | |||
Earnings (loss) per common share—assuming dilution |
$ |
2.87 |
(1.26) | |||
Weighted average number of shares outstanding: |
||||||
Basic |
273,145 |
288,607 | ||||
Diluted |
273,154 |
288,607 |
ANTERO RESOURCES CORPORATION | ||||||
Condensed Consolidated Statements of Cash Flows | ||||||
Nine Months Ended September 30, 2015 and 2016 | ||||||
(unaudited) | ||||||
(In thousands) | ||||||
Nine Months Ended September 30, | ||||||
2015 |
2016 | |||||
Cash flows from operating activities: |
||||||
Net income (loss) including noncontrolling interest |
$ |
804,422 |
(296,644) | |||
Adjustment to reconcile net income to net cash provided by operating activities: |
||||||
Depletion, depreciation, amortization, and accretion |
549,240 |
589,903 | ||||
Impairment of unproved properties |
43,670 |
47,223 | ||||
Derivative fair value gains |
(1,836,398) |
(125,624) | ||||
Gains on settled derivatives |
586,639 |
813,559 | ||||
Deferred income tax expense (benefit) |
498,709 |
(230,755) | ||||
Equity-based compensation expense |
79,280 |
75,667 | ||||
Equity in earnings of unconsolidated affiliate |
— |
(2,027) | ||||
Other |
12,129 |
(1,544) | ||||
Changes in current assets and liabilities: |
||||||
Accounts receivable |
15,299 |
10,077 | ||||
Accrued revenue |
75,765 |
(68,248) | ||||
Other current assets |
4,127 |
4,685 | ||||
Accounts payable |
(1,302) |
(7,415) | ||||
Accrued liabilities |
34,091 |
54,484 | ||||
Revenue distributions payable |
(20,839) |
42,253 | ||||
Other current liabilities |
(3,678) |
103 | ||||
Net cash provided by operating activities |
841,154 |
905,697 | ||||
Cash flows used in investing activities: |
||||||
Additions to proved properties |
— |
(64,789) | ||||
Additions to unproved properties |
(170,291) |
(559,572) | ||||
Drilling and completion costs |
(1,350,498) |
(1,009,851) | ||||
Additions to water handling and treatment systems |
(79,227) |
(137,355) | ||||
Additions to gathering systems and facilities |
(282,813) |
(154,136) | ||||
Additions to other property and equipment |
(5,225) |
(1,747) | ||||
Investment in unconsolidated affiliate |
— |
(45,044) | ||||
Change in other assets |
11,190 |
(2,173) | ||||
Proceeds from asset sales |
40,000 |
— | ||||
Net cash used in investing activities |
(1,836,864) |
(1,974,667) | ||||
Cash flows from financing activities: |
||||||
Issuance of common stock |
537,832 |
837,414 | ||||
Issuance of common units by Antero Midstream Partners LP |
240,972 |
19,605 | ||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
— |
178,000 | ||||
Issuance of senior notes |
750,000 |
650,000 | ||||
Repayments on bank credit facilities, net |
(705,000) |
(552,000) | ||||
Payments of deferred financing costs |
(17,190) |
(9,029) | ||||
Distributions to noncontrolling interest in consolidated subsidiary |
(21,358) |
(51,238) | ||||
Employee tax withholding for settlement of equity compensation awards |
(4,554) |
(4,876) | ||||
Other |
(3,561) |
(3,867) | ||||
Net cash provided by financing activities |
777,141 |
1,064,009 | ||||
Net decrease in cash and cash equivalents |
(218,569) |
(4,961) | ||||
Cash and cash equivalents, beginning of period |
245,979 |
23,473 | ||||
Cash and cash equivalents, end of period |
$ |
27,410 |
18,512 | |||
Supplemental disclosure of cash flow information: |
||||||
Cash paid during the period for interest |
$ |
116,579 |
132,928 | |||
Supplemental disclosure of noncash investing activities: |
||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
$ |
(193,288) |
(189,234) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended September 30, 2015 compared to the three months ended September 30, 2016:
Three Months Ended September 30, |
Amount of |
Percent |
||||||||||||||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||||||||||||||
Operating revenues: |
||||||||||||||||||||||||
Natural gas sales |
$ |
253,975 |
$ |
364,373 |
$ |
110,398 |
43 |
% |
||||||||||||||||
NGLs sales |
50,092 |
106,958 |
56,866 |
114 |
% |
|||||||||||||||||||
Oil sales |
20,138 |
14,793 |
(5,345) |
(27) |
% |
|||||||||||||||||||
Gathering, compression, and water handling and treatment |
4,426 |
2,969 |
(1,457) |
(33) |
% |
|||||||||||||||||||
Marketing |
35,633 |
97,076 |
61,443 |
172 |
% |
|||||||||||||||||||
Commodity derivative fair value gains |
1,079,071 |
530,334 |
(548,737) |
(51) |
% |
|||||||||||||||||||
Total operating revenues |
1,443,335 |
1,116,503 |
(326,832) |
(23) |
% |
|||||||||||||||||||
Operating expenses: |
||||||||||||||||||||||||
Lease operating |
10,786 |
13,854 |
3,068 |
28 |
% |
|||||||||||||||||||
Gathering, compression, processing, and transportation |
160,302 |
234,915 |
74,613 |
47 |
% |
|||||||||||||||||||
Production and ad valorem taxes |
10,721 |
15,554 |
4,833 |
45 |
% |
|||||||||||||||||||
Marketing |
61,799 |
114,611 |
52,812 |
85 |
% |
|||||||||||||||||||
Exploration |
1,087 |
1,166 |
79 |
7 |
% |
|||||||||||||||||||
Impairment of unproved properties |
8,754 |
11,753 |
2,999 |
34 |
% |
|||||||||||||||||||
Depletion, depreciation, and amortization |
188,667 |
199,113 |
10,446 |
6 |
% |
|||||||||||||||||||
Accretion of asset retirement obligations |
419 |
628 |
209 |
50 |
% |
|||||||||||||||||||
General and administrative (before equity-based compensation) |
35,770 |
31,196 |
(4,574) |
(13) |
% |
|||||||||||||||||||
Equity-based compensation |
23,915 |
26,381 |
2,466 |
10 |
% |
|||||||||||||||||||
Total operating expenses |
502,220 |
649,171 |
146,951 |
29 |
% |
|||||||||||||||||||
Operating income |
941,115 |
467,332 |
(473,783) |
(50) |
% |
|||||||||||||||||||
Other earnings (expenses): |
||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
1,543 |
1,543 |
* |
||||||||||||||||||||
Interest expense |
(60,921) |
(59,755) |
1,166 |
(2) |
% |
|||||||||||||||||||
Income before income taxes |
880,194 |
409,120 |
(471,074) |
(54) |
% |
|||||||||||||||||||
Income tax expense |
(335,460) |
(140,924) |
194,536 |
(58) |
% |
|||||||||||||||||||
Net income and comprehensive income including noncontrolling interest |
544,734 |
268,196 |
(276,538) |
(51) |
% |
|||||||||||||||||||
Net income and comprehensive income attributable to noncontrolling interest |
10,892 |
29,941 |
19,049 |
175 |
% |
|||||||||||||||||||
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
533,842 |
$ |
238,255 |
$ |
(295,587) |
(55) |
% |
||||||||||||||||
Adjusted EBITDAX |
$ |
290,807 |
$ |
372,751 |
$ |
81,944 |
28 |
% |
||||||||||||||||
Three Months Ended September 30, |
Amount of |
Percent |
||||||||||||||||||||||
2015 |
2016 |
(Decrease) |
Change |
|||||||||||||||||||||
Production data: |
||||||||||||||||||||||||
Natural gas (Bcf) |
110 |
128 |
18 |
16 |
% | |||||||||||||||||||
C2 Ethane (MBbl) |
— |
1,801 |
1,801 |
* |
||||||||||||||||||||
C3+ NGLs (MBbl) |
4,147 |
5,270 |
1,123 |
27 |
% | |||||||||||||||||||
Oil (MBbl) |
660 |
423 |
(237) |
(36) |
% | |||||||||||||||||||
Combined (Bcfe) |
139 |
172 |
33 |
25 |
% | |||||||||||||||||||
Daily combined production (MMcfe/d) |
1,506 |
1,875 |
369 |
25 |
% | |||||||||||||||||||
Average prices before effects of derivative settlements: |
||||||||||||||||||||||||
Natural gas (per Mcf) |
$ |
2.32 |
$ |
2.86 |
$ |
0.54 |
23 |
% | ||||||||||||||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
8.00 |
$ |
* |
* |
|||||||||||||||||
C3+ NGLs (per Bbl) |
$ |
12.08 |
$ |
17.56 |
$ |
5.48 |
45 |
% | ||||||||||||||||
Oil (per Bbl) |
$ |
30.49 |
$ |
34.93 |
$ |
4.44 |
15 |
% | ||||||||||||||||
Combined (per Mcfe) |
$ |
2.34 |
$ |
2.82 |
$ |
0.48 |
21 |
% | ||||||||||||||||
Average realized prices after effects of derivative settlements: |
||||||||||||||||||||||||
Natural gas (per Mcf) |
$ |
3.99 |
$ |
4.30 |
$ |
0.31 |
8 |
% | ||||||||||||||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
8.00 |
$ |
* |
* |
|||||||||||||||||
C3+ NGLs (per Bbl) |
$ |
16.47 |
$ |
19.96 |
$ |
3.49 |
21 |
% | ||||||||||||||||
Oil (per Bbl) |
$ |
38.18 |
$ |
34.93 |
$ |
(3.25) |
(9) |
% | ||||||||||||||||
Combined (per Mcfe) |
$ |
3.83 |
$ |
3.96 |
$ |
0.13 |
3 |
% | ||||||||||||||||
Average Costs (per Mcfe): |
||||||||||||||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.08 |
$ |
— |
* |
|||||||||||||||||
Gathering, compression, processing, and transportation |
$ |
1.16 |
$ |
1.36 |
$ |
0.20 |
17 |
% | ||||||||||||||||
Production and ad valorem taxes |
$ |
0.08 |
$ |
0.09 |
$ |
0.01 |
13 |
% | ||||||||||||||||
Marketing, net |
$ |
0.19 |
$ |
0.10 |
$ |
(0.09) |
(47) |
% | ||||||||||||||||
Depletion, depreciation, amortization, and accretion |
$ |
1.37 |
$ |
1.16 |
$ |
(0.21) |
(15) |
% | ||||||||||||||||
General and administrative (before equity-based compensation) |
$ |
0.26 |
$ |
0.18 |
$ |
(0.08) |
(31) |
% |
*Not meaningful or applicable |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the Nine months ended September 30, 2015 compared to the Nine months ended September 30, 2016:
Nine Months Ended September 30, |
Amount of |
Percent |
||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||
Operating revenues: |
||||||||||||
Natural gas sales |
$ |
810,982 |
$ |
848,936 |
$ |
37,954 |
5 |
% | ||||
NGLs sales |
188,403 |
274,736 |
86,333 |
46 |
% | |||||||
Oil sales |
55,627 |
41,712 |
(13,915) |
(25) |
% | |||||||
Gathering, compression, and water handling and treatment |
15,084 |
10,107 |
(4,977) |
(33) |
% | |||||||
Marketing |
143,242 |
287,194 |
143,952 |
100 |
% | |||||||
Commodity derivative fair value gains |
1,836,398 |
125,624 |
(1,710,774) |
(93) |
% | |||||||
Total operating revenues |
3,049,736 |
1,588,309 |
(1,461,427) |
(48) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
25,561 |
37,190 |
11,629 |
45 |
% | |||||||
Gathering, compression, processing, and transportation |
490,633 |
649,713 |
159,080 |
32 |
% | |||||||
Production and ad valorem taxes |
57,458 |
52,296 |
(5,162) |
(9) |
% | |||||||
Marketing |
214,201 |
378,521 |
164,320 |
77 |
% | |||||||
Exploration |
3,086 |
3,289 |
203 |
7 |
% | |||||||
Impairment of unproved properties |
43,670 |
47,223 |
3,553 |
8 |
% | |||||||
Depletion, depreciation, and amortization |
548,013 |
588,057 |
40,044 |
7 |
% | |||||||
Accretion of asset retirement obligations |
1,227 |
1,846 |
619 |
50 |
% | |||||||
General and administrative (before equity-based compensation) |
98,645 |
98,299 |
(346) |
* |
||||||||
Equity-based compensation |
79,280 |
75,667 |
(3,613) |
(5) |
% | |||||||
Contract termination and rig stacking |
10,902 |
— |
(10,902) |
* |
||||||||
Total operating expenses |
1,572,676 |
1,932,101 |
359,425 |
23 |
% | |||||||
Operating income (loss) |
1,477,060 |
(343,792) |
(1,820,852) |
* |
||||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
2,027 |
2,027 |
* |
||||||||
Interest expense |
(173,929) |
(185,634) |
(11,705) |
7 |
% | |||||||
Income (loss) before income taxes |
1,303,131 |
(527,399) |
(1,830,530) |
* |
||||||||
Income tax (expense) benefit |
(498,709) |
230,755 |
729,464 |
* |
||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
804,422 |
(296,644) |
(1,101,066) |
* |
||||||||
Net income and comprehensive income attributable to noncontrolling interest |
21,522 |
66,400 |
44,878 |
209 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
782,900 |
$ |
(363,044) |
$ |
(1,145,944) |
* |
|||||
Adjusted EBITDAX |
$ |
913,610 |
$ |
1,060,264 |
$ |
146,654 |
16 |
% |
Nine Months Ended September 30, |
Amount of |
Percent |
||||||||||
2015 |
2016 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
332 |
369 |
37 |
11 |
% | |||||||
C2 Ethane (MBbl) |
— |
4,463 |
4,463 |
* |
||||||||
C3+ NGLs (MBbl) |
11,042 |
14,722 |
3,680 |
33 |
% | |||||||
Oil (MBbl) |
1,549 |
1,373 |
(176) |
(11) |
% | |||||||
Combined (Bcfe) |
407 |
493 |
86 |
21 |
% | |||||||
Daily combined production (MMcfe/d) |
1,492 |
1,799 |
307 |
21 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.45 |
$ |
2.30 |
$ |
(0.15) |
(6) |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
7.81 |
$ |
* |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
17.06 |
$ |
16.29 |
$ |
(0.77) |
(5) |
% | ||||
Oil (per Bbl) |
$ |
35.91 |
$ |
30.38 |
$ |
(5.53) |
(15) |
% | ||||
Combined (per Mcfe) |
$ |
2.59 |
$ |
2.36 |
$ |
(0.23) |
(9) |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.07 |
$ |
4.38 |
$ |
0.31 |
8 |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
7.81 |
$ |
* |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
20.34 |
$ |
19.30 |
$ |
(1.04) |
(5) |
% | ||||
Oil (per Bbl) |
$ |
42.90 |
$ |
30.38 |
$ |
(12.52) |
(29) |
% | ||||
Combined (per Mcfe) |
$ |
4.03 |
$ |
4.02 |
$ |
(0.01) |
* |
|||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.06 |
$ |
0.08 |
$ |
0.02 |
33 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.20 |
$ |
1.32 |
$ |
0.12 |
10 |
% | ||||
Production and ad valorem taxes |
$ |
0.14 |
$ |
0.11 |
$ |
(0.03) |
(21) |
% | ||||
Marketing, net |
$ |
0.17 |
$ |
0.19 |
$ |
0.02 |
12 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.35 |
$ |
1.20 |
$ |
(0.15) |
(11) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.24 |
$ |
0.20 |
$ |
(0.04) |
(17) |
% |
*Not meaningful or applicable |
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SOURCE Antero Resources Corporation
DENVER, Oct. 12, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") announced today that the Company plans to issue its third quarter 2016 earnings release on Wednesday, October 26, 2016 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, October 27, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, November 4, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10091479.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, November 4, 2016 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
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SOURCE Antero Resources
DENVER, Sept. 6, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced updates to its 2016 production guidance and 2017 production growth target.
Highlights Include:
Updated 2016 Guidance
Driven by the successful execution of Antero's development program to date, along with encouraging results from the implementation of advanced completion techniques, the Company is raising 2016 net production guidance from 1.75 Bcfe/d to 1.8 Bcfe/d. This represents a 3% increase from the previously announced guidance and a 5% increase from initial 2016 guidance. Additionally, the Company is maintaining its original drilling and completion capex budget of $1.3 billion. The increase in gas equivalent production guidance includes an increase in liquids production to 73,000 Bbl/d, or an 11% increase from previous guidance and a 22% increase from initial 2016 guidance. Antero will continue to target 20% to 25% growth in 2017 off of the increased 2016 production guidance, representing a 3% increase from the previously announced target and a targeted growth rate of 29% over initial 2016 production guidance.
The increase in production guidance in conjunction with an unchanged drilling and completion budget is primarily a function of the improved recoveries and drilling efficiencies Antero has achieved throughout the year. The improved recoveries are driven by Antero's advanced completions, which have utilized 1,200 to 1,500 pounds of proppant per foot, with recent pilots utilizing as much as 1,750 to 2,000 pounds of proppant per foot. These techniques have yielded encouraging results with wellhead EURs ranging from 2.0 to 2.3 Bcf per 1,000' of lateral as compared to the Company's 1.7 Bcf per 1,000' type curve. The drilling efficiencies include a reduction in drilling days, increases in stages completed per day and drilling longer laterals.
Throughout 2016, Antero has operated an average of six rigs in the Marcellus and one rig in the Utica, while placing 78 total wells to sales. Of the 52 wells Antero has completed in the Marcellus, 29 have used greater than 1,300 pounds of proppant per foot and have generated aggregated production in excess of the Company's current 1.7 Bcf/1,000 type curve and 2.0 Bcf/1,000 target through 140 days.
Commenting on these cost reductions and well recovery improvements, Paul Rady, Chairman and CEO, said, "As the most active operator in Appalachia, we have benefited from our ability to maintain operating momentum through the current downturn, leveraging our activity into exceptional operational improvements. We continue to see improved well costs and performance in 2016, reducing our drilling and completion cost per 1,000 foot of lateral by 33% in both the Marcellus and the Utica since 2014 and our net development costs per Mcfe by 47% and 44% in the Marcellus and Utica, respectively since 2014. While these early results are impressive, we feel there is even more room for improvement going forward through increased proppant and water intensity, longer laterals and decreased drilling days."
Mr. Rady further added, "Looking ahead to the remainder of 2016, we expect production to average 1.84 Bcfe/d in the second half of the year and plan to reaccelerate activity late in the year and build further momentum as we head into 2017. While we have seen a modest benefit from the increased recoveries from our 2016 development, we expect greater contribution in 2017 as more wells with advanced completions are brought online, while still maintaining a similar drilling and completion budget year-over-year."
The following is a comparison of the original 2016 guidance issued in January 2016, previous 2016 guidance issued in June 2016, and the revised 2016 guidance.
2016 Guidance Comparison |
September 2016 Revised |
June 2016 Previous |
January 2016 Original |
Total net production (MMcfe/d) |
1,800 |
1,750 |
1,715 |
Net natural gas production (MMcf/d) |
1,365 |
1,355 |
1,355 |
Net liquids production (Bbl/d) |
73,000 |
66,000 |
60,000 |
Net Daily C3+ NGL Production (Bbl/d) |
53,500 |
52,500 |
46,500 |
Net Daily Ethane Production (Bbl/d) |
15,000 |
10,000 |
10,000 |
Net Daily Oil Production (Bbl/d) |
4,500 |
3,500 |
3,500 |
Cash production expense ($/Mcfe) (1) |
$1.40 – $1.50 |
$1.50 – $1.60 |
$1.50 – $1.60 |
Marketing expense, net ($/Mcfe) |
$0.15 – $0.20 |
$0.15 – $0.20 |
$0.15 – $0.20 |
G&A ($/Mcfe) |
$0.20 – $0.22 |
$0.20 – $0.25 |
$0.20 – $0.25 |
Natural gas realized price premium to Nymex before hedging($/Mcf)(2)(3) |
$0.00 – $0.05 |
$0.00 – $0.10 |
$0.00 – $0.10 |
Natural gas liquids realized price (% of WTI) |
35% – 40% |
35% – 40% |
35% – 40% |
Oil realized price differential to NYMEX before hedging ($/Bbl) |
$(10.00) – $(11.00) |
$(10.00) – $(11.00) |
$(10.00) – $(11.00) |
2017 Net Production Target (MMcfe/d) |
2,160 – 2,250 |
2,100 – 2,190 |
2,060 |
2016 Capital Budget Comparison |
|||
Drilling & completion ($MM) |
$1,300 |
$1,300 |
$1,300 |
Land ($MM) |
$100 |
$100 |
$100 |
Total |
$1,400 |
$1,400 |
$1,400 |
Operated wells completed |
110 |
110 |
110 |
Average drilling rigs |
7 |
7 |
7 |
(1) |
Includes lease operating, gathering, compression, processing and transportation and production and ad valorem taxes |
(2) |
Based on strip pricing as of August 31, 2016 |
(3) |
Includes Btu upgrade as Antero's processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
"EUR," or Estimated Ultimate Recovery, refers to Antero's internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer's Resource Management System or the SEC's oil and natural gas disclosure rules.
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SOURCE Antero Resources Corporation
DENVER, Aug. 2, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its second quarter 2016 financial results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, which has been filed with the Securities and Exchange Commission.
Highlights Include:
Second Quarter 2016 Financial Results
As of June 30, 2016, Antero owned a 62% limited partner interest in Antero Midstream Partners LP's ("Antero Midstream"). Antero Midstream's results are consolidated with Antero's results.
For the three months ended June 30, 2016, the Company reported a GAAP net loss of $596 million, or $(2.12) per basic and diluted share, compared to a GAAP net loss of $145 million, or $(0.52) per basic and diluted share, in the second quarter of 2015. The GAAP net loss for the second quarter of 2016 included the following items:
Without the effect of these items, the Company's results for the second quarter of 2016 were as follows:
For a description of adjusted net income, adjusted EBITDAX and cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the second quarter of 2016 averaged 1,762 MMcfe/d, including 75,041 Bbl/d of liquids (26% liquids). Second quarter 2016 production represents an organic production growth rate of 19% from the second quarter of 2015 and flat compared to the first quarter of 2016. During the second quarter, Antero shut in 7.3 Bcfe, representing 80 MMcfe/d of production for the quarter due to operational downtime in late June at the Sherwood Processing Plant in West Virginia. Antero currently has no production shut in. Second quarter 2016 C3+ natural gas liquids ("NGLs") and oil production averaged 52,424 Bbl/d and 5,244 Bbl/d, respectively, while ethane (C2) production averaged 17,373 Bbl/d. Total liquids production for the second quarter of 2016 represents an organic production growth rate of 63% and 10% from the second quarter of 2015 and first quarter of 2016, respectively.
Antero's average natural gas price before hedging decreased 12% from the prior year quarter to $1.93 per Mcf, a $0.02 per Mcf negative differential to Nymex, as Nymex natural gas prices decreased 26% from the prior year quarter. Approximately 99% of Antero's second quarter 2016 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Tennessee Gulf and Nymex. Antero's average realized natural gas price after hedging for the second quarter of 2016 was $4.31 per Mcf, a $2.36 premium to the Nymex average price for the period. This represents a 12% increase compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $283 million, or $2.38 per Mcf.
The Company's average realized C3+ NGL price before hedging for the second quarter of 2016 was $17.08 per barrel, or 38% of the Nymex WTI oil price, which represents a 5% increase as compared to the prior year quarter. Average realized oil price was $35.08 per barrel, a 20% decrease as compared to the second quarter of 2015 due to a 21% decrease in the Nymex WTI oil price. Antero's average realized ethane price for the second quarter of 2016 was $8.36 per barrel, or $0.20 per gallon. Antero's average realized C3+ NGL price including hedges was $18.98 per barrel, or $0.45 per gallon, a 3% decrease as compared to the second quarter of 2015.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, decreased from the prior year quarter by 11% to $2.13 per Mcfe due to a 21% decline in Nymex WTI and a 26% decline in Nymex natural gas prices. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, increased by 3% to $3.95 per Mcfe for the second quarter of 2016 as compared to the second quarter of 2015. For the second quarter of 2016, Antero realized a hedge settlement gain of $293 million, or $1.82 per Mcfe.
Total operating revenue for the second quarter of 2016 was $(249) million as compared to $377 million for the second quarter of 2015. Operating revenue for the second quarter of 2016 included a $977 million non-cash loss on unsettled hedges, while the second quarter of 2015 included a $198 million non-cash loss on unsettled hedges. In both periods, the non-cash loss on unsettled hedges was driven by increasing natural gas prices during the period. Revenue excluding the unrealized hedge loss was $728 million, a 27% increase compared to the second quarter of 2015. Liquids production contributed 33% of total revenue before hedges in the second quarter of 2016, as compared to a 25% contribution for the prior year quarter. For a reconciliation of revenue excluding unrealized hedge (gains) losses to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the second quarter of 2016 was $91 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee Gas Pipeline. Marketing expense for the second quarter of 2016 was $126 million. The largest components of marketing expense were the costs related to excess capacity and the cost of purchasing third party gas. Combining the two, net marketing expense was $35 million or $0.22 per Mcfe for the second quarter of 2016. For the second half of 2016, due to a third party contractual commitment effective July, 1, 2016, Antero has released to a third party certain unutilized firm transportation capacity and the costs associated with the unutilized capacity. As a result of the reduction in marketing expense, Antero expects net marketing expense to decrease to a range of $0.10 to $0.15 per Mcfe for the second half of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production tax) for the second quarter of 2016 was $1.48 per Mcfe, a 2% increase compared to $1.45 per Mcfe in the prior year quarter. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.29 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the second quarter of 2016, excluding non-cash equity-based compensation expense, was $0.21 per Mcfe, a 9% decrease from the second quarter of 2015. The significant per unit decrease in general and administrative expenses was primarily driven by the increase in production. Per unit depreciation, depletion and amortization expense decreased 6% from the prior year quarter to $1.23 per Mcfe, primarily driven by lower development costs.
Adjusted EBITDAX of $332 million for the second quarter of 2016 represents a 24% increase compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $2.06 per Mcfe, representing a 4% increase from the prior year quarter. For the second quarter of 2016, cash flow from operations before changes in working capital was $269 million, a 29% increase from the prior year quarter.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, and cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the second quarter of 2016 averaged 1,353 MMcf/d, a 40% increase from the second quarter of 2015 and a 4% increase sequentially. High pressure gathering volumes for the second quarter of 2016 averaged 1,253 MMcf/d, a 5% increase from the second quarter of 2015 and a 3% increase sequentially. Compression volumes for the second quarter of 2016 averaged 658 MMcf/d, a 45% increase from the second quarter of 2015 and a 9% increase sequentially. The increase in gathering and compression volumes was due to production growth from Antero in Antero Midstream's area of dedication. Condensate gathering volumes averaged 1,983 Bbl/d during the quarter, a 34% decrease compared to the prior year quarter and a 33% decrease sequentially. The sequential decrease in condensate gathering volumes was driven by Antero shifting Ohio Utica Shale development from its Highly-Rich Gas/Condensate area to higher rate of return drilling in the Highly-Rich Gas area, as well as the shifting of Antero Resources' development program to the Marcellus Shale from the Utica Shale, due to firm transportation constraints to premium markets in the Utica Shale. Fresh water delivery volumes averaged 105,379 Bbl/d during the quarter, an 11% increase compared to the prior year quarter and an 8% increase sequentially. The increase in fresh water delivery volumes was driven by operational efficiencies leading to accelerated Marcellus completions and an increase in the average water used per foot in completions to 41 barrels, a 25% increase as compared to 2015 and an 11% increase compared to the first quarter of 2016.
For the three months ended June 30, 2016, the Partnership reported revenues of $137 million. Revenues increased 55% compared to the prior year quarter, primarily driven by the startup of produced water handling and high rate transfer services in the first quarter of 2016. Direct operating expenses for the three months ended June 30, 2016 were $43 million. Direct operating expenses increased 138% year over year, driven primarily by the inclusion of produced water handling and high rate water transfer services, as well as the expansion of Antero Midstream's gathering and compression and fresh water delivery assets to support the production growth of Antero Resources. General and administrative expenses were $7 million during the second quarter of 2016, an increase of 17% compared to the second quarter of 2015. Total cash and non-cash operating expenses were $84 million, including $24 million of depreciation, $7 million of equity-based compensation, and $3 million of accretion of contingent acquisition consideration.
The Board of Directors of Antero Resources Midstream Management LLC, the general partner of Antero Midstream, declared a cash distribution of $0.25 per unit ($1.00 per unit annualized) for the second quarter of 2016. The distribution represents a 32% increase compared to the prior year quarter and a 6% increase sequentially. The distribution is Antero Midstream's sixth consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on August 24, 2016 to unitholders of record as of August 10, 2016.
Balance Sheet and Liquidity
As of June 30, 2016, Antero's consolidated total debt and consolidated net debt were $4.2 billion, of which $900 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total lender commitments under these two facilities are currently $5.5 billion. Including $708 million in letters of credit outstanding, the company had $3.9 billion in available consolidated liquidity as of June 30, 2016. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Second Quarter 2016 Capital Spending
Antero's drilling and completion costs for the three months ended June 30, 2016 were $315 million. In addition, the Company invested $30 million for land and $1 million in other capital projects. Antero Midstream invested $48 million for gathering and compression systems and $42 million for water infrastructure projects including $33 million on the Antero Clearwater treatment facility during the quarter.
Hedge Position
Antero currently has hedged 3.4 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from July 1, 2016 through December 31, 2022 at an average index price of $3.71 per MMBtu.
The following table summarizes Antero's hedge positions held as of June 30, 2016:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
3Q 2016: |
||||||
TCO |
60,000 |
$4.81 |
— |
— | ||
Nymex HH |
1,110,000 |
$3.44 |
— |
— | ||
Dom South |
272,500 |
$5.24 |
— |
— | ||
CGTLA |
170,000 |
$4.03 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.58 | ||
3Q 2016 Total |
1,612,500 |
$3.86 |
30,000 |
$0.58 | ||
4Q 2016: |
||||||
TCO |
60,000 |
$5.01 |
— |
— | ||
Nymex HH |
1,110,000 |
$3.57 |
— |
— | ||
Dom South |
272,500 |
$5.47 |
— |
— | ||
CGTLA |
170,000 |
$4.20 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.61 | ||
4Q 2016 Total |
1,612,500 |
$4.01 |
30,000 |
$0.61 | ||
2017: |
||||||
Nymex HH |
1,370,000 |
$3.39 |
— |
— | ||
CGTLA |
420,000 |
$4.27 |
— |
— | ||
Chicago |
70,000 |
$4.57 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
31,500 |
$0.42 | ||
2017 Total |
1,860,000 |
$3.63 |
31,500 |
$0.42 | ||
2018 |
2,002,500 |
$3.91 |
2,000 |
$0.65 | ||
2019 |
2,330,000 |
$3.70 |
— |
— | ||
2020 |
1,377,500 |
$3.66 |
— |
— | ||
2021 |
630,000 |
$3.36 |
— |
— | ||
2022 |
120,000 |
$3.24 |
— |
— |
Conference Call
A conference call is scheduled on Wednesday, August 3, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, August 12, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10086424.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, August 12, 2016 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the August 3, 2016 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Revenue excluding unrealized hedge (gains) losses as set forth in this release represents total operating revenue adjusted for unsettled hedge (gains) and losses. Antero believes that revenue excluding unrealized hedge (gains) losses is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Revenue excluding unrealized hedge (gains) losses is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized hedge (gains) losses (in thousands):
Three months ended June 30, |
Six months ended June 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Total operating revenue |
$ |
376,714 |
$ |
(249,198) |
$ |
1,606,401 |
$ |
471,806 | ||||
Hedge (gains) losses |
2,227 |
684,634 |
(757,327) |
404,710 | ||||||||
Cash receipts for settled hedges |
195,880 |
292,500 |
380,720 |
616,847 | ||||||||
Revenue excluding unrealized hedge (gains) losses |
$ |
574,821 |
$ |
727,936 |
$ |
1,229,794 |
$ |
1,493,363 |
Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items. Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. The following table reconciles net income (loss) to adjusted net income (in thousands):
Three months ended |
Six months ended | |||||||||||
June 30, |
June 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Net income (loss) |
$ |
(145,373) |
$ |
(596,244) |
$ |
249,058 |
$ |
(601,299) | ||||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
198,107 |
977,134 |
(376,607) |
1,021,557 | ||||||||
Impairment of unproved properties |
26,339 |
19,944 |
34,916 |
35,470 | ||||||||
Equity-based compensation |
27,582 |
25,816 |
55,365 |
49,286 | ||||||||
Contract termination and rig stacking |
1,937 |
— |
10,902 |
— | ||||||||
Income tax effect of reconciling items |
(91,307) |
(385,928) |
114,324 |
(417,401) | ||||||||
Adjusted net income |
$ |
17,285 |
$ |
40,722 |
$ |
87,958 |
$ |
87,613 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended June 30, |
Six months ended June 30, | |||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||
Net cash provided by operating activities |
$ |
243,668 |
$ |
238,538 |
$ |
595,108 |
$ |
578,706 | ||||
Net change in working capital |
(35,361) |
30,218 |
(94,344) |
(18,612) | ||||||||
Cash flow from operations before changes in working capital |
$ |
208,307 |
$ |
268,756 |
$ |
500,764 |
$ |
560,094 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, |
June 30, | |||||
2015 |
2016 | |||||
Bank credit facilities |
$ |
1,327,000 |
$ |
900,000 | ||
6.00% senior notes due 2020 |
525,000 |
525,000 | ||||
5.375% senior notes due 2021 |
1,000,000 |
1,000,000 | ||||
5.125% senior notes due 2022 |
1,100,000 |
1,100,000 | ||||
5.625% senior notes due 2023 |
750,000 |
750,000 | ||||
Net unamortized premium |
6,513 |
5,974 | ||||
Net unamortized debt issuance costs |
(39,731) |
(36,960) | ||||
Consolidated total debt |
$ |
4,668,782 |
$ |
4,244,014 | ||
Cash and cash equivalents |
23,473 |
28,251 | ||||
Consolidated net debt |
$ |
4,645,309 |
$ |
4,215,763 | ||
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income (loss) from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to adjusted EBITDAX, a reconciliation of adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to adjusted EBITDAX margin (in thousands except adjusted EBITDAX margin).
Three months ended |
Six months ended | |||||||||||||||||||
June 30, |
June 30, | |||||||||||||||||||
2015 |
2016 |
2015 |
2016 | |||||||||||||||||
Net income (loss) from continuing operations including noncontrolling interest |
$ |
(139,483) |
$ |
(575,490) |
$ |
259,688 |
$ |
(564,840) | ||||||||||||
Commodity derivative (gains) losses |
2,227 |
684,634 |
(757,327) |
404,710 | ||||||||||||||||
Gains on settled derivative instruments |
195,880 |
292,500 |
380,720 |
616,847 | ||||||||||||||||
Interest expense |
59,823 |
62,595 |
113,008 |
125,879 | ||||||||||||||||
Income tax expense (benefit) |
(84,089) |
(376,494) |
163,249 |
(371,679) | ||||||||||||||||
Depreciation, depletion, amortization, and accretion |
177,454 |
197,982 |
360,154 |
390,162 | ||||||||||||||||
Impairment of unproved properties |
26,339 |
19,944 |
34,916 |
35,470 | ||||||||||||||||
Exploration expense |
628 |
1,109 |
1,999 |
2,123 | ||||||||||||||||
Equity-based compensation expense |
27,582 |
25,816 |
55,365 |
49,286 | ||||||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
(484) |
— |
(484) | ||||||||||||||||
State franchise taxes |
(106) |
— |
129 |
39 | ||||||||||||||||
Contract termination and rig stacking |
1,937 |
— |
10,902 |
— | ||||||||||||||||
Total Adjusted EBITDAX |
268,192 |
332,112 |
622,803 |
687,513 | ||||||||||||||||
Interest expense |
(59,823) |
(62,595) |
(113,008) |
(125,879) | ||||||||||||||||
Exploration expense |
(628) |
(1,109) |
(1,999) |
(2,123) | ||||||||||||||||
Changes in current assets and liabilities |
35,361 |
(30,218) |
94,344 |
18,612 | ||||||||||||||||
State franchise taxes |
106 |
— |
(129) |
(39) | ||||||||||||||||
Other non-cash items |
460 |
348 |
(6,903) |
622 | ||||||||||||||||
Net cash provided by operating activities |
$ |
243,668 |
$ |
238,538 |
$ |
595,108 |
$ |
578,706 |
Three months ended |
Six months ended |
|||||||||||||||||||
June 30, |
June 30, |
|||||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2015 |
2016 |
2015 |
2016 |
||||||||||||||||
Realized price before cash receipts for settled hedges |
$ |
2.40 |
$ |
2.13 |
$ |
2.72 |
$ |
2.12 |
||||||||||||
Gathering, compression, and water handling revenues |
0.04 |
0.02 |
0.03 |
0.02 |
||||||||||||||||
Lease operating expense |
(0.05) |
(0.08) |
(0.05) |
(0.07) |
||||||||||||||||
Gathering, compression, processing and transportation costs |
(1.23) |
(1.29) |
(1.23) |
(1.29) |
||||||||||||||||
Marketing, net |
(0.22) |
(0.22) |
(0.17) |
(0.23) |
||||||||||||||||
Production taxes |
(0.17) |
(0.11) |
(0.17) |
(0.11) |
||||||||||||||||
General and administrative(1) |
(0.23) |
(0.21) |
(0.23) |
(0.21) |
||||||||||||||||
Adjusted EBITDAX margin before settled hedges |
0.54 |
0.24 |
0.90 |
0.23 |
||||||||||||||||
Cash receipts for settled hedges |
1.45 |
1.82 |
1.42 |
1.93 |
||||||||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
1.99 |
$ |
2.06 |
$ |
2.32 |
$ |
2.16 |
(1) Excludes equity-based stock compensation that is included in G&A | |||||
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Balance Sheets | |||||||
December 31, 2015 and June 30, 2016 | |||||||
(unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
December 31, 2015 |
June 30, 2016 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
23,473 |
28,251 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016 |
79,404 |
71,606 |
|||||
Accrued revenue |
128,242 |
133,479 |
|||||
Derivative instruments |
1,009,030 |
429,920 |
|||||
Other current assets |
8,087 |
6,528 |
|||||
Total current assets |
1,248,236 |
669,784 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
1,996,081 |
1,984,515 |
|||||
Proved properties |
8,211,106 |
8,794,515 |
|||||
Water handling and treatment systems |
565,616 |
655,251 |
|||||
Gathering systems and facilities |
1,502,396 |
1,596,460 |
|||||
Other property and equipment |
46,415 |
44,919 |
|||||
12,321,614 |
13,075,660 |
||||||
Less accumulated depletion, depreciation, and amortization |
(1,589,372) |
(1,977,790) |
|||||
Property and equipment, net |
10,732,242 |
11,097,870 |
|||||
Derivative instruments |
2,108,450 |
1,673,907 |
|||||
Other assets |
26,565 |
117,219 |
|||||
Total assets |
$ |
14,115,493 |
13,558,780 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
364,160 |
211,106 |
||||
Accrued liabilities |
194,076 |
201,320 |
|||||
Revenue distributions payable |
129,949 |
135,054 |
|||||
Derivative instruments |
— |
2,726 |
|||||
Other current liabilities |
19,085 |
19,226 |
|||||
Total current liabilities |
707,270 |
569,432 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,668,782 |
4,244,014 |
|||||
Deferred income tax liability |
1,370,686 |
1,063,331 |
|||||
Derivative instruments |
— |
5,179 |
|||||
Other liabilities |
82,077 |
75,925 |
|||||
Total liabilities |
6,828,815 |
5,957,881 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 277,036 shares and 304,158 shares, respectively |
2,770 |
3,042 |
|||||
Additional paid-in capital |
4,122,811 |
5,022,848 |
|||||
Accumulated earnings |
1,808,811 |
1,207,512 |
|||||
Total stockholders' equity |
5,934,392 |
6,233,402 |
|||||
Noncontrolling interest in consolidated subsidiary |
1,352,286 |
1,367,497 |
|||||
Total equity |
7,286,678 |
7,600,899 |
|||||
Total liabilities and equity |
$ |
14,115,493 |
13,558,780 |
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Statements of Operations and Comprehensive Loss | |||||||
Three Months Ended June 30, 2015 and 2016 | |||||||
(unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
Three Months Ended June 30, |
|||||||
2015 |
2016 |
||||||
Revenue: |
|||||||
Natural gas sales |
$ |
242,065 |
229,787 |
||||
Natural gas liquids sales |
59,525 |
94,713 |
|||||
Oil sales |
23,032 |
16,740 |
|||||
Gathering, compression, and water handling and treatment |
4,490 |
3,294 |
|||||
Marketing |
49,829 |
90,902 |
|||||
Commodity derivative fair value losses |
(2,227) |
(684,634) |
|||||
Total revenue |
376,714 |
(249,198) |
|||||
Operating expenses: |
|||||||
Lease operating |
6,673 |
12,043 |
|||||
Gathering, compression, processing, and transportation |
166,669 |
206,060 |
|||||
Production and ad valorem taxes |
22,519 |
17,458 |
|||||
Marketing |
79,053 |
125,977 |
|||||
Exploration |
628 |
1,109 |
|||||
Impairment of unproved properties |
26,339 |
19,944 |
|||||
Depletion, depreciation, and amortization |
177,046 |
197,362 |
|||||
Accretion of asset retirement obligations |
408 |
620 |
|||||
General and administrative (including equity-based compensation expense of $27,582 and $25,816 in 2015 and 2016, respectively) |
59,191 |
60,102 |
|||||
Contract termination and rig stacking |
1,937 |
— |
|||||
Total operating expenses |
540,463 |
640,675 |
|||||
Operating loss |
(163,749) |
(889,873) |
|||||
Other income (expenses): |
|||||||
Equity in earnings of unconsolidated affiliate |
— |
484 |
|||||
Interest |
(59,823) |
(62,595) |
|||||
Total other expenses |
(59,823) |
(62,111) |
|||||
Loss before income taxes |
(223,572) |
(951,984) |
|||||
Provision for income tax benefit |
84,089 |
376,494 |
|||||
Net loss and comprehensive loss including noncontrolling interest |
(139,483) |
(575,490) |
|||||
Net income and comprehensive income attributable to noncontrolling interest |
5,890 |
20,754 |
|||||
Net loss and comprehensive loss attributable to Antero Resources Corporation |
$ |
(145,373) |
(596,244) |
||||
Loss per common share |
$ |
(0.52) |
(2.12) |
||||
Loss per common share—assuming dilution |
$ |
(0.52) |
(2.12) |
||||
Weighted average number of shares outstanding: |
|||||||
Basic |
277,003 |
281,786 |
|||||
Diluted |
277,003 |
281,786 |
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||||||
Six Months Ended June 30, 2015 and 2016 | |||||||
(unaudited) | |||||||
(In thousands, except per share amounts) | |||||||
Six Months Ended June 30, |
|||||||
2015 |
2016 |
||||||
Revenue: |
|||||||
Natural gas sales |
$ |
557,007 |
484,563 |
||||
Natural gas liquids sales |
138,311 |
167,778 |
|||||
Oil sales |
35,489 |
26,919 |
|||||
Gathering, compression, and water handling and treatment |
10,658 |
7,138 |
|||||
Marketing |
107,609 |
190,118 |
|||||
Commodity derivative fair value gains (losses) |
757,327 |
(404,710) |
|||||
Total revenue |
1,606,401 |
471,806 |
|||||
Operating expenses: |
|||||||
Lease operating |
14,775 |
23,336 |
|||||
Gathering, compression, processing, and transportation |
330,331 |
414,798 |
|||||
Production and ad valorem taxes |
46,737 |
36,742 |
|||||
Marketing |
152,402 |
263,910 |
|||||
Exploration |
1,999 |
2,123 |
|||||
Impairment of unproved properties |
34,916 |
35,470 |
|||||
Depletion, depreciation, and amortization |
359,346 |
388,944 |
|||||
Accretion of asset retirement obligations |
808 |
1,218 |
|||||
General and administrative (including equity-based compensation expense of $55,365 and $49,286 in 2015 and 2016, respectively) |
118,240 |
116,389 |
|||||
Contract termination and rig stacking |
10,902 |
— |
|||||
Total operating expenses |
1,070,456 |
1,282,930 |
|||||
Operating income (loss) |
535,945 |
(811,124) |
|||||
Other income (expenses): |
|||||||
Equity in earnings of unconsolidated affiliate |
— |
484 |
|||||
Interest |
(113,008) |
(125,879) |
|||||
Total other expenses |
(113,008) |
(125,395) |
|||||
Income (loss) before income taxes |
422,937 |
(936,519) |
|||||
Provision for income tax (expense) benefit |
(163,249) |
371,679 |
|||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
259,688 |
(564,840) |
|||||
Net income and comprehensive income attributable to noncontrolling interest |
10,630 |
36,459 |
|||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
249,058 |
(601,299) |
||||
Earnings (loss) per common share |
$ |
0.92 |
(2.15) |
||||
Earnings (loss) per common share—assuming dilution: |
$ |
0.92 |
(2.15) |
||||
Weighted average number of shares outstanding: |
|||||||
Basic |
271,181 |
279,418 |
|||||
Diluted |
271,192 |
279,418 |
ANTERO RESOURCES CORPORATION | |||||||
Condensed Consolidated Statements of Cash Flows | |||||||
Six Months Ended June 30, 2015 and 2016 | |||||||
(unaudited) | |||||||
(In thousands) | |||||||
Six Months Ended June 30, |
|||||||
2015 |
2016 |
||||||
Cash flows from operating activities: |
|||||||
Net income (loss) including noncontrolling interest |
$ |
259,688 |
(564,840) |
||||
Adjustment to reconcile net income (loss) to net cash provided by operating activities: |
|||||||
Depletion, depreciation, amortization, and accretion |
360,154 |
390,162 |
|||||
Impairment of unproved properties |
34,916 |
35,470 |
|||||
Derivative fair value (gains) losses |
(757,327) |
404,710 |
|||||
Gains on settled derivatives |
380,720 |
616,848 |
|||||
Deferred income tax expense (benefit) |
163,249 |
(371,679) |
|||||
Equity-based compensation expense |
55,365 |
49,286 |
|||||
Equity in earnings of unconsolidated affiliate |
— |
(484) |
|||||
Other |
3,999 |
621 |
|||||
Changes in current assets and liabilities: |
|||||||
Accounts receivable |
(2,987) |
7,798 |
|||||
Accrued revenue |
66,091 |
(5,237) |
|||||
Other current assets |
1,047 |
1,559 |
|||||
Accounts payable |
4,579 |
3,430 |
|||||
Accrued liabilities |
15,417 |
6,431 |
|||||
Revenue distributions payable |
8,529 |
5,105 |
|||||
Other current liabilities |
1,668 |
(474) |
|||||
Net cash provided by operating activities |
595,108 |
578,706 |
|||||
Cash flows used in investing activities: |
|||||||
Additions to unproved properties |
(131,683) |
(58,195) |
|||||
Drilling and completion costs |
(1,009,421) |
(709,974) |
|||||
Additions to water handling and treatment systems |
(34,076) |
(78,625) |
|||||
Additions to gathering systems and facilities |
(200,045) |
(97,300) |
|||||
Additions to other property and equipment |
(2,794) |
(1,296) |
|||||
Investment in unconsolidated affiliate |
— |
(45,044) |
|||||
Change in other assets |
(759) |
(47,925) |
|||||
Proceeds from asset sales |
40,000 |
— |
|||||
Net cash used in investing activities |
(1,338,778) |
(1,038,359) |
|||||
Cash flows from financing activities: |
|||||||
Issuance of common stock |
537,693 |
752,599 |
|||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
— |
178,000 |
|||||
Issuance of senior notes |
750,000 |
— |
|||||
Repayments on bank credit facilities, net |
(612,000) |
(427,000) |
|||||
Payments of deferred financing costs |
(15,254) |
(96) |
|||||
Distributions to noncontrolling interest in consolidated subsidiary |
(12,617) |
(31,681) |
|||||
Employee tax withholding for settlement of equity compensation awards |
(4,513) |
(4,819) |
|||||
Other |
(2,332) |
(2,572) |
|||||
Net cash provided by financing activities |
640,977 |
464,431 |
|||||
Net increase (decrease) in cash and cash equivalents |
(102,693) |
4,778 |
|||||
Cash and cash equivalents, beginning of period |
245,979 |
23,473 |
|||||
Cash and cash equivalents, end of period |
$ |
143,286 |
28,251 |
||||
Supplemental disclosure of cash flow information: |
|||||||
Cash paid during the period for interest |
$ |
103,133 |
121,128 |
||||
Supplemental disclosure of noncash investing activities: |
|||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
$ |
(210,217) |
(155,671) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended June 30, 2015 compared to the three months ended June 30, 2016:
Three Months Ended June 30, |
Amount of Increase |
Percent |
||||||||||||||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||||||||||||||
Operating revenues: |
||||||||||||||||||||||||
Natural gas sales |
$ |
242,065 |
$ |
229,787 |
$ |
(12,278) |
(5) |
% | ||||||||||||||||
NGLs sales |
59,525 |
94,713 |
35,188 |
59 |
% | |||||||||||||||||||
Oil sales |
23,032 |
16,740 |
(6,292) |
(27) |
% | |||||||||||||||||||
Gathering, compression, and water handling and treatment |
4,490 |
3,294 |
(1,196) |
(27) |
% | |||||||||||||||||||
Marketing |
49,829 |
90,902 |
41,073 |
82 |
% | |||||||||||||||||||
Commodity derivative fair value losses |
(2,227) |
(684,634) |
(682,407) |
30,642 |
% | |||||||||||||||||||
Total operating revenues |
376,714 |
(249,198) |
(625,912) |
* |
% | |||||||||||||||||||
Operating expenses: |
||||||||||||||||||||||||
Lease operating |
6,673 |
12,043 |
5,370 |
80 |
% | |||||||||||||||||||
Gathering, compression, processing, and transportation |
166,669 |
206,060 |
39,391 |
24 |
% | |||||||||||||||||||
Production and ad valorem taxes |
22,519 |
17,458 |
(5,061) |
(22) |
% | |||||||||||||||||||
Marketing |
79,053 |
125,977 |
46,924 |
59 |
% | |||||||||||||||||||
Exploration |
628 |
1,109 |
481 |
77 |
% | |||||||||||||||||||
Impairment of unproved properties |
26,339 |
19,944 |
(6,395) |
(24) |
% | |||||||||||||||||||
Depletion, depreciation, and amortization |
177,046 |
197,362 |
20,316 |
11 |
% | |||||||||||||||||||
Accretion of asset retirement obligations |
408 |
620 |
212 |
52 |
% | |||||||||||||||||||
General and administrative (before equity-based compensation) |
31,609 |
34,286 |
2,677 |
8 |
% | |||||||||||||||||||
Equity-based compensation |
27,582 |
25,816 |
(1,766) |
(6) |
% | |||||||||||||||||||
Contract termination and rig stacking |
1,937 |
— |
(1,937) |
* |
||||||||||||||||||||
Total operating expenses |
540,463 |
640,675 |
100,212 |
19 |
% | |||||||||||||||||||
Operating loss |
(163,749) |
(889,873) |
(726,124) |
443 |
% | |||||||||||||||||||
Other earnings (expenses): |
||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
484 |
484 |
* |
% | |||||||||||||||||||
Interest expense |
(59,823) |
(62,595) |
(2,772) |
5 |
% | |||||||||||||||||||
Loss before income taxes |
(223,572) |
(951,984) |
(728,412) |
326 |
% | |||||||||||||||||||
Income tax benefit |
84,089 |
376,494 |
292,405 |
348 |
% | |||||||||||||||||||
Net loss and comprehensive loss including noncontrolling interest |
(139,483) |
(575,490) |
(436,007) |
313 |
% | |||||||||||||||||||
Net income and comprehensive income attributable to noncontrolling interest |
5,890 |
20,754 |
14,864 |
252 |
% | |||||||||||||||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation |
$ |
(145,373) |
$ |
(596,244) |
$ |
(450,871) |
310 |
% | ||||||||||||||||
Adjusted EBITDAX |
$ |
268,192 |
$ |
332,112 |
$ |
63,920 |
24 |
% | ||||||||||||||||
Three Months Ended June 30, |
Amount of Increase |
Percent |
||||||||||
2015 |
2016 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
110 |
119 |
9 |
9 |
% | |||||||
C2 Ethane (MBbl) |
— |
1,581 |
1,581 |
* |
||||||||
C3+ NGLs (MBbl) |
3,655 |
4,771 |
1,116 |
31 |
% | |||||||
Oil (MBbl) |
523 |
477 |
(46) |
(9) |
% | |||||||
Combined (Bcfe) |
135 |
160 |
25 |
19 |
% | |||||||
Daily combined production (MMcfe/d) |
1,484 |
1,762 |
278 |
19 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.20 |
$ |
1.93 |
$ |
(0.27) |
(12) |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
8.36 |
$ |
8.36 |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
16.29 |
$ |
17.08 |
$ |
0.79 |
5 |
% | ||||
Oil (per Bbl) |
$ |
44.06 |
$ |
35.08 |
$ |
(8.98) |
(20) |
% | ||||
Combined (per Mcfe) |
$ |
2.40 |
$ |
2.13 |
$ |
(0.27) |
(11) |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
3.86 |
$ |
4.31 |
$ |
0.45 |
12 |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
8.36 |
$ |
8.36 |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
19.51 |
$ |
18.98 |
$ |
(0.53) |
(3) |
% | ||||
Oil (per Bbl) |
$ |
47.33 |
$ |
35.08 |
$ |
(12.25) |
(26) |
% | ||||
Combined (per Mcfe) |
$ |
3.85 |
$ |
3.95 |
$ |
0.10 |
3 |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.05 |
$ |
0.08 |
$ |
0.03 |
60 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.23 |
$ |
1.29 |
$ |
0.06 |
5 |
% | ||||
Production and ad valorem taxes |
$ |
0.17 |
$ |
0.11 |
$ |
(0.06) |
(35) |
% | ||||
Marketing, net |
$ |
0.22 |
$ |
0.22 |
$ |
— |
— |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.31 |
$ |
1.23 |
$ |
(0.08) |
(6) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.23 |
$ |
0.21 |
$ |
(0.02) |
(9) |
% |
*Not meaningful or applicable |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the six months ended June 30, 2015 compared to the six months ended June 30, 2016:
Six Months Ended June 30, |
Amount of Increase |
Percent |
||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||
Operating revenues: |
||||||||||||
Natural gas sales |
$ |
557,007 |
$ |
484,563 |
$ |
(72,444) |
(13) |
% | ||||
NGLs sales |
138,311 |
167,778 |
29,467 |
21 |
% | |||||||
Oil sales |
35,489 |
26,919 |
(8,570) |
(24) |
% | |||||||
Gathering, compression, and water handling and treatment |
10,658 |
7,138 |
(3,520) |
(33) |
% | |||||||
Marketing |
107,609 |
190,118 |
82,509 |
77 |
% | |||||||
Commodity derivative fair value gains (losses) |
757,327 |
(404,710) |
(1,162,037) |
(153) |
% | |||||||
Total operating revenues |
1,606,401 |
471,806 |
(1,134,595) |
(71) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
14,775 |
23,336 |
8,561 |
58 |
% | |||||||
Gathering, compression, processing, and transportation |
330,331 |
414,798 |
84,467 |
26 |
% | |||||||
Production and ad valorem taxes |
46,737 |
36,742 |
(9,995) |
(21) |
% | |||||||
Marketing |
152,402 |
263,910 |
111,508 |
73 |
% | |||||||
Exploration |
1,999 |
2,123 |
124 |
6 |
% | |||||||
Impairment of unproved properties |
34,916 |
35,470 |
554 |
2 |
% | |||||||
Depletion, depreciation, and amortization |
359,346 |
388,944 |
29,598 |
8 |
% | |||||||
Accretion of asset retirement obligations |
808 |
1,218 |
410 |
51 |
% | |||||||
General and administrative (before equity-based compensation) |
62,875 |
67,103 |
4,228 |
7 |
% | |||||||
Equity-based compensation |
55,365 |
49,286 |
(6,079) |
(11) |
% | |||||||
Contract termination and rig stacking |
10,902 |
— |
(10,902) |
* |
||||||||
Total operating expenses |
1,070,456 |
1,282,930 |
212,474 |
20 |
% | |||||||
Operating income (loss) |
535,945 |
(811,124) |
(1,347,069) |
* |
% | |||||||
Other earnings (expenses): |
||||||||||||
Equity in earnings of unconsolidated affiliate |
— |
484 |
484 |
* |
% | |||||||
Interest expense |
(113,008) |
(125,879) |
(12,871) |
11 |
% | |||||||
Income (loss) before income taxes |
422,937 |
(936,519) |
(1,359,456) |
* |
% | |||||||
Income tax expense (benefit) |
(163,249) |
371,679 |
534,928 |
* |
% | |||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
259,688 |
(564,840) |
(824,528) |
* |
% | |||||||
Net income and comprehensive income attributable to noncontrolling interest |
10,630 |
36,459 |
25,829 |
243 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
249,058 |
$ |
(601,299) |
$ |
(850,357) |
* |
|||||
Adjusted EBITDAX |
$ |
622,803 |
$ |
687,513 |
$ |
64,710 |
10 |
% |
Six Months Ended June 30, |
Amount of Increase |
Percent |
||||||||||
2015 |
2016 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
222 |
242 |
20 |
9 |
% | |||||||
C2 Ethane (MBbl) |
— |
2,662 |
2,662 |
* |
||||||||
C3+ NGLs (MBbl) |
6,895 |
9,452 |
2,557 |
37 |
% | |||||||
Oil (MBbl) |
889 |
949 |
61 |
7 |
% | |||||||
Combined (Bcfe) |
269 |
320 |
52 |
19 |
% | |||||||
Daily combined production (MMcfe/d) |
1,485 |
1,760 |
275 |
19 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.51 |
$ |
2.00 |
$ |
(0.51) |
(20) |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
7.68 |
$ |
7.68 |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
20.06 |
$ |
15.59 |
$ |
(4.47) |
(22) |
% | ||||
Oil (per Bbl) |
$ |
39.93 |
$ |
28.36 |
$ |
(11.57) |
(29) |
% | ||||
Combined (per Mcfe) |
$ |
2.72 |
$ |
2.12 |
$ |
(0.60) |
(22) |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.12 |
$ |
4.42 |
$ |
0.30 |
7 |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
7.68 |
$ |
7.68 |
* |
|||||
C3+ NGLs (per Bbl) |
$ |
22.66 |
$ |
18.93 |
$ |
(3.73) |
(16) |
% | ||||
Oil (per Bbl) |
$ |
46.40 |
$ |
28.36 |
$ |
(18.04) |
(39) |
% | ||||
Combined (per Mcfe) |
$ |
4.14 |
$ |
4.05 |
$ |
(0.09) |
(2) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.05 |
$ |
0.07 |
$ |
0.02 |
40 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.23 |
$ |
1.29 |
$ |
0.06 |
5 |
% | ||||
Production and ad valorem taxes |
$ |
0.17 |
$ |
0.11 |
$ |
(0.06) |
(35) |
% | ||||
Marketing, net |
$ |
0.17 |
$ |
0.23 |
$ |
0.06 |
35 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.34 |
$ |
1.22 |
$ |
(0.12) |
(9) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.23 |
$ |
0.21 |
$ |
(0.02) |
(9) |
% |
*Not meaningful or applicable |
Logo - http://photos.prnewswire.com/prnh/20131101/LA09101LOGO
SOURCE Antero Resources Corporation
DENVER, July 14, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today provided its second quarter 2016 operations update.
Highlights Include:
Recent Developments
Marcellus Acreage Acquisition
On June 9, 2016, Antero signed a definitive agreement with a third party to acquire approximately 55,000 net acres in the core of the Marcellus Shale for $450 million. In addition, a third party has provided notice of its intention to exercise its tag along rights and the parties are working towards signing a definitive agreement, adding 13,000 net acres and approximately 3 MMcfe/d of net production to the acquisition for an additional $108 million. This brings the total acquisition acreage to 68,000 net acres and net production to 17 MMcfe/d for a total purchase price of $558 million. The acquisition includes undeveloped properties located primarily in Wetzel, Tyler and Doddridge Counties, West Virginia. Approximately 75% of the acreage to be acquired is located in Antero's Highly-Rich Gas/Condensate, Highly-Rich Gas and Rich Gas regimes, with the remaining 25% located in Antero's Dry Gas regime. Antero estimates the undeveloped properties include 5.1 Tcfe of unaudited Marcellus 3P reserves plus 2.2 Tcf of dry Utica resource potential. In total, the acquisition adds 625 identified 3P locations and enhances 435 existing 3P locations by incremental working interests and/or increased lateral length. The lateral length of the new or enhanced identified 3P locations averages 9,300 feet. Pro forma for the acquisition, Antero's Marcellus leasehold position will include over 480,000 net acres and 3P Reserves of 34.7 Tcfe, assuming ethane rejection. The transaction is expected to close in the third quarter of 2016, with an effective date of January 1, 2016.
Antero Resources Common Stock Offering
On June 9, 2016, Antero completed an underwritten base offering of 26,750,000 shares of common stock for net proceeds of approximately $753 million. Antero expects to use the proceeds to fund the announced acquisition and for general corporate purposes including funding future development.
Operating Update
All operational figures are as of the date of this release unless otherwise noted.
Antero's net daily production for the second quarter of 2016 averaged 1,762 MMcfe/d, including 75,041 Bbl/d of liquids (26% liquids). During the second quarter, Antero shut in 7.3 Bcfe, representing 80 MMcfe/d of production for the quarter due to operational downtime in late June at the Sherwood processing facility in West Virginia. Second quarter 2016 production represented an organic production growth rate of 19% from the second quarter of 2015 and flat from the first quarter of 2016. Second quarter 2016 C3+ natural gas liquids ("NGLs") and oil production averaged 52,424 Bbl/d and 5,244 Bbl/d, respectively. Second quarter 2016 ethane (C2) production averaged 17,373 Bbl/d. Total liquids production for the second quarter of 2016 represents an organic production growth rate of 63% from the second quarter of 2015 and a 10% increase sequentially.
Current well costs are $0.9 million and $1.04 million per 1,000 feet of lateral in the Marcellus and Utica, both for a 9,000 foot lateral. The reduction in well costs represents a 24% decline in each area since 2015 and a 5% and 9% sequential quarterly reduction, respectively. The reduction in well costs is driven both by reduced service costs on completions and continuing operational efficiencies. In the Marcellus, drilling days from spud to final rig release during the quarter ended June 30, 2016 were reduced from 24 days in 2015 to 15 days, while stages completed per day increased from 3.5 stages per day to 3.9 stages per day for the quarter. During the quarter, Antero drilled a record 7,274 feet of lateral in a 24 hour period. The average feet of lateral drilled per day for the quarter was 3,623 feet which is a 113% increase from 2015 and a 72% increase since the first quarter of 2016. All of Antero's top 20 drilling days in the Marcellus, since inception, have occurred in 2016. In the Utica, drilling days from spud to final rig release during the second quarter were reduced from 31 days in 2015 to 16 days and stages completed per day increased from 3.7 stages per day to 4.4 stages per day. Antero's current all-in completed well cost for a 9,000 feet lateral is approximately $8.1 million and approximately $9.4 million, respectively, in the Marcellus and Utica.
Commenting on the Marcellus acquisition and the continued improvements in drilling and completion activity, Paul Rady, Chairman of the Board and CEO said, "We are excited about the recently announced acquisition adding quality net acres to further expand our consolidated position in the core of the Marcellus. Not only is the acreage primarily located in what we refer to as the 'high-graded' core area of the Marcellus, but the acquisition delivers all of the key attributes that Antero seeks in acquisitions. The acreage adds a significant amount of highly economic well locations to our portfolio, ties in directly with our existing firm transport portfolio allowing us to sell our gas at currently favorably priced markets and provides value creation for Antero Midstream through the acquisition of more than 100,000 gross acres in the dedication area. Going forward, we believe we are well positioned to achieve further consolidation in Appalachia during the downturn given our continuous operating improvements that further amplify our low cost development competitive advantage, along with our significant hedge position, diversified firm transportation portfolio, ample liquidity and healthy balance sheet."
Antero's average realized natural gas price before hedging for the second quarter of 2016 was $1.93 per Mcf, a $0.02 differential to the Nymex average price for the period. Antero's average realized natural gas price after hedging for the second quarter of 2016 was $4.31 per Mcf, a $2.36 premium to the Nymex average price for the period. For the second quarter of 2016, Antero realized a cash settled natural gas hedge gain of $283 million, or $2.38 per Mcf. This cash settled natural gas hedge gain included $144 million associated with Nymex hedges, $96 million associated with hedges at the Dominion South index, $11 million associated with hedges at the TCO index and $32 million associated with hedges at the Columbia Gulf Louisiana index.
Antero's average realized C3+ NGL price before hedging for the second quarter of 2016 was $17.08 per barrel, or approximately 38% of the WTI oil price average for the period. The Company's average realized C3+ NGL price after hedging for the quarter was $18.98 per barrel, or 42% of the WTI oil price average for the period. For the second quarter of 2016, Antero realized a cash settled C3+ NGL hedge gain of $9.1 million, or $1.90 per barrel. Antero's average realized ethane price for the quarter was $8.36 per barrel, or $0.20 per gallon.
Antero's average realized oil price before hedging for the second quarter of 2016 was $35.08 per barrel, a $10.33 per barrel differential to the WTI oil price. Antero's liquids production and realizations for the second quarter of 2016 added an incremental $0.20 per Mcfe, increasing the average natural gas realized price before hedging from $1.93 per Mcf to $2.13 per Mcfe. The average all-in natural gas equivalent price, including NGLs, oil and hedge settlements, was $3.95 per Mcfe for the second quarter of 2016.
The following table details the components of average net production and average realized prices for the three months ended June 30, 2016:
Three Months Ended June 30, 2016 | ||||||||||||||
Gas (MMcf/d) |
Oil (Bbl/d) |
C3+ NGLs (Bbl/d) |
Ethane (Bbl/d) |
Combined Gas Equivalent (MMcfe/d) | ||||||||||
Average Net Production |
1,311 |
5,244 |
52,424 |
17,373 |
1,762 | |||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs ($/Bbl) |
Ethane ($/Bbl) |
Combined Gas Equivalent ($/Mcfe) | |||||||||
Average realized price before settled derivatives |
$ |
1.93 |
$ |
35.08 |
$ |
17.08 |
$ 8.36 |
$ |
2.13 | |||||
Settled derivatives |
2.38 |
– |
1.90 |
– |
1.82 | |||||||||
Average realized price after settled derivatives |
$ |
4.31 |
$ |
35.08 |
$ |
18.98 |
$ 8.36 |
$ |
3.95 | |||||
Nymex average price |
$ |
1.95 |
$ |
45.41 |
$ |
1.95 | ||||||||
Premium / (Differential) to Nymex |
$ |
2.36 |
$ |
(10.33) |
$ |
2.00 |
Marcellus Shale — Antero completed and placed on line 22 horizontal Marcellus wells during the second quarter of 2016 with an average lateral length of 9,200 feet. Of the 22 wells completed in the second quarter, 17 have been on line for more than 30 days and had an average 30-day rate of 15.9 MMcfe/d assuming ethane rejection (26% liquids). Of the 17 wells that have been on line for more than 30 days, six were constrained during certain periods of time due to midstream infrastructure buildout. Sand placement for completions increased further from 97% in the first quarter of 2016 to 99% during the second quarter. The Company is currently operating six drilling rigs and four completion crews in the Marcellus Shale play.
Utica Shale — Antero completed and placed on line nine horizontal Utica wells during the second quarter of 2016 with an average lateral length of 8,400 feet. Of the nine wells completed in the second quarter of 2016, 5 have been on line for more than 30 days and had an average restricted 30-day rate of 16.0 MMcfe/d while rejecting ethane (13% liquids). Antero is currently operating one drilling rig and one completion crew in the Utica Shale play.
Net Marketing Expense
During the second quarter of 2016, Antero estimates its net marketing expense will be approximately $35 million, or $0.22 per Mcfe, an improvement of 8% compared to first quarter's net marketing expense of $39 million.
For the second half of 2016, due to a third party contractual commitment effective July, 1, 2016, Antero has released certain unutilized firm transportation capacity and the costs associated with the unutilized capacity. As a result, Antero expects net marketing expense to decrease further to a range of $0.10 to $0.15 per Mcfe for the second half of 2016, reaffirming the net marketing expense guidance of $0.15 to $0.20 per Mcfe for full year 2016.
Commenting on net marketing expenses, Glen Warren, President and CFO, said "We are currently on track to achieve our net marketing expense guidance for the year of $0.15 to $0.20 per Mcfe, driven by the improvement in net marketing expenses in the second quarter and the existing contractual arrangement with a third party that is expected to result in a significant further reduction in net marketing expenses in the second half of the year. Given the favorable pricing we currently receive on our natural gas sales and expect to receive going forward, we have strong visibility that our Appalachian leading EBITDA margin, inclusive of the unutilized costs, will continue as we grow our production into the incremental capacity."
Further commenting on commodity price upside exposure, Mr. Warren stated, "We are well positioned to capitalize on the improvement in commodity pricing, as we have been able to continue our operational momentum through this downturn. We have driven down well costs 24% since 2015 in both the Marcellus and Utica, including a sequential quarterly reduction of 5% and 9%, respectively, and have achieved improvements in overall pricing on both our gas and liquids production through attractive third party sales agreements and firm transportation. For example, on the liquids front, through our firm commitment on Mariner East II, which is slated to commence in 2Q 2017, we expect a significant improvement in NGL netbacks, driving tremendous value for our shareholders through our current 70,000 Bbls/d of net NGL production and 2.7 billion barrels of 3P NGL reserves pro forma for the recently announced Marcellus acquisition."
Second Quarter 2016 Earnings Release and Call
Antero plans to issue its second quarter 2016 earnings release on Tuesday, August 2, 2016 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Wednesday, August 3, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, August 12, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10086424.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, August 12, 2016 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements." Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, estimated marketing expenses, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, Antero's ability to successfully complete the pending acquisition and integrate the assets with Antero's own and realize the benefits from the transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
The SEC permits oil and gas companies to disclose only proved, probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. In this release Antero has provided internally generated estimates. Antero's actual proved, probable and possible reserve estimates have been audited by its third party reserve engineer. The estimates of proved, probable and possible reserves associated with the acquired acreage, and of Antero pro forma for the acquisition, included in this press release were not audited by third-party engineers. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
Certain reserve quantities included in this release assume ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
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SOURCE Antero Resources
DENVER, June 9, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") recently announced the signing of a definitive agreement with a third party to acquire approximately 55,000 net acres in the core of the Marcellus Shale for $450 million. Antero will hold a conference call on June 10, 2016 at 7:00 a.m. MT to discuss the acquisition.
Conference Call
A conference call is scheduled on Friday, June 10, 2016 at 7:00 am MT to discuss the acquisition. A brief Q&A session for security analysts will immediately follow. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, June 16, 2016 at 7:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10087781.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Thursday, June 16, 2016 at 7:00 am MT.
Please visit www.anteroresources.com to view a summary transaction presentation containing supplemental information that will be referenced during the conference call.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, Antero's ability to successfully complete the pending acquisition and integrate the assets with its own and realize the benefits from the transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, June 9, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today the pricing of an underwritten public offering of 26,750,000 common shares (the "Offering") for aggregate gross proceeds of approximately $762 million before estimated offering expenses. In connection with the Offering, Antero Resources has also granted the underwriters a 30-day option to purchase up to an additional 4,012,500 common shares. The underwriters intend to offer the shares from time to time for sale in one or more transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices.
The Company expects to use the proceeds from the Offering, including the proceeds from any exercise of the underwriters' option to purchase additional shares of common stock, to fund the recently announced acquisition of properties from a third party and for general corporate purposes including funding future development.
Credit Suisse and J.P. Morgan are acting as joint book-running managers for the Offering.
The Offering is being made pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission ("SEC"). The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Credit Suisse Securities (USA) LLC Eleven Madison Avenue, New York, NY, 10010 1-800-221-1037 email: newyork.prospectus@credit-suisse.com |
J.P. Morgan c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY, 11717 1-866-803-9204 Email: prospectus-eq_fi@jpmchase.com |
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, Antero's ability to successfully complete the pending acquisition and integrate the assets with its own and realize the benefits from the transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, June 9, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") announced today that it has commenced an underwritten public offering of 26,750,000 shares of the Company's common stock (the "Offering"). In addition, the Company anticipates granting the underwriters a 30-day option to purchase up to an additional 4,012,500 shares of common stock. The underwriters intend to offer the shares from time to time for sale in one or more transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices.
The Company expects to use the net proceeds from the Offering, including the proceeds from any exercise of the underwriters' option to purchase additional shares of common stock, to fund the recently announced acquisition of properties from a third party (the "Acquisition") and for general corporate purposes including funding future development. The Offering is not conditioned on the consummation of the Acquisition.
Credit Suisse and J.P. Morgan will act as joint book-running managers for the Offering.
The Offering is being made pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission ("SEC"). The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Credit Suisse Securities (USA) LLC |
J.P. Morgan | |
Eleven Madison Avenue, |
c/o Broadridge Financial Solutions | |
New York, NY, 10010 |
1155 Long Island Avenue | |
1-800-221-1037 |
Edgewood, NY, 11717 | |
1-866-803-9204 | ||
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, Antero's ability to successfully complete the pending acquisition and integrate the assets with its own and realize the benefits from the transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, June 9, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced that it has signed a definitive agreement with a third party to acquire approximately 55,000 net acres in the core of the Marcellus Shale for $450 million. Approximately 75% of the 55,000 net acres contains dry Utica rights. The acquisition includes undeveloped properties located primarily in Wetzel, Tyler and Doddridge Counties in West Virginia and approximately 14 MMcfe/d of net production. The transaction is expected to close in the third quarter of 2016, subject to customary closing conditions, with an effective date of January 1, 2016.
Transaction Highlights:
Transaction Details
Antero has agreed to acquire approximately 55,000 net acres of undeveloped Marcellus Shale leasehold, including deep rights on approximately 41,000 net acres highly prospective for the underlying dry Utica, and 14 MMcfe/d of net production for $450 million. Approximately 75% of the acquired acreage is located in Antero's Rich Gas, Highly-Rich Gas and Highly-Rich Gas/Condensate regimes, with the remaining 25% located in the Dry Gas regime. Antero estimates the undeveloped properties include 4.1 Tcfe of unaudited Marcellus 3P reserves and 1.8 Tcf of dry Utica resource potential. In total, the acquisition adds 625 identified 3P locations and enhances 435 existing 3P locations by incremental working interests and/or increased lateral length. The lateral length of the new or enhanced identified 3P locations averages 9,300 feet. Pro forma for the acquisition, Antero's Marcellus leasehold position includes over 480,000 net acres and 3P Reserves of 33.7 Tcfe.
Tag Along Option
A third party has a 30-day tag along option to sell the remaining 19% average working interest in the acquired properties to Antero, or an additional 13,000 net acres, under the same terms. The tag along acreage includes 1 Tcfe of unaudited Marcellus 3P reserves, 400 Bcf of dry Utica resource and 3 MMcfe/d of net production. If the tag along option is exercised by the third party, the adjusted acquisition price is estimated to be $560 million.
Commenting on the acquisition, Paul Rady, Chairman and CEO, said, "This strategic acreage acquisition in the southwestern core of the Marcellus Shale play further enhances our leading position as a pure-play Appalachian operator. The transaction creates a new platform for development and consolidation in Wetzel County, with attractive rich and dry gas Marcellus locations, as well as stacked pay potential for the dry Utica. Additionally, this acquired acreage is able to access our firm transportation portfolio and thus move incremental production to currently favorable markets. Similar to the successful strategy that we deployed in Tyler County, we expect to further consolidate acreage in Wetzel County and build out the necessary midstream infrastructure to move our gas to market, creating significant value for both Antero Resources and Antero Midstream."
Mr. Rady added, "The acquisition enhances our development portfolio, adding or enhancing over 1,000 undeveloped liquids locations with industry EURs in line with results we have achieved so far this year in Tyler and Doddridge Counties, WV. In addition, the acquisition adds or enhances 225 Marcellus dry gas locations and over 500 highly prospective dry Utica locations, adding dry gas optionality to our inventory. This acquisition further positions Antero for continued growth and development in the southwest Marcellus."
Pro forma Metrics |
Pre- |
Post- |
Acquisition |
% Increase | ||||
3P Locations |
3,719 |
4,344 |
625(1) |
17% | ||||
3P Reserves (Tcfe) |
37.1 |
41.2 |
4.1(2) |
11% | ||||
3P Liquids (MMBbls)(3) |
1,237 |
1,350 |
113(2) |
9% | ||||
Net Acres |
573,000 |
628,000 |
55,000 |
10% | ||||
Core Liquids-rich Net Acres |
377,000 |
420,000 |
43,000 |
11% | ||||
Core Dry Gas Net Acres |
143,000 |
155,000 |
12,000 |
8% | ||||
Gross Acres Dedicated to Antero Midstream |
491,000 |
597,000 |
106,000 |
22% | ||||
2017 Production Growth Target |
20% |
20% to 25% |
0% to 5% |
1) |
Does not include existing locations that were enhanced by incremental working interests and/or increased lateral lengths |
2) |
Unaudited |
3) |
Includes C3+ NGLs and assumes ethane rejection |
Commenting on Antero's 2016 capital budget and development plans on the acquired acreage, Glen Warren, President and CFO said, "Due to the savings achieved year-to-date from service cost reductions and operating efficiencies, we expect to add an additional rig in the second half of the year while maintaining our original drilling and completion budget of $1.3 billion. The additional rig, which will focus primarily on Tyler County, enables Antero to accelerate production so that we believe we can generate 20% to 25% year-over-year growth 2017 with a minimal increase to the 2017 drilling and completion capital budget compared to 2016. Additionally, due to our firm transportation portfolio, substantially all incremental production is expected to flow to favorably priced markets and enable us to continue delivering top tier EBITDAX margins."
Mr. Warren added, "In addition to the benefits for Antero, there are substantial benefits for Antero Midstream. Over 95% of the acquired acreage will be dedicated to Antero Midstream for gathering, compression, processing, and water services, providing approximately $500 million of additional organic growth capital opportunities over the next five years that will ultimately benefit Antero Resources through its 62% ownership in Antero Midstream."
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, Antero's ability to successfully complete the pending acquisition and integrate the assets with the Company's own and realize the benefits from the transaction, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
The SEC permits oil and gas companies to disclose only proved, probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. In this release Antero has provided internally generated estimates. Antero's actual proved, probable and possible reserve estimates have been audited by its third party reserve engineer. The estimates of proved, probable and possible reserves associated with the acquired acreage, and of Antero pro forma for the acquisition, included in this press release were not audited by third-party engineers. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
Certain reserve quantities included in this release assume ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
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SOURCE Antero Resources Corporation
DENVER, April 27, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its first quarter 2016 financial results and announced increased 2016 production guidance. The relevant consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, which has been filed with the Securities and Exchange Commission.
Highlights for the First Quarter of 2016:
Recent Developments
Increased 2016 Production Guidance
Antero is forecasting net daily production to average 1,750 MMcfe/d in 2016, a 17% increase over prior year production and a 2% increase over the previous 2016 production guidance of 1,715 MMcfe/d. The increase in production guidance, while maintaining the previously announced $1.3 billion drilling and completion budget, is driven by the strong first quarter results as well as recent operational efficiencies. All other aspects of Antero's guidance previously provided on February 17, 2016 remain unchanged.
Commenting on the increased production guidance, Paul Rady, Chairman of the Board and CEO said, "The positive momentum from our development program and operational efficiencies to date provides Antero with the confidence to increase our 2016 net daily production guidance to 1,750 MMcfe/d. Our strong first quarter operating results were highlighted by an 18% improvement for Marcellus wells completed in the quarter compared to type curve and accelerated first production dates due to increased efficiencies in the field. In addition, our operating team has been focused on driving down costs which, combined with strong well performance, materially enhances capital efficiencies in the current commodity price environment. Lastly, looking into the remainder of 2016 we expect the production profile to be similar to last year, with an acceleration of completions in the second half of the year, assuming commodity prices are supportive."
Borrowing Base Reaffirmed at $4.5 Billion
On April 14, 2016, Antero's borrowing base under its upstream credit facility was reaffirmed at $4.5 billion. Lender commitments under the facility remain at $4.0 billion. The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., is currently comprised of 30 banks.
Antero Midstream Secondary Unit Offering
On March 30, 2016, Antero completed an underwritten offering of 8,000,000 Antero Midstream Partners LP ("Antero Midstream") common units for net proceeds of approximately $178 million. Net proceeds from the offering will be used to fund a portion of Antero's expected 2016 capital expenditures.
First Quarter 2016 Financial Results
As of March 31, 2016, Antero owned a 62% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated with Antero's results.
For the three months ended March 31, 2016, the Company reported a net loss attributable to Antero Resources Corporation of $5 million, or $(0.02) per basic and diluted share, compared to a net income of $394 million in the first quarter of 2015. The GAAP net income for the first quarter of 2016 included the following items:
Without the effect of these items, the Company's results for the first quarter of 2016 were as follows:
For a description of adjusted net income attributable to Antero Resources Corporation, adjusted EBITDAX and cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the first quarter of 2016 averaged 1,758 MMcfe/d, including 68,516 Bbl/d of liquids (23% liquids). First quarter 2016 production represents an organic production growth rate of 18% and 17% from the first quarter of 2015 and fourth quarter of 2015, respectively. First quarter 2016 C3+ natural gas liquids ("NGLs") and oil production averaged 51,443 Bbl/d and 5,189 Bbl/d, respectively. Ethane (C2) production averaged 11,884 Bbl/d as Antero began recovering ethane in December 2015 when the first de-ethanizer was commissioned at the Sherwood processing facility. Total liquids production for the first quarter of 2016 represents an organic production growth rate of 71% and 25% from the first quarter of 2015 and fourth quarter of 2015, respectively.
Average natural gas price before hedging decreased 26% from the prior year quarter to $2.08 per Mcf, a $0.01 per Mcf negative differential to Nymex, as Nymex natural gas prices decreased 30% from the prior year quarter. Approximately 99% of Antero's first quarter 2016 natural gas revenue was realized at favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Tennessee Gulf and Nymex. The remaining 1% of natural gas production was priced at less favorable index pricing points including Dominion South and Tetco M2. Antero's average realized natural gas price after hedging for the first quarter of 2016 was $4.54 per Mcf, a $2.45 premium to the Nymex average price for the period. This represents a 4% increase compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $302 million, or $2.46 per Mcf.
Average realized C3+ NGL price before hedging for the first quarter of 2016 was $14.07 per barrel, or 42% of the Nymex WTI oil price, which represents a 42% decrease as compared to the prior year quarter. Average realized oil price was $21.56 per barrel, a 52% decrease as compared to the first quarter of 2015. Antero's average realized ethane price for the first quarter of 2016 was $6.68 per barrel, or $0.16 per gallon. The first quarter of 2016 represented the first full quarter in which Antero recovered ethane at the Sherwood processing plant in West Virginia. Average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, decreased from the prior year quarter by 31% to $2.11 per Mcfe due to a 32% decline in Nymex WTI and a 30% decline in Nymex natural gas prices.
Average realized C3+ NGL price including hedges was $18.88 per barrel, or $0.34 per gallon, a 28% decrease as compared to the first quarter of 2015. Average natural gas-equivalent price including NGLs, oil and hedge settlements decreased by 6% to $4.14 per Mcfe for the first quarter of 2016 as compared to the first quarter of 2015. For the first quarter of 2016, Antero realized a hedge settlement gain of $324 million, or $2.03 per Mcfe.
Total operating revenues for the first quarter of 2016 were $721 million as compared to $1.2 billion for the first quarter of 2015. Operating revenue for the first quarter of 2016 included a $44 million non-cash loss on unsettled hedges while the first quarter of 2015 included a $575 million non-cash gain on unsettled hedges. Adjusted net revenue increased 17% to $765 million compared to the first quarter of 2015 (including cash-settled hedge gains and losses but excluding non-cash unsettled hedge gains and losses). Liquids production contributed 25% of combined natural gas, NGLs and oil revenue before hedges in the first quarter of 2016, as compared to a 22% contribution for the prior year quarter. For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the first quarter of 2016 was $99 million. Antero's marketing revenue was primarily associated with the sale of third-party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee Gas Pipeline. Marketing expense for the first quarter of 2016 was $138 million. The largest components of marketing expense were the costs related to excess capacity, the cost of purchasing third-party gas and firm transport demand costs. Net marketing expense was $39 million or $0.24 per Mcfe for the first quarter of 2016. Beginning July 1, 2016, pursuant to a third party contractual commitment, Antero anticipates a release of certain firm transportation capacity and an associated reduction in its firm transportation costs. As a result, Antero expects net marketing expense to be reduced by approximately 35% in the second half of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the first quarter of 2016 was $1.49 per Mcfe, which is a 2% increase compared to $1.46 per Mcfe in the prior year quarter. The per unit cash production expense for the quarter included $0.07 per Mcfe for lease operating costs, $1.30 per Mcfe for gathering, compression and transportation costs and $0.12 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the first quarter of 2016, excluding non-cash equity-based compensation expense, was $0.21 per Mcfe, a 9% decrease from the first quarter of 2015. The per unit decrease was primarily driven by the increase in production levels. Per unit depreciation, depletion and amortization expense decreased 12% from the prior year quarter to $1.20 per Mcfe, primarily driven by lower development costs.
Adjusted EBITDAX of $355 million for the first quarter of 2016 was in line with the prior year quarter and increased 15% sequentially. Adjusted EBITDAX margin for the quarter was $2.22 per Mcfe, representing a 16% decrease from the prior year quarter primarily due to lower commodity prices, but flat sequentially. For the first quarter of 2016, cash flow from operations before changes in working capital was $291 which was also in line with the prior year quarter and increased 22% sequentially.
For a description of adjusted EBITDAX and adjusted EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income attributable to Antero Resources Corporation and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com
Low pressure gathering volumes for the first quarter of 2016 averaged 1,303 MMcf/d, a 39% increase from the first quarter of 2015 and a 16% increase sequentially. High pressure gathering volumes for the first quarter of 2016 averaged 1,222 MMcf/d, an 8% increase from the first quarter of 2015 and a 2% increase sequentially. Compression volumes for the first quarter of 2016 averaged 606 MMcf/d, a 69% increase from the first quarter of 2015 and a 27% increase sequentially. Volumetric throughput growth was driven by production growth from Antero. Condensate gathering volumes averaged 2,965 Bbl/d during the quarter, a 23% increase from the first quarter of 2015 and a 25% decrease sequentially. The sequential decrease was driven by Antero shifting Ohio Utica Shale development from its Highly-Rich Gas / Condensate area to estimated higher rate of return locations in the Highly-Rich Gas area. Fresh water delivery volumes averaged 97,331 Bbl/d during the first quarter of 2016, a 7% decrease from the first quarter of 2015 and 19% decrease sequentially. The decrease in fresh water delivery volumes was driven by reduced well completion activity by Antero.
For the three months ended March 31, 2016, Antero Midstream reported revenues of $136 million, comprised of $69 million in revenues from the Gathering and Compression segment and $67 million in revenues from the Water Handling and Treatment segment. Revenues increased 58% compared to the prior year quarter, driven by the startup of our produced water handling and high rate water transfer services business in the fourth quarter of 2015. Water Handling and Treatment segment revenues include $34 million from produced water handling and high rate water transfer services Antero Midstream provides to Antero billed at cost plus 3%. Direct operating expenses for the Gathering and Compression and Water Handling and Treatment segments were $8 million and $41 million, respectively, for a total of $49 million in direct operating expenses. Water Handling and Treatment direct operating expenses include $33 million from produced water handling and high rate water transfer services. Direct operating expenses increased 155% year over year, driven primarily by the inclusion of produced water handling and high rate water transfer services, as well as the expansion of Antero Midstream's gathering and compression and fresh water delivery assets to support the production growth of Antero. General and administrative expenses were $7 million during the first quarter of 2016. General and administrative expenses increased $1 million, or 16%, as compared to the first quarter of 2015. Total cash and non-cash operating expenses increased by 72% year over year totaling $89 million, including $24 million of depreciation.
The Board of Directors of Antero Resources Midstream Management LLC, the general partner of Antero Midstream, declared a cash distribution of $0.235 per unit ($0.94 per unit annualized) for the first quarter of 2016. The distribution represents a 31% increase compared to the prior year quarter and a 7% increase sequentially. The distribution represents Antero Midstream's fifth consecutive quarterly distribution increase since its initial public offering in November 2014. The distribution will be payable on May 25, 2016 to unitholders of record as of May 11, 2016.
Balance Sheet and Liquidity
As of March 31, 2016, Antero's consolidated net debt was $4.7 billion of which $1.4 billion were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total lender commitments under these two facilities is currently $5.5 billion. Including $702 million in letters of credit outstanding, the company had $3.5 billion in available consolidated liquidity as of March 31, 2016. For a reconciliation of consolidated net debt to total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
First Quarter 2016 Capital Spending
Antero's drilling and completion costs for the three months ended March 31, 2016 were $395 million. In addition, the Company invested $29 million for land and $1 million in other capital projects. Antero Midstream invested $49 million for gathering and compression systems and $37 million for water infrastructure projects during the quarter.
Hedge Position
Antero currently has hedged 3.6 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from April 1, 2016 through December 31, 2022 at an average index price of $3.71 per MMBtu.
The following table summarizes Antero's hedge positions held as of March 31, 2016:
Period |
Natural Gas MMBtu/d |
Average Index price ($/MMBtu) |
Liquids Bbl/d |
Average Index price | ||
2Q 2016: |
||||||
TCO |
60,000 |
$4.77 |
— |
— | ||
Nymex HH |
1,110,000 |
$3.38 |
— |
— | ||
Dom South |
272,500 |
$5.17 |
— |
— | ||
CGTLA |
170,000 |
$3.94 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.57 | ||
2Q 2016 Total |
1,612,500 |
$3.80 |
30,000 |
$0.57 | ||
3Q 2016: |
||||||
TCO |
60,000 |
$4.81 |
— |
— | ||
Nymex HH |
1,110,000 |
$3.44 |
— |
— | ||
Dom South |
272,500 |
$5.24 |
— |
— | ||
CGTLA |
170,000 |
$4.03 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.58 | ||
3Q 2016 Total |
1,612,500 |
$3.86 |
30,000 |
$0.58 | ||
4Q 2016: |
||||||
TCO |
60,000 |
$5.01 |
— |
— | ||
Nymex HH |
1,110,000 |
$3.57 |
— |
— | ||
Dom South |
272,500 |
$5.47 |
— |
— | ||
CGTLA |
170,000 |
$4.20 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.61 | ||
4Q 2016 Total |
1,612,500 |
$4.01 |
30,000 |
$0.61 | ||
2017: |
||||||
Nymex HH |
1,370,000 |
$3.39 |
— |
— | ||
CGTLA |
420,000 |
$4.27 |
— |
— | ||
Chicago |
70,000 |
$4.57 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
36,500 |
$0.43 | ||
2017 Total |
1,860,000 |
$3.63 |
36,500 |
$0.43 | ||
2018 |
2,002,500 |
$3.91 |
2,000 |
$0.65 | ||
2019 |
2,330,000 |
$3.70 |
— |
— | ||
2020 |
1,377,500 |
$3.66 |
— |
— | ||
2021 |
630,000 |
$3.36 |
— |
— | ||
2021 |
120,000 |
$3.24 |
— |
— |
Approximately 69% of Antero's 2016 natural gas financial hedge portfolio is made up of Nymex Henry Hub hedges and 31% is tied to Appalachian Basin or Gulf Coast indices. Antero has the ability to physically deliver a substantial portion of its natural gas production through direct firm transportation to the Columbia Gulf Coast Onshore index near Henry, Louisiana, the index for Nymex Henry Hub pricing, essentially eliminating basis risk on the Company's Nymex Henry Hub hedges. Antero has 15 different counterparties to its hedge contracts, all of which are lenders in the Company's bank credit facility.
Conference Call
A conference call is scheduled on Thursday, April 28, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 866-605-3851 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, May 6, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10083144.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, May 6, 2016 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the April 28, 2016 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Adjusted net revenue as set forth in this release represents total operating revenue adjusted for certain non-cash items, including unsettled hedge gains and losses. Antero believes that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to adjusted net revenue:
Three months ended | ||||||
2015 |
2016 | |||||
Total operating revenue |
$ |
1,229,687 |
$ |
721,004 | ||
Hedge gains |
(759,554) |
(279,924) | ||||
Cash receipts for settled hedges |
184,840 |
324,347 | ||||
Adjusted net revenue |
$ |
654,973 |
$ |
765,427 |
Adjusted net income attributable to Antero Resources Corporation as set forth in this release represents net income attributable to Antero Resources Corporation, adjusted for certain items. Antero believes that adjusted net income attributable to Antero Resources Corporation is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income attributable to Antero Resources Corporation is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) attributable to Antero Resources Corporation as an indicator of financial performance. The following table reconciles net income (loss) attributable to Antero Resources Corporation to adjusted net income attributable to Antero Resources Corporation:
Three months ended |
|||||||
March 31, |
|||||||
2015 |
2016 |
||||||
Net income (loss) attributable to Antero Resources Corporation |
$ |
394,431 |
$ |
(5,055) |
|||
Non-cash commodity derivative (gains) losses on unsettled derivatives |
(574,714) |
44,423 |
|||||
Impairment of unproved properties |
8,577 |
15,526 |
|||||
Equity-based compensation |
27,783 |
23,470 |
|||||
Contract termination and rig stacking |
8,965 |
— |
|||||
Income tax effect of reconciling items |
205,629 |
(31,273) |
|||||
Adjusted net income attributable to Antero Resources Corporation |
$ |
70,671 |
$ |
47,091 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release:
Three months ended | ||||||
2015 |
2016 | |||||
Net cash provided by operating activities |
$ |
351,440 |
340,168 | |||
Net change in working capital |
(58,983) |
(48,830) | ||||
Cash flow from operations before changes in working capital |
$ |
292,457 |
291,338 |
The following table reconciles consolidated total debt to consolidated net debt as used in this release:
December 31, |
March 31, | |||||||
2015 |
2016 | |||||||
Bank credit facilities |
$ |
1,327,000 |
$ |
1,360,000 | ||||
6.00% senior notes due 2020 |
525,000 |
525,000 | ||||||
5.375% senior notes due 2021 |
1,000,000 |
1,000,000 | ||||||
5.125% senior notes due 2022 |
1,100,000 |
1,100,000 | ||||||
5.625% senior notes due 2023 |
750,000 |
750,000 | ||||||
Net unamortized premium |
6,513 |
6,245 | ||||||
Net unamortized debt issuance costs |
(39,731) |
(38,436) | ||||||
Total debt |
$ |
4,668,782 |
$ |
4,702,809 | ||||
Cash and cash equivalents |
23,473 |
39,870 | ||||||
Consolidated net debt |
$ |
4,645,309 |
$ |
4,662,939 | ||||
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating adjusted EBITDAX reported by different companies. The following table represents a reconciliation of the Company's net income including noncontrolling interest to adjusted EBITDAX, a reconciliation of total adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash settled hedges to adjusted EBITDAX margin:
Three months ended | |||||||||
March 31, | |||||||||
2015 |
2016 | ||||||||
Net income including noncontrolling interest |
$ |
399,171 |
$ |
10,650 | |||||
Commodity derivative gains |
(759,554) |
(279,924) | |||||||
Gains on settled derivative instruments |
184,840 |
324,347 | |||||||
Interest expense |
53,185 |
63,284 | |||||||
Income tax expense |
247,338 |
4,815 | |||||||
Depreciation, depletion, amortization, and accretion |
182,700 |
192,180 | |||||||
Impairment of unproved properties |
8,577 |
15,526 | |||||||
Exploration expense |
1,371 |
1,014 | |||||||
Equity-based compensation expense |
27,783 |
23,470 | |||||||
State franchise taxes |
235 |
39 | |||||||
Contract termination and rig stacking |
8,965 |
— | |||||||
Total Adjusted EBITDAX |
354,611 |
355,401 | |||||||
Interest expense |
(53,185) |
(63,284) | |||||||
Exploration expense |
(1,371) |
(1,014) | |||||||
Changes in current assets and liabilities |
58,983 |
48,830 | |||||||
State franchise taxes |
(235) |
(39) | |||||||
Other non-cash items |
(7,363) |
274 | |||||||
Net cash provided by operating activities |
$ |
351,440 |
$ |
340,168 | |||||
Three months ended | ||||||
March 31, | ||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2015 |
2016 | ||||
Realized price before cash receipts for settled hedges |
$ |
3.04 |
$ |
2.11 | ||
Gathering, compression, and water handling revenues |
0.04 |
0.02 | ||||
Lease operating expense |
(0.06) |
(0.07) | ||||
Gathering, compression, processing and transportation costs |
(1.22) |
(1.30) | ||||
Marketing, net |
(0.12) |
(0.24) | ||||
Production taxes |
(0.18) |
(0.12) | ||||
General and administrative(1) |
(0.23) |
(0.21) | ||||
Adjusted EBITDAX margin before settled hedges |
1.27 |
0.19 | ||||
Cash receipts for settled hedges |
1.38 |
2.03 | ||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.65 |
$ |
2.22 | ||
(1) Excludes equity-based stock compensation that is included in G&A |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
For more information, contact Michael Kennedy – SVP – Finance, at (303) 357-6782 or mkennedy@anteroresources.com.
ANTERO RESOURCES CORPORATION |
|||||||
Three Months Ended March 31, |
|||||||
2015 |
2016 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
23,473 |
39,870 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016 |
79,404 |
78,753 |
|||||
Accrued revenue |
128,242 |
136,446 |
|||||
Derivative instruments |
1,009,030 |
975,199 |
|||||
Other current assets |
8,087 |
8,072 |
|||||
Total current assets |
1,248,236 |
1,238,340 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
1,996,081 |
1,994,377 |
|||||
Proved properties |
8,211,106 |
8,531,113 |
|||||
Water handling and treatment systems |
565,616 |
582,331 |
|||||
Gathering systems and facilities |
1,502,396 |
1,543,766 |
|||||
Other property and equipment |
46,415 |
46,741 |
|||||
12,321,614 |
12,698,328 |
||||||
Less accumulated depletion, depreciation, and amortization |
(1,589,372) |
(1,780,526) |
|||||
Property and equipment, net |
10,732,242 |
10,917,802 |
|||||
Derivative instruments |
2,108,450 |
2,098,233 |
|||||
Other assets |
26,565 |
34,337 |
|||||
Total assets |
$ |
14,115,493 |
14,288,712 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
364,160 |
250,797 |
||||
Accrued liabilities |
194,076 |
241,676 |
|||||
Revenue distributions payable |
129,949 |
132,918 |
|||||
Other current liabilities |
19,085 |
19,693 |
|||||
Total current liabilities |
707,270 |
645,084 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,668,782 |
4,702,809 |
|||||
Deferred income tax liability |
1,370,686 |
1,439,825 |
|||||
Derivative instruments |
— |
375 |
|||||
Other liabilities |
82,077 |
80,275 |
|||||
Total liabilities |
6,828,815 |
6,868,368 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 277,035,558 shares and 277,061,336 shares, respectively |
2,770 |
2,771 |
|||||
Additional paid-in capital |
4,122,811 |
4,251,755 |
|||||
Accumulated earnings |
1,808,811 |
1,803,756 |
|||||
Total stockholders' equity |
5,934,392 |
6,058,282 |
|||||
Noncontrolling interest in consolidated subsidiary |
1,352,286 |
1,362,062 |
|||||
Total equity |
7,286,678 |
7,420,344 |
|||||
Total liabilities and equity |
$ |
14,115,493 |
14,288,712 |
ANTERO RESOURCES CORPORATION |
||||||
Three Months Ended March 31, |
||||||
2015 |
2016 |
|||||
Revenue: |
||||||
Natural gas sales |
$ |
314,942 |
$ |
254,776 |
||
Natural gas liquids sales |
78,786 |
73,065 |
||||
Oil sales |
12,457 |
10,179 |
||||
Gathering, compression, and water handling |
6,168 |
3,844 |
||||
Marketing |
57,780 |
99,216 |
||||
Commodity derivative fair value gains |
759,554 |
279,924 |
||||
Total revenue |
1,229,687 |
721,004 |
||||
Operating expenses: |
||||||
Lease operating |
8,102 |
11,293 |
||||
Gathering, compression, processing, and transportation |
163,662 |
208,738 |
||||
Production and ad valorem taxes |
24,218 |
19,284 |
||||
Marketing |
73,349 |
137,933 |
||||
Exploration |
1,371 |
1,014 |
||||
Impairment of unproved properties |
8,577 |
15,526 |
||||
Depletion, depreciation, and amortization |
182,300 |
191,582 |
||||
Accretion of asset retirement obligations |
400 |
598 |
||||
General and administrative (including equity-based compensation expense of $27,783 and $23,470 in 2015 and 2016, respectively) |
59,049 |
56,287 |
||||
Contract termination and rig stacking |
8,965 |
— |
||||
Total operating expenses |
529,993 |
642,255 |
||||
Operating income |
699,694 |
78,749 |
||||
Other expenses: |
||||||
Interest |
(53,185) |
(63,284) |
||||
Income before income taxes |
646,509 |
15,465 |
||||
Provision for income tax expense |
(247,338) |
(4,815) |
||||
Net income and comprehensive income including noncontrolling interest |
399,171 |
10,650 |
||||
Net income and comprehensive income attributable to noncontrolling interest |
4,740 |
15,705 |
||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
394,431 |
$ |
(5,055) |
||
Earnings (loss) per common share |
$ |
1.49 |
$ |
(0.02) |
||
Earnings (loss) per common share—assuming dilution |
$ |
1.49 |
$ |
(0.02) |
||
Weighted average number of shares outstanding: |
||||||
Basic |
265,294,794 |
277,050,344 |
||||
Diluted |
265,300,080 |
277,050,344 |
ANTERO RESOURCES CORPORATION |
|||||||
Three Months Ended March 31, |
|||||||
2015 |
2016 |
||||||
Cash flows from operating activities: |
|||||||
Net income including noncontrolling interest |
399,171 |
10,650 |
|||||
Adjustment to reconcile net income to net cash provided by operating activities: |
|||||||
Depletion, depreciation, amortization, and accretion |
182,700 |
192,180 |
|||||
Impairment of unproved properties |
8,577 |
15,526 |
|||||
Derivative fair value gains |
(759,554) |
(279,924) |
|||||
Gains on settled derivatives |
184,840 |
324,347 |
|||||
Deferred income tax expense |
247,338 |
4,815 |
|||||
Equity-based compensation expense |
27,783 |
23,470 |
|||||
Other |
1,602 |
274 |
|||||
Changes in current assets and liabilities: |
|||||||
Accounts receivable |
(42,207) |
651 |
|||||
Accrued revenue |
25,654 |
(8,204) |
|||||
Other current assets |
1,607 |
15 |
|||||
Accounts payable |
(513) |
5,643 |
|||||
Accrued liabilities |
72,634 |
47,785 |
|||||
Revenue distributions payable |
1,103 |
2,969 |
|||||
Other current liabilities |
705 |
(29) |
|||||
Net cash provided by operating activities |
351,440 |
340,168 |
|||||
Cash flows used in investing activities: |
|||||||
Additions to unproved properties |
(51,541) |
(28,675) |
|||||
Drilling and completion costs |
(569,068) |
(395,185) |
|||||
Additions to water handling and treatment systems |
(22,126) |
(37,036) |
|||||
Additions to gathering systems and facilities |
(125,988) |
(48,686) |
|||||
Additions to other property and equipment |
(2,103) |
(541) |
|||||
Change in other assets |
(8,410) |
(9,172) |
|||||
Proceeds from asset sales |
40,000 |
— |
|||||
Net cash used in investing activities |
(739,236) |
(519,295) |
|||||
Cash flows from financing activities: |
|||||||
Issuance of common stock |
537,875 |
— |
|||||
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation |
— |
178,000 |
|||||
Issuance of senior notes |
750,000 |
— |
|||||
Borrowings (repayments) on bank credit facilities, net |
(940,000) |
33,000 |
|||||
Payments of deferred financing costs |
(15,022) |
(64) |
|||||
Distributions to noncontrolling interest in consolidated subsidiary |
(4,338) |
(14,013) |
|||||
Employee tax withholding for settlement of equity compensation awards |
(46) |
(117) |
|||||
Other |
(1,161) |
(1,282) |
|||||
Net cash provided by financing activities |
327,308 |
195,524 |
|||||
Net increase (decrease) in cash and cash equivalents |
(60,488) |
16,397 |
|||||
Cash and cash equivalents, beginning of period |
245,979 |
23,473 |
|||||
Cash and cash equivalents, end of period |
185,491 |
39,870 |
|||||
Supplemental disclosure of cash flow information: |
|||||||
Cash paid during the period for interest |
14,563 |
14,350 |
|||||
Supplemental disclosure of noncash investing activities: |
|||||||
Decrease in accounts payable and accrued liabilities for additions to property and equipment |
(184,753) |
(119,191) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended March 31, 2015 compared to the three months ended March 31, 2016
Three Months Ended March 31, |
Amount of |
Percent |
||||||||||
(in thousands) |
2015 |
2016 |
(Decrease) |
Change |
||||||||
Operating revenues: |
||||||||||||
Natural gas sales |
$ |
314,942 |
$ |
254,776 |
$ |
(60,166) |
(19) |
% | ||||
NGLs sales |
78,786 |
73,065 |
(5,721) |
(7) |
% | |||||||
Oil sales |
12,457 |
10,179 |
(2,278) |
(18) |
% | |||||||
Gathering, compression, and water handling and treatment |
6,168 |
3,844 |
(2,324) |
(38) |
% | |||||||
Marketing |
57,780 |
99,216 |
41,436 |
72 |
% | |||||||
Commodity derivative fair value gains |
759,554 |
279,924 |
(479,630) |
(63) |
% | |||||||
Total operating revenues |
1,229,687 |
721,004 |
(508,683) |
(41) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
8,102 |
11,293 |
3,191 |
39 |
% | |||||||
Gathering, compression, processing, and transportation |
163,662 |
208,738 |
45,076 |
28 |
% | |||||||
Production and ad valorem taxes |
24,218 |
19,284 |
(4,934) |
(20) |
% | |||||||
Marketing |
73,349 |
137,933 |
64,584 |
88 |
% | |||||||
Exploration |
1,371 |
1,014 |
(357) |
(26) |
% | |||||||
Impairment of unproved properties |
8,577 |
15,526 |
6,949 |
81 |
% | |||||||
Depletion, depreciation, and amortization |
182,300 |
191,582 |
9,282 |
5 |
% | |||||||
Accretion of asset retirement obligations |
400 |
598 |
198 |
50 |
% | |||||||
General and administrative (before equity-based compensation) |
31,266 |
32,817 |
1,551 |
5 |
% | |||||||
Equity-based compensation |
27,783 |
23,470 |
(4,313) |
(16) |
% | |||||||
Contract termination and rig stacking |
8,965 |
— |
(8,965) |
* |
||||||||
Total operating expenses |
529,993 |
642,255 |
112,262 |
21 |
% | |||||||
Operating income |
699,694 |
78,749 |
(620,945) |
(89) |
% | |||||||
Other Expenses: |
||||||||||||
Interest expense |
(53,185) |
(63,284) |
(10,099) |
19 |
% | |||||||
Income before income taxes |
646,509 |
15,465 |
(631,044) |
(98) |
% | |||||||
Income tax expense |
(247,338) |
(4,815) |
242,523 |
(98) |
% | |||||||
Net income and comprehensive income including noncontrolling interest |
399,171 |
10,650 |
(388,521) |
(97) |
% | |||||||
Net income and comprehensive income attributable to noncontrolling interest |
4,740 |
15,705 |
10,965 |
231 |
% | |||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
394,431 |
$ |
(5,055) |
$ |
(399,486) |
* |
|||||
Adjusted EBITDAX |
$ |
354,611 |
$ |
355,401 |
$ |
790 |
— |
% | ||||
Three Months Ended March 31, |
Amount of |
Percent |
||||||||||
2015 |
2016 |
(Decrease) |
Change |
|||||||||
Production data: |
||||||||||||
Natural gas (Bcf) |
112 |
123 |
11 |
9 |
% | |||||||
C2 Ethane (MBbl) |
— |
1,081 |
1,081 |
* |
% | |||||||
C3+ NGLs (MBbl) |
3,241 |
4,681 |
1,440 |
44 |
% | |||||||
Oil (MBbl) |
366 |
472 |
106 |
29 |
% | |||||||
Combined (Bcfe) |
134 |
160 |
26 |
20 |
% | |||||||
Daily combined production (MMcfe/d) |
1,485 |
1,758 |
273 |
18 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
2.81 |
$ |
2.08 |
$ |
(0.73) |
(26) |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
6.68 |
$ |
6.68 |
* |
% | ||||
C3+ NGLs (per Bbl) |
$ |
24.31 |
$ |
14.07 |
$ |
(10.24) |
(42) |
% | ||||
Oil (per Bbl) |
$ |
34.03 |
$ |
21.56 |
$ |
(12.47) |
(37) |
% | ||||
Combined (per Mcfe) |
$ |
3.04 |
$ |
2.11 |
$ |
(0.93) |
(31) |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.37 |
$ |
4.54 |
$ |
0.17 |
4 |
% | ||||
C2 Ethane (per Bbl) |
$ |
— |
$ |
6.68 |
$ |
6.68 |
* |
% | ||||
C3+ NGLs (per Bbl) |
$ |
26.23 |
$ |
18.88 |
$ |
(7.35) |
(28) |
% | ||||
Oil (per Bbl) |
$ |
45.08 |
$ |
21.56 |
$ |
(23.52) |
(52) |
% | ||||
Combined (per Mcfe) |
$ |
4.42 |
$ |
4.14 |
$ |
(0.28) |
(6) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.06 |
$ |
0.07 |
$ |
0.01 |
17 |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.22 |
$ |
1.30 |
$ |
0.08 |
7 |
% | ||||
Production and ad valorem taxes |
$ |
0.18 |
$ |
0.12 |
$ |
(0.06) |
(33) |
% | ||||
Marketing, net |
$ |
0.12 |
$ |
0.24 |
$ |
0.12 |
100 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.37 |
$ |
1.20 |
$ |
(0.17) |
(12) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.23 |
$ |
0.21 |
$ |
(0.02) |
(9) |
% |
* Not meaningful or applicable.
Logo - http://photos.prnewswire.com/prnh/20131101/LA09101LOGO
SOURCE Antero Resources Corporation
DENVER, April 14, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today provided its first quarter 2016 operations update.
Highlights Include:
Recent Developments
Borrowing Base Reaffirmed at $4.5 Billion
As a result of the recent spring borrowing base redetermination, Antero's borrowing base under its upstream credit facility was reaffirmed at $4.5 billion. Lender commitments under the facility remain at $4.0 billion. The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., is currently comprised of 29 banks.
Antero Midstream Secondary Unit Offering
On March 24, 2016 Antero priced the sale of 8,000,000 Antero Midstream common units for net proceeds of approximately $178 million. Net proceeds from the offering will be used to fund a portion of Antero's expected 2016 capital expenditures. Pro forma for the offering, Antero has approximately $3.7 billion of liquidity as of year-end 2015 and owns a 62% interest in Antero Midstream.
Operating Update
All operational figures are as of the date of this release unless otherwise noted.
Antero's net daily production for the first quarter of 2016 averaged 1,758 MMcfe/d, including 68,516 Bbl/d of liquids (23% liquids). First quarter 2016 production represents an organic production growth rate of 18% and 17% from the first quarter of 2015 and fourth quarter of 2015, respectively. First quarter 2016 C3+ natural gas liquids ("NGLs") and oil production averaged 51,443 Bbl/d and 5,189 Bbl/d, respectively. Ethane (C2) production averaged 11,884 Bbl/d, as Antero began recovering ethane in December 2015 when the first de-ethanizer was commissioned at the Sherwood processing facility. Total liquids production for the first quarter of 2016 represents an organic production growth rate of 71% and 25% from the first quarter of 2015 and fourth quarter of 2015, respectively.
Current well costs are $0.95 million and $1.14 million per 1,000 feet of lateral in the Marcellus and Utica, respectively, representing a 19% and 16% decline since 2015. The reduction in well costs from 2015 is primarily driven by reduced service costs on completions and a number of operational efficiencies. In the Marcellus, drilling days during the quarter ended March 31, 2016 were reduced from 24 days to 21 days and stages completed per day increased from 3.5 stages per day to 3.8 stages per day. During the quarter, Antero drilled 5,291 feet of lateral in a 24 hour period, surpassing the previous company record by more than 1,000 feet. All of Antero's top 10 drilling days in the Marcellus, since inception, have occurred in 2016. In the Utica, drilling days during the first quarter were reduced from 31 days to 24 days and stages completed per day increased from 3.7 stages per day to 4.4 stages per day. In summary, Antero's current all-in completed well cost for a 9,000' lateral in the Marcellus is approximately $8.5 million and in the Utica is approximately $10.3 million.
Commenting on first quarter 2016 production and improved well costs, Paul Rady, Chairman of the Board and CEO said, "We had an excellent quarter operationally, once again achieving record production levels while also reducing well costs an additional 16% to 19% from 2015 levels. These lower well costs were the result of our continued operational efficiencies and our ability to restructure a number of our service contracts that substantially drove down completions costs. Reducing well costs has been a high priority for Antero over the past 18 months, as it provides us with another lever to improve well economics and drive value for our shareholders. We have also locked in attractive product prices with our industry leading hedge book and continue to realize improved pricing through our firm transportation portfolio. When you combine this attractive realized pricing with the continued reduction in well costs, you can see why we have been able to continue to deliver attractive returns in one of the sharpest commodity price downturns in decades."
Antero's average realized natural gas price before hedging for the first quarter of 2016 was $2.08 per Mcf, a $0.01 differential to the Nymex average price for the period. The first quarter of 2016 was the first full quarter that the Stonewall gathering pipeline was in service. This development resulted in Antero selling approximately 99% of its gas production to favorably priced markets during the quarter, including TCO, Chicago, MichCon, TGP and Nymex, up significantly from 83% in the fourth quarter of 2015.
Antero's average realized natural gas price after hedging for the first quarter of 2016 was $4.54 per Mcf, a $2.45 premium to the Nymex average price for the period. For the first quarter of 2016, Antero realized a cash settled natural gas hedge gain of $302 million, or $2.46 per Mcf. This cash settled natural gas hedge gain included $107 million associated with hedges at the Dominion South index, $151 million associated with Nymex hedges, $10 million associated with hedges at the TCO index and $34 million associated with hedges at the Columbia Gulf Louisiana index.
Antero's average realized C3+ NGL price before hedging for the first quarter of 2016 was $14.07 per barrel, or approximately 42% of the WTI oil price average for the period. The Company's average realized C3+ NGL price after hedging for the quarter was $18.88 per barrel, or 57% of the WTI oil price average for the period. For the first quarter of 2016, Antero realized a cash settled C3+ NGL hedge gain of $23 million, or $4.81 per barrel. Antero's average realized ethane price for the quarter was $6.68 per barrel, or $0.16 per gallon.
Antero's average realized oil price before hedging for the first quarter of 2016 was $21.56 per barrel, an $11.62 per barrel differential to the WTI oil price. Antero's liquids production and realizations for the first quarter of 2016 added an incremental $0.03 per Mcfe, increasing the average natural gas realized price before hedging from $2.08 per Mcf to $2.11 per Mcfe. The average all-in natural gas equivalent price, including NGLs, oil and hedge settlements, was $4.14 per Mcfe for the first quarter of 2016.
The following table details the components of average net production and average realized prices for the three months ended March 31, 2016:
Three Months Ended March 31, 2016 | ||||||||||||||
Gas |
Oil |
C3+ NGLs |
Ethane |
Combined | ||||||||||
Average Net Production |
1,347 |
5,189 |
51,443 |
11,884 |
1,758 | |||||||||
Average Realized Prices |
Gas ($/Mcf) |
Oil ($/Bbl) |
C3+ NGLs |
Ethane |
Combined | |||||||||
Average realized price before settled derivatives |
$ |
2.08 |
$ |
21.56 |
$ |
14.07 |
$ |
6.68 |
$ |
2.11 | ||||
Settled derivatives |
2.46 |
– |
4.81 |
– |
2.03 | |||||||||
Average realized price after settled derivatives |
$ |
4.54 |
$ |
21.56 |
$ |
18.88 |
$ |
6.68 |
$ |
4.14 | ||||
Nymex average price |
$ |
2.09 |
$ |
33.18 |
$ |
2.09 | ||||||||
Premium / (Differential) to Nymex |
$ |
2.45 |
$ |
(11.62) |
$ |
2.05 |
Commenting on product pricing and the development plan, Glen Warren, President and Chief Financial Officer, said "Despite the continued downward pressure on commodity prices, our market-leading hedge and firm transportation portfolios have continued to serve as a differentiating factor for Antero. Gas price realizations before hedging were only a $0.01 differential to Nymex for the quarter, highlighting Antero's ability to access favorably priced markets through our firm transportation portfolio. In addition, our substantial hedge position enables us to maintain operational momentum in a lower commodity price environment. The stability of our cash flow combined with the operational flexibility we have created through our drilled but uncompleted well inventory and our relatively low maintenance capital provides us the ability to deliver 17% sequential quarterly growth in the first quarter of 2016 and target 20% growth in 2017."
Marcellus Shale — Antero completed and placed on line 19 horizontal Marcellus wells during the first quarter of 2016. The average lateral length for the 19 wells was approximately 8,000 feet. Of the 19 wells completed in the first quarter of 2016, 15 have been on line for more than 30 days and had an average 30-day rate of 17.6 MMcfe/d assuming ethane rejection (22% liquids). Sand placement for completions increased to 98% during the quarter. While the well results in the first quarter of 2016 were driven by legacy completions, Antero is currently completing wells with approximately 25% higher fluid volume and proppant loading. The Company is currently operating seven drilling rigs and four completion crews in the Marcellus Shale play.
Utica Shale — Antero completed and placed on line 13 horizontal Utica wells during the first quarter of 2016. The average lateral length for the 13 wells was approximately 8,500 feet. Of the 13 wells completed in the first quarter of 2016, 8 have been on line for more than 30 days and had an average restricted 30-day rate of 14.1 MMcfe/d while rejecting ethane (14% liquids). During the quarter, Antero completed the Fogle Unit 1H well in Noble County, Ohio with encouraging early results. Importantly, this well represented the most southerly drilled location to date on Antero's Utica acreage. Antero is currently operating one drilling rig and one completion crew in the Utica Shale play.
First Quarter 2016 Earnings Release and Call
Antero plans to issue its first quarter 2016 earnings release on Wednesday, April 27, 2016 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, April 28, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 866-605-3851 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Friday, May 6, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10083144.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, May 6, 2016 at 9:00 am MT.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources
DENVER, April 1, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) and Antero Midstream (NYSE:AM) (collectively, "Antero") today announced that Christopher R. Manning has resigned from the board of directors of Antero Resources and the board of directors of the general partner of Antero Midstream. Neither Antero Resources nor Antero Midstream has plans to fill the vacated board seats in the near term.
Paul M. Rady, Chairman and CEO of Antero Resources and Antero Midstream commented, "I would like to thank Chris for his contribution to Antero's success over the last 11 years. When Chris first joined Antero's board in 2005, we were a small, privately held producer that had just completed the sale of our Barnett Shale assets to XTO Energy. As we transformed Antero into a leading Appalachian upstream company and one of the top natural gas producers in the U.S., as well as one of the highest growth midstream MLPs, Chris has provided valuable insight and expertise every step of the way. We are grateful for his contributions to Antero over the years and wish him the very best in the future."
Mr. Manning commented, "It has been an honor and a privilege to have been involved with Antero since its inception. Working with my fellow directors at both companies and the Antero management team led by Paul Rady and Glen Warren has been extremely rewarding and I wish them the best in their continued management of two great companies with world class assets."
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Antero Resources' website is located at www.anteroresources.com. Antero Midstream is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia, Ohio and Pennsylvania, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio.
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SOURCE Antero Resources; Antero Midstream
DENVER, March 24, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Company") announced today the pricing of an underwritten public offering of 8,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream Partners LP (NYSE: AM) (the "Partnership") held by Antero Resources at a price of $22.40 per common unit for aggregate gross proceeds of approximately $179 million before estimated offering expenses. In connection with the Offering, Antero Resources granted the underwriter a 30-day option to purchase up to an additional 1,200,000 common units. After giving effect to the Offering, and assuming no exercise of the underwriter's option to purchase additional common units, Antero Resources will own approximately 62% of the Partnership's outstanding common and subordinated units.
The common units are being sold in the Offering pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission (the "SEC"). The Offering is expected to close on March 30, 2016, subject to customary closing conditions. Antero Resources intends to use the proceeds from the Offering to repay borrowings under its credit facility and to fund a portion of its 2016 development program.
Citigroup is acting as the sole book-running manager for the Offering. The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Citigroup Global Markets Inc.
c/o Broadridge Financial Solutions
1155 Long Island Avenue
Edgewood, NY, 11717
1-800-831-9146
email: prospectus@citi.com
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero Resources' control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero Resources believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this press release is intended to constitute guidance with respect to Antero Midstream.
Antero Resources cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, Antero Resources' ability to meet development and drilling plans, the Company's ability to implement its hedge strategy and results, risk regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas, NGL and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero Resources' Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, March 24, 2016 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced the pricing of an underwritten public offering of 8,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream held by Antero Resources Corporation (NYSE: AR) at a price of $22.40 per unit for aggregate gross proceeds to Antero Resources Corporation of approximately $179 million before estimated offering expenses. Antero Midstream will not receive any proceeds from the sale of common units in the Offering. In connection with the Offering, Antero Resources granted the underwriter a 30-day option to purchase up to an additional 1,200,000 common units. After giving effect to the Offering, and assuming no exercise of the underwriter's option to purchase additional common units, Antero Resources will own approximately 62% of the Partnership's outstanding common and subordinated units.
The common units are being sold in the Offering pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission (the "SEC"). The Offering is expected to close on March 30, 2016, subject to customary closing conditions.
Citigroup is acting as the sole book-running manager for the Offering. The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Citigroup Global Markets Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY, 11717 1-800-831-9146 email: prospectus@citi.com |
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Midstream Partners LP is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia, Ohio and Pennsylvania, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio. The Partnership's website is located at www.anteromidstream.com.
Cautionary Statements
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although the Partnership believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
The Partnership cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the gathering and compression and water handling and treatment business. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2015.
For more information, contact Michael Kennedy – CFO of Antero Midstream at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream Partners LP
DENVER, March 23, 2016 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced that Antero Resources Corporation (NYSE: AR) ("Antero Resources" or the "Selling Unitholder") commenced an underwritten public offering of 8,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream held by Antero Resources. The common units are being sold in the Offering pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission (the "SEC"). In addition, the Selling Unitholder anticipates granting the underwriter a 30-day option to purchase up to an additional 1,200,000 common units. The underwriter intends to offer the units from time to time for sale in one or more transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices. Antero Midstream will not receive any proceeds from the sale of common units in the Offering.
Antero Resources currently owns 75,940,957 subordinated units and 40,929,378 common units, including 10,988,421 common units received as partial consideration in the water business drop down transaction in September 2015.
Citigroup is acting as the sole book-running manager for the Offering. The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Citigroup Global Markets Inc. c/o Broadridge Financial Solutions 1155 Long Island Avenue Edgewood, NY, 11717 1-800-831-9146 email: prospectus@citi.com |
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Midstream Partners LP is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia, Ohio and Pennsylvania, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio. The Partnership's website is located at www.anteromidstream.com.
Cautionary Statements
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although the Partnership believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
The Partnership cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the gathering and compression and water handling and treatment business. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2015.
For more information, contact Michael Kennedy – CFO of Antero Midstream at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream Partners LP
DENVER, March 23, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero Resources," the "Company" or the "Selling Unitholder") announced today the commencement of an underwritten public offering of 8,000,000 common units (the "Offering") representing limited partner interests in Antero Midstream Partners LP (NYSE: AM) held by Antero Resources. The common units are being sold in the Offering pursuant to an effective registration statement on Form S-3 previously filed with the Securities and Exchange Commission (the "SEC"). In addition, the Selling Unitholder anticipates granting the underwriter a 30-day option to purchase up to an additional 1,200,000 common units. The underwriter intends to offer the units from time to time for sale in one or more transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices. Antero Resources intends to use the proceeds from the Offering to repay borrowings under its credit facility and to fund a portion of its 2016 development program.
Antero Resources currently owns 75,940,957 subordinated units and 40,929,378 common units, including 10,988,421 common units received as partial consideration in the water business drop down transaction in September 2015.
Citigroup is acting as the sole book-running manager for the Offering. The Offering is being made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, copies of which, when available, may be obtained from:
Citigroup Global Markets Inc.
c/o Broadridge Financial Solutions
1155 Long Island Avenue
Edgewood, NY, 11717
1-800-831-9146
email: prospectus@citi.com
You may also get these documents for free by visiting the SEC's website at www.sec.gov. This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities described above, nor shall there be any sale of such securities in any state or jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this press release is intended to constitute guidance with respect to Antero Midstream.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, Antero's ability to meet development and drilling plans, the Company's ability to implement its hedge strategy and results, risk regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas, NGL and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
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SOURCE Antero Resources Corporation
DENVER, Feb. 24, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its fourth quarter and full-year 2015 financial and operating results. The relevant financial statements are included in Antero's Annual Report on Form 10-K for the year ended December 31, 2015, which has been filed with the Securities and Exchange Commission ("SEC").
Highlights for the Fourth Quarter of 2015:
Recent Developments
Year-End 2015 Proved and 3P Reserves
On January 27, 2016, Antero announced that proved reserves at December 31, 2015 were 13.2 Tcfe, a 4% increase compared to proved reserves at December 31, 2014. Finding and development cost for proved reserve additions was $0.80 per Mcfe. This finding and development cost includes drilling and completion capital as well as costs incurred for well pads, roads, certain wellhead facilities, acquisitions, land additions and gives effect to performance and price revisions. Proved developed reserves increased by 54% from year-end 2014 to 5.8 Tcfe at December 31, 2015. Additionally, the percentage of proved reserves classified as proved developed increased to 44% at December 31, 2015 as compared to 30% at year-end 2014.
The Company's proved, probable and possible ("3P") reserves at year-end 2015 totaled 37.1 Tcfe, which represents a 9% decrease compared to the previous year. Both proved and 3P reserves as of December 31, 2015 excluded 366 million barrels and 1,237 million barrels of ethane, respectively, that is expected to remain in the natural gas stream until such time that pricing supports full ethane recovery. Antero's Marcellus and Utica 3P drilling inventory totaled 3,719 locations at year-end 2015, of which approximately 78% were in the Marcellus.
2016 Capital Budget and Guidance
On February 17, 2016, Antero announced that it expects to invest $1.3 billion in 2016 for drilling and completion and $100 million for core leasehold acreage acquisitions. The $1.3 billion drilling and completion budget represents a 21% reduction from 2015 drilling and completion capital expenditures of $1.65 billion. Net daily production for 2016 is projected to average 1.715 Bcfe/d, a 15% increase over 2015 actual net daily production of 1.493 Bcfe/d. Antero's 2016 capital budget excludes Antero Midstream Partners LP's ("Antero Midstream") (NYSE: AM) $435 million capital budget relating to low and high pressure gathering pipelines, compressor stations and fresh water delivery and advanced wastewater treatment infrastructure.
Antero Resources Financial Results
As of December 31, 2015, Antero owned a 66% limited partner interest in Antero Midstream. Antero Midstream financial results are consolidated with Antero's results.
Fourth Quarter 2015 Financial Results
For the three months ended December 31, 2015, the Company reported net income from continuing operations attributable to common stockholders of $158 million, or $0.57 per basic and diluted share, compared to net income from continuing operations of $607 million or $2.32 per basic and diluted share in the fourth quarter for 2014. GAAP net income for the fourth quarter of 2015 included the following items:
Without the effect of these items, the Company's results for the fourth quarter of 2015 were as follows:
Net production for the fourth quarter of 2015 averaged 1,497 MMcfe/d, an 18% increase as compared to the fourth quarter of 2014 and a 1% decrease compared to the third quarter of 2015. The sequential decrease in production is primarily due to the periodic shut-in of production, averaging 45 MMcfe/d in the fourth quarter, as a result of Antero's decision not to sell gas at depressed pricing at the Dominion South and TETCO M2 indices. Net production was comprised of 1,168 MMcf/d of natural gas (78%), 49,005 Bbl/d of natural gas liquids ("NGL"s) (20%) and 5,751 Bbl/d of crude oil (2%). Fourth quarter 2015 net liquids production (NGLs and oil) of 54,757 Bbl/d increased 80% as compared to the fourth quarter of 2014 and 5% from the third quarter of 2015.
Average natural gas price before hedging decreased 42% from the prior year quarter to $2.13 per Mcf, a $0.14 per Mcf negative differential to Nymex, due to a 43% decline in Nymex. Approximately 83% of Antero's fourth quarter 2015 natural gas production was priced at favorable indices, including Columbia Gas Transmission (TCO), Nymex, Chicago and Gulf Coast. The remaining 17% of natural gas production was priced at various less favorable index pricing points including Dominion South and Tetco M2.
Average realized y-grade C3+ NGL price for the fourth quarter of 2015 was $17.37 per barrel, or 41% of Nymex WTI oil price, a 48% decrease as compared to the prior year quarter, and average realized oil price before hedging was $28.59 per barrel, a 52% decrease as compared to the fourth quarter of 2014. Antero's average realized ethane price (C2) for the fourth quarter of 2015 was $6.17 per barrel, or $0.15 per gallon. The fourth quarter of 2015 represented the first period in which Antero recovered ethane at the Sherwood processing plant in West Virginia. Average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, decreased from the prior year quarter by 42% to $2.32 per Mcfe due to a 43% decline in both Nymex WTI and Henry Hub natural gas prices.
Average realized natural gas price including hedges was $4.40 per Mcf for the fourth quarter of 2015, in line when compared to the fourth quarter of 2014. Average realized NGL price including hedges was $21.51 per barrel, a 37% decrease as compared to the fourth quarter of 2014. Average realized oil price including hedges was $40.85 per barrel, a 48% decrease as compared to the fourth quarter of 2014. Average natural gas-equivalent price including NGLs, oil and hedge settlements decreased by 9% to $4.28 per Mcfe for the fourth quarter of 2015 as compared to the fourth quarter of 2014. For the fourth quarter of 2015, Antero realized hedging gains of $270 million, or $1.96 per Mcfe.
Total operating revenues for the fourth quarter of 2015 were $905 million as compared to $1.5 billion for the fourth quarter of 2014. Operating revenue for the fourth quarter of 2015 included a $275 million non-cash gain on unsettled hedges while the fourth quarter of 2014 included a $853 million non-cash gain on unsettled hedges. Liquids production contributed 28% of combined natural gas, NGLs and oil revenue before hedges in the fourth quarter of 2015, as compared to a 22% contribution for the prior year quarter. Adjusted net revenue increased 8% to $630 million compared to the fourth quarter of 2014 (including cash-settled hedge gains and losses but excluding unsettled hedge gains and losses). For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the fourth quarter of 2015 was $33 million. Antero's marketing revenue was primarily associated with the sale of third-party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee Gas Pipeline.
Marketing expense for the fourth quarter of 2015 was $85 million. The largest components of marketing expense were the costs related to excess capacity, the cost of purchasing third-party gas and the firm transport demand costs associated with the Company's unused ATEX ethane pipeline capacity. During the fourth quarter, Antero gained access to over 1 Bcf/d of incremental Marcellus firm transportation takeaway capacity to more favorably priced markets through the Stonewall Pipeline and Tennessee Gas Pipeline. This takeaway capacity was only approximately 55% utilized in December as there was limited access to the Tennessee pipeline and the firm sales agreements utilizing the Stonewall capacity were not effective until January 1, 2016. The percentage utilization increased to approximately 80% in January 2016 with the commencement of the firm sales agreements utilizing the Stonewall pipeline and additional access to the Tennessee pipeline. Per unit net marketing expenses for the fourth quarter of 2015 were $0.38 per Mcfe.
Additionally, as previously disclosed, there was a one-time non-cash expense of $28 million during the quarter related to the buy-back and termination of a 130 BBtu/d firm sales contract with Dominion South related pricing. The termination of this contract has been classified as contract termination and rig stacking expense in the Company's statement of operations. Based on year-end 2015 strip pricing, the expected incremental revenue over the next two years from terminating this contract and instead selling the volumes at the TCO index is projected to be approximately $60 million, substantially exceeding the termination charge associated with this transaction.
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the fourth quarter of 2015 was $1.46 per Mcfe which is a 5% decrease compared to $1.54 per Mcfe in the prior year quarter. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.23 per Mcfe for gathering, compression and transportation costs and $0.15 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the fourth quarter of 2015, excluding non-cash equity-based compensation expense, was $0.27 per Mcfe, a 13% increase from the fourth quarter of 2014. The increase was primarily driven by increased staffing levels, as well as increases in legal and other general corporate expenses, partly due to Antero's increased development activities and production levels. Per unit depreciation, depletion and amortization expense decreased 13% from the prior year quarter to $1.18 per Mcfe, primarily driven by proved developed reserves increasing at a faster rate than the corresponding cost additions from wells completed during the quarter, partially offset by increased depreciation on midstream and water assets.
Adjusted EBITDAX of $308 million for the fourth quarter of 2015 was 7% lower than the prior year quarter primarily due to decreased product revenue. EBITDAX margin for the quarter was $2.23 per Mcfe, representing a 22% decrease from the prior year quarter primarily due to lower commodity prices. For the fourth quarter of 2015, cash flow from operations before changes in working capital decreased 14% from the prior year to $239 million.
For a description of Adjusted EBITDAX and EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income from continuing operations attributable to common stockholders and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com
Low pressure gathering volumes for the fourth quarter of 2015 averaged 1,124 MMcf/d, a 52% increase from the fourth quarter of 2014 and an 8% increase sequentially. High pressure gathering volumes for the fourth quarter of 2015 averaged 1,195 MMcf/d, a 32% increase from the fourth quarter of 2014 and a 2% decrease from the third quarter of 2015. Compression volumes for the fourth quarter of 2015 averaged 478 MMcf/d, a 115% increase from the fourth quarter of 2014 and a 10% increase sequentially. Condensate gathering volumes averaged 3,967 Bbl/d during the quarter, a 48% increase from the fourth quarter of 2015 and 39% increase from the third quarter of 2015. Volumetric throughput growth was driven primarily by production growth from Antero. Fresh water delivery volumes averaged 119,671 Bbl/d during the fourth quarter of 2015, a 36% decrease compared to the prior year quarter and a 78% increase sequentially.
For the three months ended December 31, 2015, Antero Midstream reported revenues of $132 million, comprised of $63 million in revenues from the Gathering and Compression segment and $69 million in revenues from the Water Handling segment. Direct operating expenses for the Gathering and Compression and Water Handling segments were $6 million and $34 million, respectively, for a total of $40 million in direct operating expenses. General and administrative expenses totaled $13 million during the fourth quarter of 2015, including $5 million of non-cash equity-based compensation expense. Total cash and non-cash operating expenses were $80 million, including $23 million of depreciation.
The Board of Directors of Antero Resources Midstream Management LLC, the general partner of Antero Midstream, declared a cash distribution of $0.22 per unit ($0.88 per unit annualized) for the fourth quarter of 2015. The distribution represents a 29% increase over the minimum quarterly distribution and a 7% increase quarter-over-quarter. The distribution represents Antero Midstream's fourth consecutive quarterly distribution increase since its initial public offering in November 2014. The distribution will be payable on February 29, 2016 to unitholders of record as of February 15, 2016.
2015 Financial Results
Net production for 2015 averaged 1,493 MMcfe/d, an increase of 48% from the prior year. Net production was comprised of 1,203 MMcf/d of natural gas (81%), 42,604 Bbl/d of NGLs (17%) and 5,694 Bbl/d of crude oil (2%). Net liquids production in 2015 averaged 48,298 Bbl/d, an increase of 110% over 2014 liquids production. The net production increase was primarily driven by liquids-rich production from 69 new Marcellus wells and 62 new Utica wells brought on line in 2015, all operated by Antero.
Average natural gas price before hedges decreased 42% from the prior year to $2.37 per Mcf, a $0.29 per Mcf negative differential to Nymex, in line with 2015 guidance of $0.20 per Mcf to $0.30 per Mcf. Approximately 69% of Antero's 2015 natural gas production was priced at favorable indices, including Columbia Gas Transmission (TCO), Nymex and Chicago. The remaining 31% of natural gas production was priced at various other less favorable index pricing points, including Dominion South and Tetco M2.
Average realized Y-grade C3+ NGL price for 2015 was $17.15 per barrel, or 35% of the Nymex WTI oil price, a 63% decrease as compared to the prior year and in line with 2015 guidance of 33% to 37% of WTI. Average realized oil price before hedging was $34.05 per barrel, a 58% decrease as compared to the prior year. Average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, decreased 47% to $2.52 per Mcfe from the prior year due to a 48% decline in Nymex WTI oil prices and 40% decline in Nymex Henry Hub natural gas prices, respectively.
Average realized natural gas price including hedges was $4.15 per Mcf for 2015, an 8% decrease as compared to 2014. Average realized NGL price including hedges was $20.57 per barrel, a 56% decrease compared to 2014. Average realized oil price including hedges was $42.38 per barrel, a 50% decrease as compared to 2014. Average natural gas-equivalent price including NGLs, oil and hedge settlements, decreased by 20% to $4.10 per Mcfe for 2015 as compared to 2014. For 2015, Antero realized hedging gains of $857 million, or $1.57 per Mcfe.
Total operating revenues for 2015 were $4.0 billion as compared to $2.7 billion for the prior year. Operating revenue for 2015 included a $1.5 billion non-cash gain on unsettled hedges while 2014 included a $732 million non-cash gain on unsettled hedges. Liquids production contributed 24% of combined natural gas, NGLs and oil revenue before hedges in 2015 compared to 25% during 2014. Non-GAAP adjusted net revenue increased 25% to $2.4 billion compared to 2014 (including cash-settled hedge gains and losses but excluding unsettled hedge gains and losses). For a reconciliation of adjusted net revenue to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for 2015 was $176 million. Antero's marketing revenue was primarily associated with the sale of third-party gas purchased to utilize the Company's excess firm transportation capacity on the Rockies Express Pipeline and Tennessee Gas Pipeline.
Marketing expense for 2015 was $299 million. The largest components of marketing expense include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs.
Net marketing expense for 2015 was $123 million, or $0.23 per Mcfe, in line with 2015 guidance of $0.20 to $0.30 per Mcfe.
Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for 2015 was $1.42 per Mcfe which is a 10% decrease compared to $1.58 per Mcfe in the prior year and ahead of 2015 guidance of $1.50 to $1.60 per Mcfe. The per unit cash production expense for 2015 included $0.07 per Mcfe for lease operating costs, $1.21 per Mcfe for gathering, compression and transportation costs and $0.14 per Mcfe for production and ad valorem taxes. The decrease was primarily due to decreases in fuel costs as compared to the prior year due to lower natural gas prices.
Per unit general and administrative expense for 2015, excluding non-cash equity based compensation expense, was $0.25 per Mcfe, an 11% decrease from 2014 and in line with 2015 guidance of $0.23 per Mcfe to $0.27 per Mcfe. The decrease was primarily driven by the significant increase in net production. Per unit depreciation, depletion and amortization expense was consistent with the prior year at $1.31 per Mcfe.
The Company reported net income from continuing operations attributable to common stockholders of $941 million ($3.43 per basic and diluted share) on a GAAP basis for 2015, including $1.5 billion of non-cash gains on unsettled hedges ($954 million net of tax), $98 million of non-cash equity-based compensation expense ($61 million net of tax), $104 million of impairments of unproved properties ($65 million net of tax), and $39 million of contract termination and rig stacking expense ($24 million net of tax). Excluding these items, adjusted net income from continuing operations attributable to common stockholders was $152 million ($0.56 per basic and diluted share) for 2015, representing a 52% decrease over the prior year.
Adjusted EBITDAX of $1.2 billion for 2015 was 5% higher than the prior year primarily due to a 48% increase in production, which was partially offset by a 20% decrease in the average per Mcfe price received after the impact of cash settled derivatives, net of the related increases in cash operating and general and administrative expenses. EBITDAX margin for 2015 was $2.24 per Mcfe, representing a 29% decrease from the prior year due to lower commodity prices. For 2015, cash flow from operations before changes in working capital was in line with the prior year at $976 million.
For a description of Adjusted EBITDAX and EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income from continuing operations attributable to common stockholders and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Balance Sheet and Liquidity
As of December 31, 2015, Antero's consolidated net debt was $4.7 billion of which $1.3 billion were borrowings outstanding under the Company's $5.5 billion of lender commitments on its senior secured revolving credit facilities. Including $702 million in letters of credit outstanding, the company had $3.5 billion in available consolidated liquidity as of December 31, 2015. For a reconciliation of consolidated net debt to total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
2015 Capital Spending
Antero's drilling and completion costs for the year ended December 31, 2015, were approximately $1.65 billion. In addition, the Company invested $199 million for additional leasehold interests, including $39 million for acquisitions and $160 million for land, and $80 million in Antero's fresh water distribution and wastewater treatment projects in the Marcellus and Utica Shale plays. Antero's drilling and completion costs for the three months ended December 31, 2015, were $301 million. In addition, the Company invested $28 million for additional leasehold interests during the fourth quarter of 2015.
Conference Call
A conference call is scheduled on Thursday, February 25, 2016, at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources." A telephone replay of the call will be available until Friday, March 4, 2016, at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10078393.
To access the live webcast and view the related earnings conference call presentation, visit Antero's website at www.anteroresources.com. The webcast will be archived for replay on the Company's website until March 4, 2016, at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the February 25, 2016 conference call. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Non-GAAP Financial Measures
Adjusted net revenue as set forth in this release represents total operating revenue adjusted for certain non-cash items, including unsettled hedge gains and losses and gains and losses on asset sales. Antero believes that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to adjusted net revenue:
Three months ended |
Year ended | ||||||||||
December 31, |
December 31, | ||||||||||
2014 |
2015 |
2014 |
2015 | ||||||||
Total operating revenues |
$ |
1,478,597 |
$ |
905,122 |
$ |
2,720,632 |
$ |
3,954,858 | |||
Commodity derivative fair value gains |
(931,921) |
(545,103) |
(868,201) |
(2,381,501) | |||||||
Gains on settled derivatives |
78,451 |
269,933 |
135,784 |
856,572 | |||||||
Gain on sale of assets |
(40,000) |
0 |
(40,000) |
0 | |||||||
Adjusted net revenues |
$ |
585,127 |
$ |
629,952 |
$ |
1,948,215 |
$ |
2,429,929 | |||
Adjusted net income from continuing operations attributable to common stockholders as set forth in this release represents net income (loss) from continuing operations attributable to common stockholders, adjusted for certain items. Antero believes that adjusted net income from continuing operations attributable to common stockholders is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Adjusted net income from continuing operations attributable to common stockholders is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) from continuing operations attributable to common stockholders as an indicator of financial performance. The following table reconciles net income (loss) from continuing operations attributable to common stockholders to adjusted net income from continuing operations attributable to common stockholders:
Three months ended |
Years ended | |||||||||||
December 31, |
December 31, | |||||||||||
2014 |
2015 |
2014 |
2015 | |||||||||
Net income from continuing operations attributable to common stockholders |
$ |
606,722 |
$ |
158,464 |
$ |
671,377 |
$ |
941,364 | ||||
Non-cash commodity derivative gains on unsettled derivatives |
(853,470) |
(275,170) |
(732,417) |
(1,524,929) | ||||||||
Impairment of unproved properties |
7,303 |
60,651 |
15,198 |
104,321 | ||||||||
Equity-based compensation expense |
26,356 |
18,597 |
112,252 |
97,877 | ||||||||
Loss on early extinguishment of debt |
— |
— |
20,386 |
— | ||||||||
Gain on sale of assets |
(40,000) |
— |
(40,000) |
— | ||||||||
Contract termination and rig stacking |
— |
27,629 |
— |
38,531 | ||||||||
Income tax effect of reconciling items |
330,670 |
63,938 |
267,642 |
495,215 | ||||||||
Adjusted net income from continuing operations attributable to common stockholders |
$ |
77,581 |
$ |
54,109 |
$ |
314,438 |
$ |
152,379 |
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital. Cash flow from operations before changes in working capital is widely accepted by the investment community as a financial indicator of an oil and gas company's ability to generate cash to internally fund exploration and development activities and to service debt. Cash flow from operations before changes in working capital is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry. In turn, many investors use this published research in making investment decisions. Cash flow from operations before changes in working capital is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.
The following table reconciles net cash provided by operating activities to cash flow from operations before changes in working capital as used in this release:
Three months ended |
Years ended | |||||||||||
2014 |
2015 |
2014 |
2015 | |||||||||
Net cash provided by operating activities |
$ |
199,375 |
$ |
169,781 |
$ |
998,121 |
$ |
1,006,381 | ||||
Net change in working capital |
78,348 |
68,842 |
(17,805) |
(30,067) | ||||||||
Cash flow from operations before changes in working capital |
$ |
277,723 |
$ |
238,623 |
$ |
980,316 |
$ |
976,314 |
The following table reconciles consolidated net debt to total debt as used in this release:
Years ended | ||||||
2014 |
2015 | |||||
Bank credit facilities |
$ |
1,730,000 |
$ |
1,327,000 | ||
6.00% senior notes due 2020 |
525,000 |
525,000 | ||||
5.375% senior notes due 2021 |
1,000,000 |
1,000,000 | ||||
5.125% senior notes due 2022 |
1,100,000 |
1,100,000 | ||||
5.625% senior notes due 2023 |
— |
750,000 | ||||
Net unamortized premium |
7,550 |
6,513 | ||||
Total debt |
$ |
4,362,550 |
$ |
4,708,513 | ||
Cash and cash equivalents |
245,979 |
23,473 | ||||
Consolidated net debt |
$ |
4,116,571 |
$ |
4,685,040 |
Adjusted EBITDAX is a non-GAAP financial measure that Antero defines as net income from continuing operations after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes Adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of the Company's net income from continuing operations to total Adjusted EBITDAX, a reconciliation of total Adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to Adjusted EBITDAX margin:
Three months ended December 31, |
Years ended December 31, | |||||||||||
(in thousands) |
2014 |
2015 |
2014 |
2015 | ||||||||
Net income from continuing operations including noncontrolling interest |
$ |
608,970 |
$ |
175,574 |
$ |
673,625 |
$ |
979,996 | ||||
Commodity derivative fair value gains |
(931,921) |
(545,103) |
(868,201) |
(2,381,501) | ||||||||
Gains on settled derivatives |
78,451 |
269,933 |
135,784 |
856,572 | ||||||||
Gain on sale of assets |
(40,000) |
— |
(40,000) |
— | ||||||||
Interest expense |
48,994 |
60,471 |
160,051 |
234,400 | ||||||||
Loss on early extinguishment of debt |
— |
— |
20,386 |
— | ||||||||
Income tax expense |
369,753 |
77,181 |
445,672 |
575,890 | ||||||||
Depletion, depreciation, amortization, and accretion |
157,252 |
162,178 |
479,167 |
711,418 | ||||||||
Impairment of unproved properties |
7,303 |
60,651 |
15,198 |
104,321 | ||||||||
Exploration expense |
6,717 |
760 |
27,893 |
3,846 | ||||||||
Equity-based compensation expense |
26,356 |
18,597 |
112,252 |
97,877 | ||||||||
State franchise taxes |
450 |
(59) |
2,188 |
72 | ||||||||
Contract termination and rig stacking |
— |
27,629 |
— |
38,531 | ||||||||
Consolidated Adjusted EBITDAX |
332,325 |
307,812 |
1,164,015 |
1,221,422 | ||||||||
Net income from discontinued operations |
2,210 |
— |
2,210 |
— | ||||||||
Gain on sale of assets |
(3,564) |
— |
(3,564) |
— | ||||||||
Income tax expense |
1,354 |
— |
1,354 |
— | ||||||||
Adjusted EBITDAX from discontinued operations |
— |
— |
— |
— | ||||||||
Total Adjusted EBITDAX |
332,325 |
307,812 |
1,164,015 |
1,221,422 | ||||||||
Interest expense |
(48,994) |
(60,471) |
(160,051) |
(234,400) | ||||||||
Exploration expense |
(6,717) |
(760) |
(27,893) |
(3,846) | ||||||||
Changes in current assets and liabilities |
(78,348) |
(68,842) |
17,805 |
30,067 | ||||||||
State franchise taxes |
(450) |
59 |
(2,188) |
(72) | ||||||||
Other noncash items |
1,559 |
(8,017) |
6,433 |
(6,790) | ||||||||
Net cash provided by operating activities |
$ |
199,375 |
$ |
169,781 |
$ |
998,121 |
$ |
1,006,381 |
Three months ended |
Years ended | |||||||||||
December 31, |
December 31, | |||||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
2014 |
2015 |
2014 |
2015 | ||||||||
Realized price before gains on settled derivatives |
$ |
4.00 |
$ |
2.32 |
$ |
4.73 |
$ |
2.52 | ||||
Gathering, compression, and water handling and treatment revenues |
0.09 |
0.05 |
0.06 |
0.04 | ||||||||
Lease operating expense |
(0.09) |
(0.08) |
(0.08) |
(0.07) | ||||||||
Gathering, compression, processing and transportation costs |
(1.25) |
(1.23) |
(1.26) |
(1.21) | ||||||||
Marketing, net |
(0.13) |
(0.38) |
(0.14) |
(0.23) | ||||||||
Production and ad valorem taxes |
(0.20) |
(0.15) |
(0.24) |
(0.14) | ||||||||
General and administrative(1) |
(0.24) |
(0.26) |
(0.28) |
(0.24) | ||||||||
Gains on settled derivatives |
0.68 |
1.96 |
0.37 |
1.57 | ||||||||
Adjusted EBITDAX margin ($ per Mcfe): |
$ |
2.86 |
$ |
2.23 |
$ |
3.16 |
$ |
2.24 | ||||
(1) – excludes equity-based stock compensation that is included in G&A |
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this press release is intended to constitute guidance with respect to Antero Midstream.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, Antero's ability to meet development and drilling plans, the Company's ability to implement its hedge strategy and results, risk regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas, NGL and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
For more information, contact Michael Kennedy – SVP – Finance at (303) 357-6782 or mkennedy@anteroresources.com.
ANTERO RESOURCES CORPORATION | |||||||
Consolidated Balance Sheets | |||||||
December 31, 2014 and 2015 | |||||||
(In thousands, except share amounts) | |||||||
2014 |
2015 |
||||||
Assets |
|||||||
Current assets: |
|||||||
Cash and cash equivalents |
$ |
245,979 |
23,473 |
||||
Accounts receivable, net of allowance for doubtful accounts of $1,251 in 2014 and $1,195 in 2015 |
116,203 |
79,404 |
|||||
Accrued revenue |
191,558 |
128,242 |
|||||
Derivative instruments |
692,554 |
1,009,030 |
|||||
Other current assets |
5,866 |
8,087 |
|||||
Total current assets |
1,252,160 |
1,248,236 |
|||||
Property and equipment: |
|||||||
Natural gas properties, at cost (successful efforts method): |
|||||||
Unproved properties |
2,060,936 |
1,996,081 |
|||||
Proved properties |
6,515,221 |
8,211,106 |
|||||
Water handling and treatment systems |
421,012 |
565,616 |
|||||
Gathering systems and facilities |
1,197,239 |
1,502,396 |
|||||
Other property and equipment |
37,687 |
46,415 |
|||||
10,232,095 |
12,321,614 |
||||||
Less accumulated depletion, depreciation, and amortization |
(879,643) |
(1,589,372) |
|||||
Property and equipment, net |
9,352,452 |
10,732,242 |
|||||
Derivative instruments |
899,997 |
2,108,450 |
|||||
Other assets |
68,886 |
66,296 |
|||||
Total assets |
$ |
11,573,495 |
14,155,224 |
||||
Liabilities and Equity |
|||||||
Current liabilities: |
|||||||
Accounts payable |
$ |
531,564 |
364,160 |
||||
Accrued liabilities |
168,614 |
194,076 |
|||||
Revenue distributions payable |
182,352 |
129,949 |
|||||
Other current liabilities |
12,202 |
19,085 |
|||||
Total current liabilities |
894,732 |
707,270 |
|||||
Long-term liabilities: |
|||||||
Long-term debt |
4,362,550 |
4,708,513 |
|||||
Deferred income tax liability |
794,796 |
1,370,686 |
|||||
Other liabilities |
47,587 |
82,077 |
|||||
Total liabilities |
6,099,665 |
6,868,546 |
|||||
Commitments and contingencies |
|||||||
Equity: |
|||||||
Stockholders' equity: |
|||||||
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued |
— |
— |
|||||
Common stock, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 262,071,642 shares and 277,035,558 shares, respectively |
2,621 |
2,770 |
|||||
Additional paid-in capital |
3,513,725 |
4,122,811 |
|||||
Accumulated earnings |
867,447 |
1,808,811 |
|||||
Total stockholders' equity |
4,383,793 |
5,934,392 |
|||||
Noncontrolling interest in consolidated subsidiary |
1,090,037 |
1,352,286 |
|||||
Total equity |
5,473,830 |
7,286,678 |
|||||
Total liabilities and equity |
$ |
11,573,495 |
14,155,224 |
ANTERO RESOURCES CORPORATION | ||||||||||
Consolidated Statements of Operations and Comprehensive Income (Loss) | ||||||||||
Years Ended December 31, 2013, 2014 and 2015 | ||||||||||
(In thousands, except share and per share amounts) | ||||||||||
2013 |
2014 |
2015 |
||||||||
Revenue: |
||||||||||
Natural gas sales |
$ |
689,198 |
1,301,349 |
1,039,892 |
||||||
Natural gas liquids sales |
111,663 |
328,323 |
264,483 |
|||||||
Oil sales |
20,584 |
107,080 |
70,753 |
|||||||
Gathering, compression, and water handling and treatment |
— |
22,075 |
22,000 |
|||||||
Marketing |
— |
53,604 |
176,229 |
|||||||
Commodity derivative fair value gains |
491,689 |
868,201 |
2,381,501 |
|||||||
Gain on sale of gathering system |
— |
40,000 |
— |
|||||||
Total revenue |
1,313,134 |
2,720,632 |
3,954,858 |
|||||||
Operating expenses: |
||||||||||
Lease operating |
9,439 |
29,341 |
36,011 |
|||||||
Gathering, compression, processing, and transportation |
218,428 |
461,413 |
659,361 |
|||||||
Production and ad valorem taxes |
50,481 |
87,918 |
78,325 |
|||||||
Marketing |
— |
103,435 |
299,062 |
|||||||
Exploration |
22,272 |
27,893 |
3,846 |
|||||||
Impairment of unproved properties |
10,928 |
15,198 |
104,321 |
|||||||
Depletion, depreciation, and amortization |
233,876 |
477,896 |
709,763 |
|||||||
Accretion of asset retirement obligations |
1,065 |
1,271 |
1,655 |
|||||||
General and administrative (including equity-based compensation expense of $365,280, $112,252, and $97,877 in 2013, 2014, and 2015, respectively) |
425,438 |
216,533 |
233,697 |
|||||||
Contract termination and rig stacking |
— |
— |
38,531 |
|||||||
Total operating expenses |
971,927 |
1,420,898 |
2,164,572 |
|||||||
Operating income |
341,207 |
1,299,734 |
1,790,286 |
|||||||
Other expenses: |
||||||||||
Interest |
(136,617) |
(160,051) |
(234,400) |
|||||||
Loss on early extinguishment of debt |
(42,567) |
(20,386) |
— |
|||||||
Total other expenses |
(179,184) |
(180,437) |
(234,400) |
|||||||
Income from continuing operations before income taxes and discontinued operations |
162,023 |
1,119,297 |
1,555,886 |
|||||||
Provision for income tax expense |
(186,210) |
(445,672) |
(575,890) |
|||||||
Income (loss) from continuing operations |
(24,187) |
673,625 |
979,996 |
|||||||
Discontinued operations: |
||||||||||
Income from sale of discontinued operations, net of income tax expense of $3,249 and $1,354 in 2013 and 2014, respectively |
5,257 |
2,210 |
— |
|||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest |
(18,930) |
675,835 |
979,996 |
|||||||
Net income and comprehensive income attributable to noncontrolling interest |
— |
2,248 |
38,632 |
|||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation |
$ |
(18,930) |
673,587 |
941,364 |
||||||
Earnings (loss) per common share: |
||||||||||
Continuing operations |
$ |
(0.09) |
2.56 |
3.43 |
||||||
Discontinued operations |
0.02 |
0.01 |
— |
|||||||
Total |
$ |
(0.07) |
2.57 |
3.43 |
||||||
Earnings (loss) per common share—assuming dilution: |
||||||||||
Continuing operations |
$ |
(0.09) |
2.56 |
3.43 |
||||||
Discontinued operations |
0.02 |
0.01 |
— |
|||||||
Total |
$ |
(0.07) |
2.57 |
3.43 |
||||||
Weighted average number of shares outstanding: |
||||||||||
Basic |
262,049,659 |
262,053,868 |
274,122,567 |
|||||||
Diluted |
262,049,659 |
262,068,106 |
274,143,341 |
ANTERO RESOURCES CORPORATION | ||||||||||
Consolidated Statements of Cash Flows | ||||||||||
Years ended December 31, 2013, 2014, and 2015 | ||||||||||
(In thousands) | ||||||||||
2013 |
2014 |
2015 |
||||||||
Cash flows from operating activities: |
||||||||||
Net income (loss) including noncontrolling interest |
$ |
(18,930) |
675,835 |
979,996 |
||||||
Adjustment to reconcile net income to net cash provided by operating activities: |
||||||||||
Depletion, depreciation, amortization, and accretion |
234,941 |
479,167 |
711,418 |
|||||||
Impairment of unproved properties |
10,928 |
15,198 |
104,321 |
|||||||
Derivative fair value gains |
(491,689) |
(868,201) |
(2,381,501) |
|||||||
Gains on settled derivatives |
163,570 |
135,784 |
856,572 |
|||||||
Deferred income tax expense |
190,210 |
445,672 |
575,890 |
|||||||
Gain on sale of assets |
— |
(40,000) |
— |
|||||||
Equity-based compensation expense |
365,280 |
112,252 |
97,877 |
|||||||
Loss on early extinguishment of debt |
42,567 |
20,386 |
— |
|||||||
Gain on sale of discontinued operations |
(8,506) |
(3,564) |
— |
|||||||
Deferred income tax expense—discontinued operations |
3,249 |
1,354 |
— |
|||||||
Other |
1,173 |
6,433 |
31,741 |
|||||||
Changes in current assets and liabilities: |
||||||||||
Accounts receivable |
(9,314) |
(45,593) |
(3,201) |
|||||||
Accrued revenue |
(50,156) |
(94,733) |
63,316 |
|||||||
Other current assets |
19,543 |
(2,891) |
(2,221) |
|||||||
Accounts payable |
1,039 |
(11,710) |
5,200 |
|||||||
Accrued liabilities |
26,803 |
85,953 |
13,210 |
|||||||
Revenue distributions payable |
50,552 |
85,763 |
(52,403) |
|||||||
Other current liabilities |
3,447 |
1,016 |
6,166 |
|||||||
Net cash provided by operating activities |
534,707 |
998,121 |
1,006,381 |
|||||||
Cash flows used in investing activities: |
||||||||||
Additions to proved properties |
(15,300) |
(64,066) |
— |
|||||||
Additions to unproved properties |
(440,825) |
(777,422) |
(198,694) |
|||||||
Drilling and completion costs |
(1,615,965) |
(2,477,150) |
(1,651,282) |
|||||||
Additions to water handling and treatment systems |
(203,790) |
(196,675) |
(131,051) |
|||||||
Additions to gathering systems and facilities |
(389,453) |
(558,037) |
(360,287) |
|||||||
Additions to other property and equipment |
(6,240) |
(13,218) |
(6,595) |
|||||||
Change in other assets |
(2,019) |
(3,082) |
9,750 |
|||||||
Proceeds from asset sales |
— |
— |
40,000 |
|||||||
Net cash used in investing activities |
(2,673,592) |
(4,089,650) |
(2,298,159) |
|||||||
Cash flows from financing activities: |
||||||||||
Issuance of common stock |
1,578,573 |
— |
537,832 |
|||||||
Issuance of common units in Antero Midstream Partners LP |
— |
1,087,224 |
240,703 |
|||||||
Issuance of senior notes |
1,231,750 |
1,102,500 |
750,000 |
|||||||
Repayment of senior notes |
(690,000) |
(260,000) |
— |
|||||||
Borrowings (repayments) on bank credit facilities, net |
71,000 |
1,442,000 |
(403,000) |
|||||||
Make-whole premium on debt extinguished |
(33,041) |
(17,383) |
— |
|||||||
Payments of deferred financing costs |
(20,899) |
(31,543) |
(17,293) |
|||||||
Distributions to noncontrolling interest in consolidated subsidiary |
— |
— |
(34,129) |
|||||||
Other |
— |
(2,777) |
(4,841) |
|||||||
Net cash provided by financing activities |
2,137,383 |
3,320,021 |
1,069,272 |
|||||||
Net increase (decrease) in cash and cash equivalents |
(1,502) |
228,492 |
(222,506) |
|||||||
Cash and cash equivalents, beginning of period |
18,989 |
17,487 |
245,979 |
|||||||
Cash and cash equivalents, end of period |
$ |
17,487 |
245,979 |
23,473 |
||||||
Supplemental disclosure of cash flow information: |
||||||||||
Cash paid during the period for interest |
$ |
117,832 |
163,055 |
219,945 |
||||||
Supplemental disclosure of noncash investing activities: |
||||||||||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment |
$ |
188,123 |
181,591 |
(169,783) |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended December 31, 2014 compared to the three months ended December 31, 2015:
Three months ended December 31, |
Amount of |
Percent |
||||||||||
(in thousands) |
2014 |
2015 |
(Decrease) |
Change |
||||||||
Operating revenues: |
||||||||||||
Natural gas sales |
$ |
364,472 |
$ |
228,910 |
$ |
(135,562) |
(37) |
% | ||||
NGLs sales |
83,516 |
76,080 |
(7,436) |
(9) |
% | |||||||
Oil sales |
18,021 |
15,126 |
(2,895) |
(16) |
% | |||||||
Gathering, compression, and water handling and treatment |
10,111 |
6,916 |
(3,195) |
(32) |
% | |||||||
Marketing |
30,556 |
32,987 |
2,431 |
8 |
% | |||||||
Commodity derivative fair value gains |
931,921 |
545,103 |
(386,818) |
(42) |
% | |||||||
Gain on sale of assets |
40,000 |
— |
(40,000) |
* |
||||||||
Total operating revenues |
1,478,597 |
905,122 |
(573,475) |
(39) |
% | |||||||
Operating expenses: |
||||||||||||
Lease operating |
10,771 |
10,450 |
(321) |
(3) |
% | |||||||
Gathering, compression, processing, and transportation |
145,535 |
168,728 |
23,193 |
16 |
% | |||||||
Production and ad valorem taxes |
23,795 |
20,867 |
(2,928) |
(12) |
% | |||||||
Marketing |
45,316 |
84,861 |
39,545 |
87 |
% | |||||||
Exploration |
6,717 |
760 |
(5,957) |
(89) |
% | |||||||
Impairment of unproved properties |
7,303 |
60,651 |
53,348 |
730 |
% | |||||||
Depletion, depreciation, and amortization |
156,912 |
161,750 |
4,838 |
3 |
% | |||||||
Accretion of asset retirement obligations |
340 |
428 |
88 |
26 |
% | |||||||
General and administrative (before equity-based compensation) |
27,835 |
37,175 |
9,340 |
34 |
% | |||||||
Equity-based compensation |
26,356 |
18,597 |
(7,759) |
(29) |
% | |||||||
Contract termination and rig stacking |
— |
27,629 |
27,629 |
* |
||||||||
Total operating expenses |
450,880 |
591,896 |
141,016 |
31 |
% | |||||||
Operating income |
1,027,717 |
313,226 |
(714,491) |
(70) |
% | |||||||
Other Expenses: |
||||||||||||
Interest expense |
(48,994) |
(60,471) |
(11,477) |
23 |
% | |||||||
Income from continuing operations before income taxes and discontinued operations |
978,723 |
252,755 |
(725,968) |
(74) |
% | |||||||
Income tax expense |
(369,753) |
(77,181) |
292,572 |
(79) |
% | |||||||
Net income and comprehensive income including noncontrolling interest |
608,970 |
175,574 |
(433,396) |
(71) |
% | |||||||
Net income and comprehensive income attributable to noncontrolling interest |
2,248 |
17,110 |
14,862 |
661 |
% | |||||||
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
606,722 |
$ |
158,464 |
$ |
(448,258) |
(74) |
% | ||||
Adjusted EBITDAX |
$ |
332,325 |
$ |
307,812 |
$ |
(24,513) |
(7) |
% | ||||
Production data: |
||||||||||||
Natural gas (Bcf) |
100 |
107 |
7 |
7 |
% | |||||||
NGLs (MBbl) |
2,500 |
4,509 |
2,009 |
80 |
% | |||||||
Oil (MBbl) |
301 |
529 |
228 |
76 |
% | |||||||
Combined (Bcfe) |
116 |
138 |
22 |
18 |
% | |||||||
Daily combined production (MMcfe/d) |
1,265 |
1,497 |
232 |
18 |
% | |||||||
Average prices before effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
3.66 |
$ |
2.13 |
$ |
(1.53) |
(42) |
% | ||||
NGLs (per Bbl) |
$ |
33.41 |
$ |
16.87 |
$ |
(16.54) |
(50) |
% | ||||
Oil (per Bbl) |
$ |
59.85 |
$ |
28.59 |
$ |
(31.26) |
(52) |
% | ||||
Combined (per Mcfe) |
$ |
4.00 |
$ |
2.32 |
$ |
(1.68) |
(42) |
% | ||||
Average realized prices after effects of derivative settlements: |
||||||||||||
Natural gas (per Mcf) |
$ |
4.39 |
$ |
4.40 |
$ |
0.01 |
— |
% | ||||
NGLs (per Bbl) |
$ |
33.41 |
$ |
21.15 |
$ |
(12.26) |
(37) |
% | ||||
Oil (per Bbl) |
$ |
78.24 |
$ |
40.85 |
$ |
(37.39) |
(48) |
% | ||||
Combined (per Mcfe) |
$ |
4.68 |
$ |
4.28 |
$ |
(0.40) |
(9) |
% | ||||
Average Costs (per Mcfe): |
||||||||||||
Lease operating |
$ |
0.09 |
$ |
0.08 |
$ |
(0.01) |
(11) |
% | ||||
Gathering, compression, processing, and transportation |
$ |
1.25 |
$ |
1.23 |
$ |
(0.02) |
(2) |
% | ||||
Production and ad valorem taxes |
$ |
0.20 |
$ |
0.15 |
$ |
(0.05) |
(25) |
% | ||||
Marketing, net |
$ |
0.13 |
$ |
0.38 |
$ |
0.25 |
192 |
% | ||||
Depletion, depreciation, amortization, and accretion |
$ |
1.35 |
$ |
1.18 |
$ |
(0.17) |
(13) |
% | ||||
General and administrative (before equity-based compensation) |
$ |
0.24 |
$ |
0.27 |
$ |
0.03 |
13 |
% |
* |
Not meaningful or applicable |
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the year ended December 31, 2014 compared to the year ended December 31, 2015:
Year ended December 31, |
Amount of |
Percent |
|||||||||||
(in thousands) |
2014 |
2015 |
(Decrease) |
Change |
|||||||||
Operating revenues: |
|||||||||||||
Natural gas sales |
$ |
1,301,349 |
$ |
1,039,892 |
$ |
(261,457) |
(20) |
% | |||||
NGLs sales |
328,323 |
264,483 |
(63,840) |
(19) |
% | ||||||||
Oil sales |
107,080 |
70,753 |
(36,327) |
(34) |
% | ||||||||
Gathering, compression, and water handling and treatment |
22,075 |
22,000 |
(75) |
— |
% | ||||||||
Marketing |
53,604 |
176,229 |
122,625 |
229 |
% | ||||||||
Commodity derivative fair value gains |
868,201 |
2,381,501 |
1,513,300 |
174 |
% | ||||||||
Gain on sale of gathering system |
40,000 |
— |
(40,000) |
* |
|||||||||
Total operating revenues |
2,720,632 |
3,954,858 |
1,234,226 |
45 |
% | ||||||||
Operating expenses: |
|||||||||||||
Lease operating |
29,341 |
36,011 |
6,670 |
23 |
% | ||||||||
Gathering, compression, processing, and transportation |
461,413 |
659,361 |
197,948 |
43 |
% | ||||||||
Production and ad valorem taxes |
87,918 |
78,325 |
(9,593) |
(11) |
% | ||||||||
Marketing |
103,435 |
299,062 |
195,627 |
189 |
% | ||||||||
Exploration |
27,893 |
3,846 |
(24,047) |
(86) |
% | ||||||||
Impairment of unproved properties |
15,198 |
104,321 |
89,123 |
586 |
% | ||||||||
Depletion, depreciation, and amortization |
477,896 |
709,763 |
231,867 |
49 |
% | ||||||||
Accretion of asset retirement obligations |
1,271 |
1,655 |
384 |
30 |
% | ||||||||
General and administrative (before equity-based compensation) |
104,281 |
135,820 |
31,539 |
30 |
% | ||||||||
Equity-based compensation |
112,252 |
97,877 |
(14,375) |
(13) |
% | ||||||||
Contract termination and rig stacking |
— |
38,531 |
38,531 |
* |
|||||||||
Total operating expenses |
1,420,898 |
2,164,572 |
743,674 |
52 |
% | ||||||||
Operating income |
1,299,734 |
1,790,286 |
490,552 |
38 |
% | ||||||||
Other Expenses: |
|||||||||||||
Interest expense |
(160,051) |
(234,400) |
(74,349) |
46 |
% | ||||||||
Loss on early extinguishment of debt |
(20,386) |
— |
20,386 |
* |
|||||||||
Total other expenses |
(180,437) |
(234,400) |
(53,963) |
30 |
% | ||||||||
Income from continuing operations before income taxes and discontinued operations |
1,119,297 |
1,555,886 |
436,589 |
39 |
% | ||||||||
Income tax expense |
(445,672) |
(575,890) |
(130,218) |
29 |
% | ||||||||
Income from continuing operations |
673,625 |
979,996 |
306,371 |
45 |
% | ||||||||
Income from discontinued operations |
2,210 |
— |
(2,210) |
* |
|||||||||
Net income and comprehensive income including noncontrolling interest |
675,835 |
979,996 |
304,161 |
45 |
% | ||||||||
Net income and comprehensive income attributable to noncontrolling interest |
2,248 |
38,632 |
36,384 |
1,619 |
% | ||||||||
Net income and comprehensive income attributable to Antero Resources Corporation |
$ |
673,587 |
$ |
941,364 |
$ |
267,777 |
40 |
% | |||||
Adjusted EBITDAX |
$ |
1,164,015 |
$ |
1,221,422 |
$ |
57,407 |
5 |
% | |||||
Production data: |
|||||||||||||
Natural gas (Bcf) |
317 |
439 |
122 |
39 |
% | ||||||||
NGLs (MBbl) |
7,102 |
15,550 |
8,448 |
119 |
% | ||||||||
Oil (MBbl) |
1,311 |
2,078 |
767 |
58 |
% | ||||||||
Combined (Bcfe) |
368 |
545 |
177 |
48 |
% | ||||||||
Daily combined production (MMcfe/d) |
1,007 |
1,493 |
486 |
48 |
% | ||||||||
Average prices before effects of derivative settlements: |
|||||||||||||
Natural gas (per Mcf) |
$ |
4.10 |
$ |
2.37 |
$ |
(1.73) |
(42) |
% | |||||
NGLs (per Bbl) |
$ |
46.23 |
$ |
17.01 |
$ |
(29.22) |
(63) |
% | |||||
Oil (per Bbl) |
$ |
81.65 |
$ |
34.05 |
$ |
(47.60) |
(58) |
% | |||||
Combined (per Mcfe) |
$ |
4.73 |
$ |
2.52 |
$ |
(2.21) |
(47) |
% | |||||
Average realized prices after effects of derivative settlements: |
|||||||||||||
Natural gas (per Mcf) |
$ |
4.52 |
$ |
4.15 |
$ |
(0.37) |
(8) |
% | |||||
NGLs (per Bbl) |
$ |
46.23 |
$ |
20.57 |
$ |
(25.66) |
(56) |
% | |||||
Oil (per Bbl) |
$ |
84.66 |
$ |
42.38 |
$ |
(42.28) |
(50) |
% | |||||
Combined (per Mcfe) |
$ |
5.10 |
$ |
4.10 |
$ |
(1.00) |
(20) |
% | |||||
Average Costs (per Mcfe): |
|||||||||||||
Lease operating |
$ |
0.08 |
$ |
0.07 |
$ |
(0.01) |
(13) |
% | |||||
Gathering, compression, processing, and transportation |
$ |
1.26 |
$ |
1.21 |
$ |
(0.05) |
(4) |
% | |||||
Production and ad valorem taxes |
$ |
0.24 |
$ |
0.14 |
$ |
(0.10) |
(42) |
% | |||||
Marketing, net |
$ |
0.14 |
$ |
0.23 |
$ |
0.09 |
64 |
% | |||||
Depletion, depreciation, amortization, and accretion |
$ |
1.30 |
$ |
1.31 |
$ |
0.01 |
1 |
% | |||||
General and administrative (before equity-based compensation) |
$ |
0.28 |
$ |
0.25 |
$ |
(0.03) |
(11) |
% | |||||
* |
Not meaningful or applicable |
Logo - http://photos.prnewswire.com/prnh/20131101/LA09101LOGO
SOURCE Antero Resources Corporation
DENVER, Feb. 17, 2016 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today announced its 2016 capital budget and guidance.
2016 Capital Budget and Guidance Highlights:
Commenting on the 2016 capital budget and guidance, Paul Rady, Antero's Chairman and CEO, said, "Given the current commodity price environment, we have reduced our capital program by 23% as compared to last year. Further, we have structured our 2016 development program to give us significant operational flexibility to react to significant changes in commodity prices, up or down, throughout the year. For example, we have the ability to reduce our current $1.3 billion development plan as six of our rig contracts expire over the course of the year. Conversely, to the extent commodity prices improve from current levels, we are well positioned to accelerate activity as a result of our sizable inventory of drilled but uncompleted wells. Lastly, we are in the unique position of having sold essentially all of our forecasted 2016 and 2017 production forward through hedging at attractive fixed prices. Combined with our peer leading firm transportation portfolio to favorable markets and large inventory of low cost reserves, we are well positioned to grow and prosper in one of the lowest commodity price cycles in decades."
Further commenting on the 2016 capital budget and guidance, Glen Warren, President and CFO, said, "We plan to continue delivering top-tier production growth, cash flow growth and margins in 2016, while continuing to target production growth of 20% for 2017. The ability to generate production growth of 15% in 2016 and target 20% in 2017, while reducing the 2016 budget by 23%, is a testament to the momentum we have established and efficiencies we have gained from having the largest and most active development program in Appalachia. We have built a highly sustainable business model with a large and growing production base, a market-leading firm transportation position, a significant long-term hedge position with a current mark-to-market value of $3.3 billion and $3.0 billion of liquidity under our credit facility. Driven by the incremental firm transport recently placed in service in the Marcellus, we are forecasting a premium to Nymex, before hedges, on our natural gas production in 2016 and beyond, based on current futures pricing. When we combine this forecasted uptick in pricing with the well cost reductions that we are continuing to achieve today and the 23% reduction in the 2016 capital budget, we project that we will reduce our outspend level by over 40% in 2016 versus last year."
2016 Capital Budget
Antero's initial capital budget for 2016 includes $1.3 billion for drilling and completion and $100 million for core leasehold acreage acquisitions and extensions. Antero's 2016 capital budget excludes Antero Midstream's (NYSE: AM) $435 million capital budget relating to low and high pressure gathering pipelines, compressor stations, fresh water pipelines and advanced wastewater treatment infrastructure. Antero Midstream announced its 2016 capital budget and guidance today in a separate news release, which can be found at www.anteromidstream.com.
The $1.3 billion drilling and completion budget represents a 21% reduction in drilling and completion capital as compared to 2015. The budget decrease is primarily driven by continuing capital efficiency improvements, a reduction in rig count and the deferral and carryover of a total of 70 Marcellus and Ohio Utica well completions into 2017. Twenty of the deferred completions are Marcellus wells located on Antero acreage in West Virginia that are dedicated to a third-party midstream provider that were carried over from 2015 and will now be carried over into 2017.
Approximately 75% of the drilling and completion budget for 2016 is allocated to the Marcellus Shale and the remaining 25% is allocated to the Ohio Utica Shale. Antero plans to operate an average of five drilling rigs in the Marcellus Shale in West Virginia and two drilling rigs in the Utica Shale in Ohio. In the Marcellus, Antero has budgeted the completion of 21 wells in its Highly-Rich Gas / Condensate regime and 59 wells in its Highly-Rich Gas regime, or a total of 80 wells. In the Ohio Utica, Antero has budgeted the completion of 11 wells in its Highly-Rich Gas regime and 19 wells in its Rich Gas regime, or a total of 30 wells. The relative shift in activity in 2016 from the Ohio Utica to the Marcellus is primarily driven by firm transportation constraints in the Ohio Utica, as the Company projects utilizing all of its 600,000 MMBtu/d of Rockies Express capacity during the year. Beyond Antero's Rockies Express capacity to Chicago, the Company's next available outlet would be Tetco M2, a current unfavorably priced index, until the Rover Pipeline project is completed. For this reason, Antero plans to shift some activity from the Ohio Utica to the Marcellus Shale in 2016. The Company will gain an additional 800,000 MMBtu/d of takeaway capacity from the Ohio Utica upon the completion of the Rover Pipeline, which is now anticipated to be placed into service in mid-2017. The Rover Pipeline will enable Antero to transport incremental Ohio Utica gas production in the second half of 2017 and beyond to the favorably priced Chicago and Gulf Coast markets.
Antero entered 2016 running 10 drilling rigs, but is forecasting a step down throughout the year to average a total of seven rigs for the year. As six drilling contracts expire over the course of the year, Antero has the flexibility to reduce its 2016 capital budget further should market conditions deteriorate.
During 2015 in the Marcellus, Antero averaged 24 drilling days per well with an average lateral length of 8,900 feet, representing a five day improvement compared to the 2014 development program. Additionally, Antero averaged four completion stages per day, an 8% increase over the 2014 completion program average. These operational improvements were driven by multiple enhancements, including increased mud pump circulation rates and improved plug drill out times, along with longer laterals drilled and shorter drilling days to total depth. Antero is currently drilling and completing wells at an average budgeted cost of $1.14 million per 1,000' of lateral in the Marcellus, representing a 16% improvement over 2014 well costs. These well costs include $1.2 million for roads, pads and wellhead equipment. Drilling and completion costs also include legacy drilling and completion contracts that expire in 2016 and 2017. Based on current spot market pricing for drilling rigs and completion crews, Antero projects that well costs will decline by over 11% by 2017.
During 2015 in the Ohio Utica, Antero averaged 30 drilling days per well with an average lateral length of 8,600 feet, representing a four day improvement compared to the 2014 development program. Additionally, Antero averaged four completion stages per day, a 17% increase over the 2014 completion program average. Antero is currently drilling and completing wells at an average budgeted cost of $1.29 million per 1,000' of lateral in the Utica, representing an 18% improvement over 2014 well costs. These well costs also include $1.2 million for roads, pads and wellhead equipment. Similar to the Marcellus, these estimated drilling and completion costs include legacy drilling and completion contracts that expire in 2016 and 2017. Based on current spot market pricing for drilling rigs and completion crews, Antero projects that well costs will decline by over 12% by 2017.
In 2016, Antero plans to continue consolidating acreage in the core of its Marcellus and Utica leasehold positions. However, given the current low commodity price environment, Antero has reduced its 2016 land budget to $100 million, a 38% reduction from 2015. Consistent with historical practices, the Company does not budget for acquisitions.
The following is a comparison of the 2016 capital budget to 2015 preliminary unaudited capital costs.
($ in MM) |
||||||||||
Capital Comparison |
2015 |
2016 |
% Change | |||||||
Drilling & Completion |
$1,650 |
$1,300 |
(21%) | |||||||
Land (1) |
160 |
100 |
(38%) | |||||||
Total Capital |
$1,810 |
$1,400 |
(23%) | |||||||
Average Operated Drilling Rigs |
14 |
7 |
(50%) | |||||||
Operated Wells Completed |
131 |
110 |
(16%) | |||||||
Deferred Completions |
50 |
70 |
40% | |||||||
(1) |
Preliminary unaudited 2015 capital costs exclude $39 million for acquisitions. |
The 2016 capital budget is expected to be fully funded through internally generated operating cash flow and available borrowing capacity within Antero's bank credit facility. As of September 30, 2015, Antero had $3.0 billion of available borrowing capacity under its existing bank revolver.
2016 Guidance
Antero's 2016 net daily production, including liquids, is forecast to grow approximately 15% to 1.715 Bcfe/d compared to 2015 average net production of 1.493 Bcfe/d. Net liquids production is forecast to increase 24% to an average of 60,000 Bbl/d in 2016, including 10,000 Bbl/d of ethane and 3,500 Bbl/d of condensate. In anticipation of the start-up of Mariner East II in 2017 and Antero's corresponding ethane sales agreement with Borealis upon the Mariner East II in-service date, MarkWest installed a de-ethanizer at the Sherwood Complex in Doddridge County, West Virginia. The de-ethanizer was commissioned in the fourth quarter of 2015 and Antero recovered approximately 10,000 Bbl/d of gross ethane for the month of December 2015. The Company projects recovery of approximately 10,000 Bbl/d of net ethane during 2016. Once Mariner East II is placed in-service, Antero projects recovering 11,500 Bbl/d of ethane to fulfill the Borealis contract at an expected premium to the Nymex natural gas-equivalent price.
Price Realizations
Antero projects the percentage of natural gas production sold at current favorably priced indices to increase significantly in 2016 with the recent completion of the Stonewall gathering pipeline and early termination of unfavorable firm sales contracts resulting in gas price realizations at a premium compared to Nymex. The Stonewall pipeline, which was placed in-service on November 30, 2015, allows Antero the flexibility to shift volumes from Dominion South and TETCO M2 pricing to the more favorable TCO and Gulf Coast markets. A portion of that volume shift was previously contracted as a 130 BBtu/d firm sales contract at Dominion South pricing. Antero elected in October 2015 to terminate this firm sale agreement with a buy-back cost of approximately $28 million. Based on current strip pricing, the expected incremental revenues over the next two years from terminating this contract and selling the volumes at a more favorably priced index is projected to substantially exceed the termination charge associated with this transaction, which was recorded as a one-time expense in Antero's fourth quarter 2015 results. This transition to favorable gas markets, including the impact from Stonewall and the firm sales buy-back, is projected to result in approximately $135 million in incremental EBITDAX for Antero's production volumes in 2016 based on current strip pricing. Antero now has the ability to transport and sell virtually all of its gas in 2016 to current favorably priced indices, including Nymex, TCO, Chicago and Gulf Coast pricing.
Based on expected improved pricing for butane and heavier NGL volumes, Antero is forecasting a C3+ NGL realized price of 35% to 40% of WTI oil prices in 2016 compared to a 35% of WTI realization in 2015. Additionally, Antero has hedged 100% of its forecasted propane production at $0.59 per gallon, $0.22 per gallon higher than current 2016 Mont Belvieu pricing of $0.37 per gallon. Furthermore, once Mariner East II is placed in-service, Antero will have the ability to market 61,500 Bbl/d of its ethane, propane and normal-butane volumes to international buyers at netback prices currently superior to local Appalachian netback prices, partly due to lower transport costs.
Assuming the execution of the $1.3 billion drilling and completion capital plan discussed above, the Company is using the following key assumptions in its projections for 2016:
Production |
||
Net Daily Production (MMcfe/d) |
1,715 | |
Net Daily Residue Natural Gas Production (MMcf/d) |
1,355 | |
Net Daily Liquids Production (Bbl/d) |
60,000 | |
Net Daily C3+ NGL Production (Bbl/d) |
46,500 | |
Net Daily Ethane Production (Bbl/d) |
10,000 | |
Net Daily Oil Production (Bbl/d) |
3,500 | |
Realized Pricing |
||
Natural Gas Realized Price Premium to Nymex Henry Hub Before Hedging ($/Mcf)(1)(2) |
$0.00 – $0.10 | |
Oil Realized Price Differential to Nymex WTI Oil Before Hedging ($/Bbl) |
$(10.00) – $(11.00) | |
C3+ NGL Realized Price Before Hedging (% of Nymex WTI) (1) |
35% – 40% | |
Ethane Realized Price (Differential to Mont Belvieu) ($/Bbl) |
$0.00 | |
Cash Expenses |
||
Cash Production Expense ($/Mcfe)(3) |
$1.50 – $1.60 | |
Marketing Expense, Net of Marketing Revenue ($/Mcfe) |
$0.15 – $0.20 | |
G&A Expense ($/Mcfe) |
$0.20 – $0.25 | |
(1) |
Based on strip pricing as of December 31, 2015 |
(2) |
Includes Btu upgrade as Antero's processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average |
(3) |
Includes lease operating expenses, gathering, compression, transportation expenses and production taxes |
Commodity Price Sensitivity
Including Antero's substantial hedge position, and based on commodity prices as of December 31, 2015, a $0.50/MMBtu change in the average Nymex Henry Hub prices, assuming regional basis prices maintain the current relationship to Nymex Henry Hub, results in no change to 2016 EBITDAX. For oil pricing, a $10.00/Bbl change to the average Nymex WTI price, assuming NGLs maintain the current price relationship to Nymex WTI, results in an estimated change to 2016 EBITDAX of $25 million.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this press release is intended to constitute guidance with respect to Antero Midstream.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, Antero's ability to meet development and drilling plans, the Company's ability to implement its hedge strategy and results, risk regarding the timing and amount of future production of natural gas, NGLs and oil, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, the ability to satisfy applicable minimum volume requirements, regulatory changes, the uncertainty inherent in estimating natural gas, NGL and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2014.
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SOURCE Antero Resources Corporation
DENVER, Feb. 17, 2016 /PRNewswire/ -- Antero Midstream Partners LP (NYSE: AM) ("Antero Midstream" or the "Partnership") today announced its 2016 capital budget and guidance.
2016 Capital Budget and Guidance Highlights:
2016 Capital Budget
During 2016, Antero Midstream plans to expand its existing Marcellus and Utica Shale gathering, compression, and fresh water delivery infrastructure to accommodate Antero Resources Corporation's (NYSE: AR) ("Antero Resources") development plans. Today in a separate news release, Antero Resources announced its 2016 drilling and completion capital budget of $1.3 billion which is forecast to generate production growth of 15%, and can be found at www.anteroresources.com. In the Marcellus, Antero Resources plans to operate an average of 5 drilling rigs and complete approximately 80 horizontal wells in 2016, all located on acreage dedicated to Antero Midstream. In the Utica, Antero Resources plans to operate an average of 2 drilling rigs and complete 35 horizontal wells in 2016, all located on acreage dedicated to Antero Midstream.
Antero Resources plans to execute a development program in 2016 supported by the following key attributes:
Commenting on the Antero Resources 2016 capital budget and development program, along with its impact on Antero Midstream operations, Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream, said, "Similar to Antero Resources' 2015 development plan, the 2016 capital budget and production guidance assumes the deferral of 50 completions in the Marcellus and Utica combined from the second and third quarter of 2016 into the first half of 2017, which provides Antero Resources with significant operational flexibility to react to changes in commodity prices throughout the year. Additionally, Antero Resources expects to complete all 30 previously deferred wells that are located on Antero Midstream dedicated acreage in 2016, and the remaining 20 wells located on third-party gathering and compression dedicated acreage in 2017, which will allow Antero Resources to target 20% production growth in 2017. The strong production growth profile, plus the fact that Antero Midstream will gather an incrementally larger proportion of Antero Resources' overall production, combine to drive even stronger growth in Antero Midstream's gas and water throughput volumes."
The Partnership has budgeted investment of $410 million and $25 million in expansion and maintenance capital, respectively, resulting in a total Antero Midstream capital budget of $435 million in 2016. This capital budget includes $90 million of expansion capital for gathering infrastructure, which is forecast to result in 9 miles and 22 miles of additional low pressure and high pressure gathering pipelines, respectively. The gathering and compression expansion capital also includes $150 million for the construction of five compressor stations in the Marcellus Shale and Utica Shale. Antero Midstream expects to place two of the stations in-service in 2016, which will add 240 MMcf/d of incremental compression capacity in the Marcellus Shale. Approximately 90% of the gathering and compression capital is planned to be invested in the Marcellus Shale and the remaining 10% invested in the Utica Shale. This mix is driven by Antero Resources' focus on Marcellus Shale drilling and completions in 2016 due to constraints on firm transportation to favorable markets in the Ohio Utica Shale. At year-end 2016, Antero Midstream expects to have over 170 miles and 134 miles of low pressure and high pressure gathering pipelines, respectively, and over 1 Bcf/d of compression capacity in-service in the Marcellus and Utica Shale plays combined.
In addition to gathering and compression capital expenditures, Antero Midstream has budgeted investment of $40 million for water infrastructure expansion capital to construct one fresh water storage impoundment as well as 11 miles and 19 miles of fresh water trunklines and surface pipelines, respectively. Approximately 75% of the water infrastructure budget will be allocated to the Marcellus Shale and the remaining 25% will be allocated to the Utica Shale, excluding capital invested for the ongoing construction of the advanced wastewater treatment facility, or "Antero Clearwater Facility."
The 2016 budget includes $130 million for the continued construction of the Antero Clearwater Facility, which is expected to be placed into service in late 2017. The 60,000 barrel per day facility, which is centrally located on Antero's footprint in the southwestern core of the Marcellus Shale, is forecast to generate attractive returns at full utilization.
Antero Midstream expects to fund all 2016 capital expenditures through internally generated operating cash flow and available borrowing capacity within Antero Midstream's existing $1.5 billion bank credit facility. As of September 30, 2015, Antero Midstream had over $1.0 billion of liquidity.
Below is a comparison of the 2016 capital budget to 2015 preliminary unaudited capital costs.
Year Ended December 31, |
||||||
Capital Comparison ($MM) |
2015(2) |
2016 |
% Change | |||
Gathering and Compression Infrastructure(1) |
$349 |
$240 |
(31)% | |||
Fresh Water Infrastructure |
6 |
40 |
567% | |||
Advanced Wastewater Treatment |
55 |
130 |
136% | |||
Maintenance Capital |
13 |
25 |
92% | |||
Total Capital |
$423 |
$435 |
3% | |||
1) Excludes $40 million adjustment for unpaid payables retained by Antero Resources for capital expenditures associated with assets contributed to Antero Midstream during the Partnership's IPO. |
2) 2015 fresh water infrastructure and advanced wastewater treatment represents only capital invested by Antero Midstream. |
2016 Guidance
Antero Midstream is forecasting adjusted EBITDA of $300 million to $325 million and Distributable Cash Flow ("DCF") of $250 million to $275 million for 2016. Additionally, Antero Midstream is forecasting aggregate distributions attributable to calendar year 2016 that are 28% to 30% higher than the aggregate 2015 distributions of $0.795 per unit, while maintaining an average DCF coverage ratio in excess of the Partnership's targeted ratio of 1.1x to 1.2x on an annual basis. Antero Midstream's 2016 guidance excludes any impact from potential third party volumes, potential third party acquisitions and the exercise of the option to acquire a 15% interest in the Stonewall gathering pipeline.
Full Year 2016 | ||||
Low |
High | |||
Adjusted EBITDA ($MMs) |
$300 |
— |
$325 | |
Distributable Cash Flow ($MMs) |
$250 |
— |
$275 | |
Year-Over-Year Distribution Growth |
28% |
— |
30% | |
DCF Coverage Ratio |
> 1.1x to 1.2x Target |
Commenting on the Antero Midstream 2016 capital budget and guidance, Michael Kennedy, Antero Midstream's CFO, said, "Looking ahead into 2016, we believe Antero Midstream will continue to benefit from Antero Resources' industry-leading production growth profile, which is focused on attractive rate of return locations on acreage dedicated to Antero Midstream. Further, much of Antero Resources' planned 2016 development is expected to occur in areas in which Antero Midstream has existing gathering and compression infrastructure, which allows Antero Midstream to forecast a reduction in gathering and compression capital expenditures by 31% year over year and only a slight increase in the 2016 total capital budget despite the inclusion of significant capital to be invested in water infrastructure and the construction of the Antero Clearwater Facility. We believe Antero Resources' sizable hedge position, which is forecast to cover 100% of 2016 guided natural gas production, 100% of 2016 guided propane production, and 100% of its 2017 targeted production, significantly de-risks the Antero Resources development plan and in turn Antero Midstream's cash flows."
Mr. Kennedy further added, "Antero Midstream's top tier distribution growth of 28% to 30% in 2016 keeps us on track to deliver our previously announced distribution growth target of 28% to 30% per year through 2017. While our strong volumetric growth and the contribution from our recently acquired water business are expected to generate DCF coverage in excess of our 1.1x to 1.2x target during 2016, we believe it is prudent to run at a higher DCF coverage ratio during challenging commodity price environments given our already industry-leading distribution growth. This retained cash flow, along with the ability to efficiently deploy "just-in-time" capital in attractive, fixed-fee organic growth opportunities, gives Antero Midstream the unique ability to maintain a strong financial profile with a clear visibility for funding projects in an uncertain commodity price environment."
Option on Stonewall Gathering Pipeline
As previously disclosed, Antero Midstream has the right to participate in up to a 15% non-operating equity interest in the 67-mile Stonewall gathering pipeline for which Antero Resources is an anchor shipper. The Stonewall gathering pipeline was placed into service on November 30, 2015 and Antero Resources has a firm commitment of 900 MMcf/d through the system, which provides access to the Gulf Coast on the Tennessee Pipeline as well as to the Mid-Atlantic area through a long-term firm sales agreement with WGL Midstream, a subsidiary of WGL Holdings, LLC. Antero Midstream's option expires on May 30, 2016. As of today, Antero Midstream has not elected to participate in this project. If Antero Midstream exercises this option, it expects the capital contribution from exercising its option to be approximately $45 million to $55 million, which is not included in the $435 million capital budget or financial guidance previously discussed.
Non-GAAP Disclosures
As used in this news release, adjusted EBITDA means net income plus interest expense, depreciation and amortization expense, income tax expense (if applicable), non-cash long-term compensation expense and other non-cash adjustments. As used in this news release, distributable cash flow means adjusted EBITDA less interest expense and ongoing maintenance capital expenditures. Distributable cash flow should not be viewed as indicative of the actual amount of cash that the Partnership has available for distributions from operating surplus or that the Partnership plans to distribute. Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of the Partnership's consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, use to assess:
The Partnership believes that adjusted EBITDA and distributable cash flow provide useful information to investors in assessing the Partnership's financial condition and results of operations. Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Additionally, because adjusted EBITDA and distributable cash flow may be defined differently by other companies in its industry, the Partnership's definition of adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
The partnership does not provide financial guidance for projected net income or changes in working capital, and, therefore, is unable to provide a reconciliation of its adjusted EBITDA and distributable cash flow projections to net income, operating income, or net cash flow provided by operating activities, the most comparable financial measures calculated in accordance with GAAP.
Antero Midstream Partners LP is a limited partnership that owns, operates and develops midstream gathering and compression assets located in West Virginia, Ohio and Pennsylvania, as well as integrated water assets that primarily service Antero Resources' properties located in West Virginia and Ohio.
This release includes "forward-looking statements" within the meaning of federal securities laws. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Partnership's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although the Partnership believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Nothing in this release is intended to constitute guidance with respect to Antero Resources.
The Partnership cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the gathering and compression and water handling business. These risks include, but are not limited to, Antero Resources' expected future growth, Antero Resources' ability to meet its drilling and development plan, commodity price volatility, ability to execute the Partnership's business strategy, competition and government regulations, actions taken by third-party producers, operators, processors and transporters, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors" in Antero Midstream's Annual Report on Form 10-K for the year ended December 31, 2014 and "Item 1A. Risk Factors" in Antero Midstream's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2015.
For more information, contact Michael Kennedy – CFO of Antero Midstream at (303) 357-6782 or mkennedy@anteroresources.com.
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SOURCE Antero Midstream Partners LP
DENVER, Jan. 27, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced reserves as of December 31, 2015.
Announcement Highlights:
Antero's proved reserves at December 31, 2015 were 13.2 Tcfe, a 4% increase compared to proved reserves at December 31, 2014. Proved, probable and possible ("3P") reserves at year-end 2015 totaled 37.1 Tcfe, which represents a 9% decrease compared to the previous year. Both proved and 3P reserves as of December 31, 2015 exclude 366 million barrels and 1,237 million barrels of ethane, respectively, that is expected remain in the natural gas stream until such time pricing supports full ethane recovery.
Antero replaced 425% of net production in 2015 after giving effect to performance and price revisions and excluding the reclassification of certain locations to the probable category. Finding and development cost for proved reserve additions was $0.80 per Mcfe, based on unaudited capital expenditures for 2015. This finding and development cost includes drilling and completion capital as well as costs incurred for well pads, roads, certain wellhead facilities, acquisitions, land additions and give effect to performance and price revisions. Drill bit only finding and development cost was $0.71 per Mcfe for 2015. The expected reserve life of the Company's proved reserves, based on 2015 production, is approximately 24 years.
Under the Securities and Exchange Commission ("SEC") reporting rules, proved undeveloped reserves are limited to reserves that are planned to be developed within five years of initial booking. The Company reclassified 2.3 Tcfe of proved undeveloped reserves to the probable category in 2015 to comply with the SEC five-year development rule. Antero's 7.4 Tcfe of proved undeveloped reserves will require an estimated $5.1 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.69 per Mcfe. The future development capital includes the assumption of legacy contract expirations over the next year and replacement with current market based contracts.
Proved Reserves
As of December 31, 2015, the Company's 13.2 Tcfe of proved reserves were comprised of 72% natural gas, 27% NGLs and 1% oil. The Marcellus Shale accounted for 86% of proved reserves and the Utica Shale accounted for 14%. For 2015, due to the success of Antero's drilling program targeting liquids-rich locations in the Marcellus and Utica Shale plays, the Company added 2.9 Tcfe of proved reserves through the drill bit. At year-end 2015, proved reserves included 1.1 Tcfe of ethane reserves in the Marcellus Shale as the first de-ethanizer was placed on line at the MarkWest Sherwood facility in December 2015 and Antero's first international ethane sales contract is expected to commence in 2017 upon the completion of Mariner East 2. The remaining Marcellus ethane reserves, as well as the Utica ethane reserves, continue to be carried as natural gas reserves as it is assumed that these ethane reserves will be sold on an energy equivalent basis in the natural gas stream. These additions were partially offset by the reclassification of 2.3 Tcfe of proved reserves to the probable category in order to comply with the SEC five-year development rule and 560 Bcfe of negative revisions primarily related to the effect of lower natural gas and oil prices. The majority of the locations associated with the 2.3 Tcfe of reserves reclassified to the probable category are located on the eastern portion of Antero's Marcellus acreage that is currently dedicated to a third-party midstream provider. These primarily dry gas locations have a higher operating cost structure and do not receive liquids-related pricing. As a result, these locations are no longer expected to be drilled within the next five years under the Company's development plans, assuming SEC pricing.
Approximately 30% of Antero's combined 569,000 net acre leasehold position was classified as proved at December 31, 2015. Based on Antero's successful drilling results to date, as well as those of other operators in the vicinity of Antero's leasehold, the Company believes that a substantial portion of its Marcellus and Utica Shale acreage will be added to proved reserves over time as more wells are drilled. No West Virginia or Pennsylvania Utica dry gas locations were classified as 3P reserves at year-end 2015, with the exception of one proved developed producing location, due to the early stage of drilling and production in the play.
Proved developed reserves increased by 54% from year-end 2014 to 5.8 Tcfe at December 31, 2015. The Company added 69 Marcellus and 62 Utica wells to proved developed reserves in 2015. The percentage of proved reserves classified as proved developed increased to 44% at December 31, 2015 as compared to 30% at year-end 2014. Proved undeveloped reserves decreased by 17% primarily as a result of the reclassification of locations to the probable category due to the application of the SEC five-year development rule in a lower commodity price and reduced activity environment.
Antero's estimate of capital costs incurred during 2015, including drilling and completion costs of $1.65 billion and leasehold costs of $199 million, was approximately $1.85 billion. The leasehold costs included $39 million for acquisitions and $160 million for land. Assuming the approximate $1.85 billion estimate of capital costs, preliminary 2015 all-in finding and development cost for proved reserve additions from all sources, including performance and price revisions, was $0.80 per Mcfe. Antero's three-year all-in finding and development cost for proved reserve additions from all sources, including price and performance revisions, through 2015 was $0.57 per Mcfe. The 2015 capital costs are unaudited and preliminary. Final capital costs will be provided in Antero's Annual Report on Form 10-K for the year ended December 31, 2015.
Summary of Changes in Proved Reserves (in Bcfe) | |
Balance at December 31, 2014 |
12,683 |
Extensions, discoveries and additions |
2,878 |
Purchases of proved reserves |
– |
Performance and price revisions |
(560) |
Partial ethane recovery |
1,091 |
Reclassification to probable due to SEC 5-year development rule |
(2,332) |
Sales of proved reserves |
– |
Production |
(545) |
Balance at December 31, 2015 |
13,215 |
2015 Year-End |
|||||||
Assumed Appalachian Index Weighted Average Pricing: |
SEC Pricing |
Strip Pricing(1) |
Variance |
% Variance | |||
WTI Oil Price ($/Bbl) |
$50.13 |
$53.66 |
$3.53 |
7% | |||
Natural Gas Price ($/MMbtu) |
$2.56 |
$3.23 |
$0.67 |
26% | |||
C3+ Natural Gas Liquids ($/Bbl)(2) |
$23.09 |
$26.12 |
$3.03 |
13% | |||
PV-10 Values ($ Billion): |
|||||||
Proved Reserves PV-10 |
$3.6 |
$5.7 |
$2.1 |
58% | |||
Hedge PV-10(3) |
3.1 |
2.5 |
(0.6) |
(19)% | |||
Total PV-10 |
$6.7 |
$8.2 |
$1.5 |
22% |
1) |
Strip pricing as of December 31, 2015 for each of the first ten years and flat thereafter. NGL pricing assumes 39%, 46% and 48% of WTI strip prices for 2016, 2017 and 2018 and thereafter, respectively. |
2) |
Represents realized NGL price including regional market differentials. NGL price, including regional differential and transportation & fractionation charges, for SEC and Strip pricing was $18.43 per barrel and $21.46 per barrel, respectively. |
3) |
Hedge PV-10 at strip pricing differs from year-end 2015 mark-to-market value of $3.1 billion due to the application of a higher discount rate. |
SEC prices for reserves, calculated as of December 31, 2015 on a weighted average Appalachian index basis related to company-specific sales points, were $40.06 per barrel for oil and $2.56 per MMBtu for natural gas. Assuming SEC prices, which are not indicative of current forward prices, the pre-tax present value discounted at 10% ("pre-tax PV–10") of the December 31, 2015 proved reserves was $3.6 billion, a 68% decrease from year-end 2014. Including Antero's hedges as of December 31, 2015 assuming SEC prices, the pre-tax PV–10 value of proved reserves was $6.7 billion, a 42% decrease from year-end 2014.
Assuming future strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing as of December 31, 2015, the pre-tax PV–10 value of the same year-end 2015 proved reserves was $5.7 billion which represents a 56% increase over the corresponding SEC reserve based pre-tax PV–10, before hedges. Including Antero's hedges, the pre-tax PV–10 value of proved reserves was $8.2 billion assuming strip pricing.
Proved, Probable and Possible Reserves
Antero estimates that it had year-end 2015 3P reserves of 37.1 Tcfe, a 9% decrease from year-end 2014. The 9% decrease in 3P reserves was primarily driven by the removal of 4.6 Tcfe of probable and possible reserves in the Upper Devonian Shale due to lower commodity prices. The 3P reserves contain 29.7 Tcf of natural gas, 1,145 million barrels of NGLs, and 92 million barrels of oil. The Marcellus and Utica Shale comprised 29.6 Tcfe and 7.5 Tcfe of the 3P reserves, respectively. During 2015, Antero added 27,000 net acres in the Marcellus Shale in northern West Virginia while its Utica Shale position in southern Ohio was reduced by 1,000 net acres.
Importantly, 28.4 Tcfe of Antero's 29.6 Tcfe of 3P reserves in the Marcellus, or 96%, were classified as proved and probable reserves ("2P"), reflecting the low risk and statistically repeatable nature of Antero's Marcellus drilling. Further, 84%, or 6.3 Tcfe of Antero's 7.5 Tcfe of 3P reserves in the Utica, were classified as 2P.
The table below summarizes Antero's estimated 3P reserve volumes as of December 31, 2015 using SEC pricing, categorized by operating area:
Marcellus Shale |
Ohio Utica Shale |
||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations | ||||
Proved |
8,073 |
555 |
11,406 |
992 |
1,459 |
58 |
1,809 |
214 | |||
Probable |
14,216 |
458 |
16,961 |
2,185 |
3,972 |
83 |
4,468 |
564 | |||
Possible |
1,025 |
43 |
1,282 |
176 |
951 |
40 |
1,191 |
162 | |||
Total 3P |
23,314 |
1,056 |
29,649 |
3,353 |
6,381 |
181 |
7,468 |
940 | |||
% Liquids(1) |
21% |
15% |
|||||||||
Combined Reserves |
|||||||||||
Gas (Bcf) |
Liquids (MMBbl) |
Total (Bcfe) |
Gross Locations |
||||||||
Proved |
9,532 |
614 |
13,215 |
1,206 |
|||||||
Probable |
18,188 |
540 |
21,430 |
2,749 |
|||||||
Possible |
1,976 |
83 |
2,472 |
338 |
|||||||
Total 3P |
29,696 |
1,237 |
37,117 |
4,293 |
|||||||
% Liquids(1) |
20% |
(1) |
Represents liquids volumes as a percentage of total volumes. Combined liquids comprised of 1,145 million barrels of NGLs and 92 million barrels of oil. | ||||||||||
Assuming SEC prices, the pre-tax PV–10 of the December 31, 2015 3P reserves was $3.7 billion before hedges and $6.8 billion including hedges. Assuming year-end strip pricing, with adjustments similar to SEC pricing, the pre-tax PV–10 of the same year-end 2015 3P reserves was $11.2 billion which represents a 198% increase over the corresponding SEC reserve based pre-tax PV–10, before hedges. Including Antero's hedges, the pre-tax PV–10 of 3P reserves was $13.7 billion assuming strip pricing which represents a 101% increase over the corresponding SEC reserve based pre-tax PV–10.
Antero's proved and 3P reserves at December 31, 2015 were prepared by its internal reserve engineers and audited by DeGolyer and MacNaughton ("D&M"). D&M's reserve audit covered properties representing 100% of Antero's total 3P reserves at December 31, 2015.
Non-GAAP Disclosure
Year-end pre-tax PV–10 value is a non-GAAP financial measure as defined by the SEC. We believe that the presentation of pre-tax PV–10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors use pre-tax PV–10 value as a basis for comparison of the relative size and value of our reserves as compared with other companies. We believe that PV–10 estimates using strip pricing can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV–10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV–10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV–10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). We are not yet able to provide a reconciliation of pre-tax PV–10 to Standardized Measure because the discounted future income taxes associated with our reserves is not yet calculable. We expect to include a full reconciliation of pre-tax PV–10 to Standardized Measure in our Annual Report on Form 10-K for the year ended December 31, 2015.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
Cautionary Statements
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, other than historical facts included in this release, are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2014.
The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC. Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release. Antero's estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
This release provides a summary of Antero's reserves as of December 31, 2015, assuming partial ethane "rejection" where sales demand for ethane is not available. Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher. Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs. When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product. In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.
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SOURCE Antero Resources
DENVER, Jan. 13, 2016 /PRNewswire/ -- Antero Resources (NYSE: AR) ("Antero" or the "Company") today announced its fourth quarter 2015 operations update.
Fourth Quarter 2015 Highlights include:
Operating Update
All operational information is as of the date of this release unless otherwise noted.
Antero's net daily production for the fourth quarter of 2015 averaged 1,497 MMcfe/d, including 1,168 MMcf/d (78%) of natural gas, 49,006 Bbl/d (20%) of natural gas liquids ("NGLs"), including 2,179 Bbl/d of ethane, and 5,751 Bbl/d (2%) of oil. In anticipation of the start-up of Mariner East II and Antero's corresponding ethane sales agreement with Borealis upon the Mariner East II in-service date, MarkWest installed a de-ethanizer at the Sherwood Complex in Doddridge County, West Virginia. The de-ethanizer was commissioned in the fourth quarter of 2015 and Antero recovered approximately 10,000 Bbl/d of gross ethane for the month of December 2015. The Company plans to continue to recover approximately 10,000 Bbl/d of ethane during 2016. Once Mariner East II is placed in service, Antero intends to recover 11,500 Bbl/d of ethane to fulfill the Borealis contract at an expected premium price to Nymex natural gas.
Fourth quarter 2015 production represents an organic production growth rate of 18% from the fourth quarter of 2014 and a 1% decrease compared to the third quarter of 2015. The sequential decrease in production is primarily due to the periodic shut-in of production, averaging 45 MMcfe/d in the fourth quarter, as a result of Antero's decision not to sell gas at depressed pricing at the Dominion South and TETCO M2 indices. Liquids production for the fourth quarter of 2015 represents an organic production growth rate of 80% from the fourth quarter of 2014 and a 5% increase sequentially.
Antero's net daily production for 2015 averaged 1,493 MMcfe/d, an increase of 48% from the prior year and 7% higher than 2015 full year guidance of 1,400 MMcfe/d. Net production was comprised of 1,203 MMcf/d of natural gas (81%), 42,604 Bbl/d of NGLs (17%), including 549 Bbl/d of ethane, and 5,694 Bbl/d of crude oil (2%). The 2015 net liquids production of 48,298 Bbl/d is an increase of 110% over the prior year.
Commenting on the fourth quarter and full year 2015, Paul Rady, Chairman of the Board and CEO, said, "We had an outstanding quarter and year operationally. While we shut in an average of 45 MMcfe/d of production during the fourth quarter due to weak local pricing, our year-over-year production increased 48% and our liquids production increased 110% from 2014 levels. We also completed our first Utica well in West Virginia with encouraging initial production results that are consistent with other industry wells in the trend. This well is the most southerly Utica well drilled by industry in West Virginia to date, and begins to delineate our 188,000 net acres of Utica leasehold rights underlying our Marcellus position."
Antero's average realized natural gas price before settled derivatives for the fourth quarter of 2015 was $2.13 per Mcf, a $0.14 per Mcf negative differential to the average Nymex price for the period. This differential represents an improvement from the $0.45 per Mcf negative differential to Nymex realized in the third quarter of 2015. This improvement was driven by the opening of the third-party Stonewall gathering pipeline which was placed in service on December 1, 2015. Approximately 83% of Antero's fourth quarter 2015 natural gas production was sold at favorable price indices including TCO, Chicago, Gulf Coast, and Nymex, including virtually all volumes sold during the month of December, up from 68% in the third quarter. Antero's average realized natural gas price after settled derivatives for the fourth quarter of 2015 was $4.40 per Mcf, a $2.13 per Mcf positive differential to the average Nymex price for the period. For the fourth quarter of 2015, Antero realized a cash settled natural gas derivative gain of $244 million, or $2.27 per Mcf. This settled natural gas derivative gain included $117 million associated with Nymex derivatives, $94 million associated with derivatives at the Dominion South index, $26 million associated with derivatives at the TCO index and $7 million associated with derivatives at the Columbia Gulf Louisiana Onshore ("CGTLA") index.
With the completion of the previously mentioned Stonewall gathering pipeline in early December, Antero was able to shift approximately 350 MMcf/d of net natural gas sales from Dominion South and TETCO M2 pricing to the more favorable TCO market, resulting in incremental revenue of $7 million in December. Antero expects to sell approximately 95% of its 2016 gas production into currently favorably priced indices, including TCO, Chicago, Gulf Coast and Nymex.
Antero's average realized C3+ NGL price before settled derivatives for the fourth quarter of 2015 was $17.37 per barrel, or approximately 41% of the average WTI oil price for the period. This increase was primarily the result of increased seasonal demand in the northeast. The Company's average realized NGL price after settled derivatives for the quarter was $21.65 per barrel, or 52% of the average WTI oil price for the period. For the fourth quarter of 2015, Antero realized a settled NGL derivative gain of $19 million, or $4.28 per barrel. Antero settled 23,000 barrels per day of propane commodity derivatives in the fourth quarter of 2015 at $0.64 per gallon and has 30,000 barrels per day of propane commodity derivatives for 2016 at a fixed price of $0.59 per gallon. Antero's average realized ethane price (C2) for the fourth quarter of 2015 was $6.17 per barrel, or $0.15 per gallon. The fourth quarter of 2015 represented the first period in which Antero recovered ethane at the Sherwood processing plant in West Virginia.
Antero's average realized oil price before hedging for the fourth quarter of 2015 was $28.59 per barrel, a $13.34 per barrel negative differential to the average WTI oil price. The Company's average realized oil price after hedging for the quarter was $40.85 per barrel, a $1.08 per barrel negative differential to the average WTI oil price. For the fourth quarter of 2015, Antero realized a settled oil derivative gain of $7 million, or $12.26 per barrel.
The average all-in natural gas equivalent price including NGLs, oil and settled derivatives, was $4.28 per Mcfe for the fourth quarter of 2015, a 9% decrease from the fourth quarter of 2014.
Commenting on product pricing, Glen Warren, President and Chief Financial Officer, said, "There were some very significant developments for us during the quarter related to the marketing and pricing of our gas and NGLs. On the natural gas front, the Stonewall gathering pipeline was placed in service in early December, allowing us to shift 350 MMcf/d of net natural gas sales from currently unfavorable TETCO M2 and Dominion South pricing to favorable TCO pricing. On the NGL front, we saw a healthy uptick in NGL pricing related to increased seasonal demand and began recovering ethane during the quarter in preparation for the expected kickoff of our export agreement with Borealis in 2017. We expect improved basis differentials to persist through 2016, as we forecast that we will sell 95% of our natural gas production at favorably priced indices, resulting in an expected premium to Nymex pricing for the year."
The following table details the components of average net production and average realized prices for the three months ended December 31, 2015:
Three Months Ended December 31, 2015 | |||||||||||||||
Gas |
Oil |
NGL (C3+) |
Ethane (C2) |
Combined | |||||||||||
Average Net Production |
1,168 |
5,751 |
46,827 |
2,179 |
1,497 | ||||||||||
Average Realized Prices |
Gas |
Oil |
NGL (C3+) |
Ethane (C2) |
Combined | ||||||||||
Average realized price before settled derivatives |
$ |
2.13 |
$ |
28.59 |
$ |
17.37 |
$ |
6.17 |
$ |
2.32 | |||||
Settled derivatives |
2.27 |
12.26 |
4.28 |
– |
1.96 | ||||||||||
Average realized price after settled derivatives |
$ |
4.40 |
$ |
40.85 |
$ |
21.65 |
$ |
6.17 |
$ |
4.28 | |||||
Nymex average price |
$ |
2.27 |
$ |
41.93 |
$ |
2.27 | |||||||||
Premium / (Differential) to Nymex |
$ |
2.13 |
$ |
(1.08) |
$ |
2.01 | |||||||||
Marcellus Shale — Antero completed and placed on line 14 horizontal Marcellus wells during the fourth quarter of 2015. The average lateral length for the 14 wells was approximately 7,777 feet and the average stage length was approximately 202 feet. During the quarter, Antero drilled and cased the longest lateral in Company history, the Nova Unit 2H, which had a lateral length of 14,024 feet.
Ten of the 14 wells completed in the fourth quarter of 2015 have been on line for more than 30 days and had an average 30-day rate of 14.9 MMcfe/d while rejecting ethane (26% liquids). Antero is currently operating seven drilling rigs and four completion crews in the Marcellus Shale play.
Utica Shale — Antero completed and placed on line 16 horizontal Utica wells during the fourth quarter of 2015. The average lateral length for the 16 wells was approximately 8,883 feet and the average stage length was approximately 178 feet. All 16 wells were placed on a flowback management program, of which 10 wells have been on line for more than 30 days and had an average restricted 30-day rate of 15.4 MMcfe/d while rejecting ethane (15% liquids). These 10 wells had an average flowing casing pressure of 3,675 psi per well for the 30 days. Antero is currently operating three drilling rigs and three completion crews in the Utica Shale play.
West Virginia Utica Update
During the quarter, Antero completed the Rymer 4HD, its first Utica well in Tyler County, West Virginia with a lateral length of 6,620 feet. The well has been flowing into the sales line for 20 days with an average choke-restricted flow rate of 20 MMcf/d. This well represents the southernmost well drilled to date in the West Virginia dry Utica play. While results are early stage and several more months of flow testing are required, this well assists in the evaluation of Antero's 188,000 net Utica acres underlying its Marcellus acreage position in West Virginia and Pennsylvania.
Commodity Derivatives Position
During the quarter, Antero added 413 Bcf of fixed price natural gas swaps and 12 MMBbl of fixed price propane swaps from 2017 to 2022. As of December 31, 2015, Antero had commodity derivatives for 3.5 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from January 1, 2016 through December 31, 2022 at an average index price of $3.79 per Mcfe and mark-to-market hedge value of $3.1 billion.
The following table summarizes Antero's commodity derivatives position held as of December 31, 2015:
Period and Index |
Natural Gas |
Average |
Liquids |
Average | ||
2016: |
||||||
TCO |
60,000 |
$4.91 |
— |
— | ||
Nymex Henry Hub |
1,110,000 |
$3.49 |
— |
— | ||
Dom South |
272,500 |
$5.35 |
— |
— | ||
CGTLA |
170,000 |
$4.09 |
— |
— | ||
Propane MB ($/Gallon) |
— |
— |
30,000 |
$0.59 | ||
2016 Total |
1,612,500 |
$3.92 |
30,000 |
$0.59 | ||
Period |
Natural Gas |
Average |
Liquids |
Average | ||
2017 |
1,860,000 |
$3.63 |
35,500 |
$0.43 | ||
2018 |
2,002,500 |
$3.91 |
2,000 |
$0.65 | ||
2019 |
1,960,000 |
$3.87 |
— |
— | ||
2020 |
1,287,500 |
$3.72 |
— |
— | ||
2021 |
480,000 |
$3.48 |
— |
— | ||
2022 |
10,000 |
$3.30 |
Fourth Quarter and Full Year 2015 Earnings Release and Call
Antero plans to issue its fourth quarter 2015 earnings release on Wednesday, February 24, 2016 after the close of trading on the New York Stock Exchange.
A conference call is scheduled on Thursday, February 25, 2016 at 9:00 am MT to discuss the results. A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter. To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources." A telephone replay of the call will be available until Friday, March 4, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10078393.
A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com. The webcast will be archived for replay on the Company's website until Friday, March 4, 2016 at 9:00 am MT.
Presentation
An updated presentation has been posted to the Company's website to reflect and support information contained in this release. The presentation can be found at www.anteroresources.com on the homepage. Information on the Company's website does not constitute a portion of this press release.
Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. The Company's website is located at www.anteroresources.com.
This release includes "forward-looking statements". Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero's control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, future financial position, future technical improvements and future marketing opportunities are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero's Annual Report on Form 10-K for the year ended December 31, 2014.
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SOURCE Antero Resources
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