Project: Permian North Project
Firm Commitment: 0
COST: 25 $MM
COST: 2.5 $B
VOLUMES: 29.6 MBOE/d
ACRES: 1624000 Acres
HOUSTON, Jan. 12, 2021 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss fourth quarter and full year 2020 results on Friday, February 26, 2021, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-fourth-quarter-and-full-year-2020-results-for-february-26-2021-301206917.html
SOURCE EOG Resources, Inc.
HOUSTON, Dec. 17, 2020 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (EOG) has declared a dividend of $0.375 per share on EOG's Common Stock, payable January 29, 2021, to stockholders of record as of January 15, 2021. The indicated annual rate is $1.50.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-301195524.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 5, 2020 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported a third quarter 2020 net loss of $42 million, or $0.07 per share, compared with third quarter 2019 net income of $615 million, or $1.06 per share.
Adjusted non-GAAP net income for the third quarter 2020 was $252 million, or $0.43 per share, compared with adjusted non-GAAP net income of $654 million, or $1.13 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Third Quarter 2020 Review
EOG continued to respond aggressively to adverse market conditions by sharply lowering operating and capital costs as well as deferring production volumes to future periods. Reductions to operating costs were offset by lower commodity prices and production volumes, resulting in lower earnings in the third quarter 2020 compared with the same prior year period. Realized crude oil prices were $40.15 per barrel in the third quarter, down 29 percent from the same prior year period, while natural gas prices declined 21 percent, to $1.68 per thousand cubic feet. These declines were partially offset by an increase in natural gas liquids prices in the third quarter to $14.34 per barrel, up 13 percent compared with the same prior year period.
Compared with the third quarter 2019, total company crude oil volumes were 19 percent lower, at 377,600 barrels of oil per day (Bopd). Natural gas liquids production was one percent lower and natural gas volumes were 13 percent lower, contributing to 14 percent lower total company daily production. EOG continued to return shut-in wells to production during the third quarter, and nearly all shut-in wells were back on production by the end of September. On average, 28,000 Bopd was shut-in during the third quarter. EOG also began initial production from approximately 100 net new wells in the third quarter, after deferring such activity earlier in the year in response to lower oil prices.
Lease and well costs declined 24 percent on a per-unit basis compared with the same prior year period, driving an overall reduction in per-unit operating costs. Most of the lease and well cost savings were based on sustainable efficiency improvements in well-site maintenance, equipment repair, managing offset completions and other production operations.
Net cash provided by operating activities was $1.2 billion. Excluding changes in working capital and certain other items, EOG generated $1.3 billion of discretionary cash flow. The company incurred total expenditures of $646 million, including $499 million of capital expenditures before acquisitions, non–cash transactions and asset retirement costs, resulting in $762 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"Our operational execution continues to be excellent," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "I'm grateful to all EOG employees during these unusual times. We continue to exceed expectations by optimizing production volumes and reducing costs while maintaining our strong safety and environmental performance.
"Notably, we are not playing defense in the current challenging environment. In fact, the opposite is true: we are aggressively moving EOG forward, advancing new plays, identifying innovative solutions to lower costs and improve well productivity, sharpening our technological edge and further demonstrating our commitment to sustainability. All of this is driven from the bottom up by a decentralized organization and a unique culture. This year more than ever, we are focused on investing in our people and enhancing our culture to sustain our competitive advantage and enable EOG to play an increasingly vital role in meeting the long-term global energy needs."
New South Texas Natural Gas Play and Premium Inventory Update
EOG has made a large natural gas resource play discovery on its Dorado prospect located in Webb County, Texas. A total of 21 trillion cubic feet (Tcf) of estimated net resource potential is contained in 700 feet of stacked pay in the Austin Chalk and Eagle Ford Shale formations. The company has identified an initial 1,250 net premium drilling locations across its 163,000 net acre position in the core of the play. EOG has drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford.
The Austin Chalk formation has an estimated net resource potential of 9.5 Tcf of natural gas. EOG has identified 530 net premium drilling locations in the Austin Chalk. The prolific Austin Chalk wells generate rates of return that are competitive with EOG's large inventory of premium oil plays. The rates of return are supported by low cash operating costs and proximity to several natural gas markets with options for LNG and pipeline export pricing. In addition, EOG plans to apply its latest water and emissions management technology to minimize the environmental footprint of its development activities.
The five initial Austin Chalk wells produced an average of 3.5 billion cubic feet (Bcf) of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. EOG expects to complete approximately 15 wells in the Austin Chalk in 2021. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $7.0 million per well.
The company has identified additional net resource potential of 11.5 Tcf and 720 net premium drilling locations in the Lower and Upper Eagle Ford, which underlies the Austin Chalk in the same area. Wells targeting the Eagle Ford also generate strong premium rates of return, supported by low drilling costs and shared infrastructure with the Austin Chalk wells.
The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000 foot lateral at a targeted well cost of $6.5 million per well.
Including the Dorado locations, EOG added 1,400 net premium drilling locations to its undrilled premium inventory in the third quarter 2020. Taking into account wells drilled over the past year and updated location counts across its portfolio, EOG's premium inventory now totals approximately 11,500 net locations.
"Our new South Texas natural gas play is the latest example of EOG's sustainable business model of organic exploration-driven resource expansion," Thomas said. "The addition of Dorado to EOG's diverse portfolio of premium plays improves the financial profile of EOG by every measure. It also allows us to diversify capital deployment throughout the organization and across our assets. We believe this prolific new discovery represents the lowest-cost natural gas play in the U.S., which will be both operationally efficient and have a small environmental footprint. With 21 Tcf of net resource potential captured by EOG in the heart of the play, it is also one of the largest. Dorado competes today with EOG's premium oil plays, and we expect it to move rapidly into the top tier of our inventory as development unfolds. This is just the latest example of how EOG continues to organically improve."
Capital Allocation Outlook
Over the next three years, EOG's goal is to continue improving reinvestment returns, lowering per-unit operating costs and generating strong free cash flow to support a growing sustainable dividend while further strengthening its balance sheet. The company anticipates the current imbalance in the global crude oil market is likely to extend into 2021, and therefore expects to maintain its crude oil production at approximately the same level as the fourth quarter 2020. Assuming a balanced crude oil market after 2021, EOG expects to reinvest 70 to 80 percent of its discretionary cash flow and generate up to 10 percent compound annual crude oil production growth in 2022 and 2023 at a $50 West Texas Intermediate crude oil price and using the company's current inventory of premium locations. At higher oil prices, EOG expects to maintain the same growth rate of up to 10 percent per year. Priorities for the allocation of additional free cash flow include sustainable dividend growth, debt reduction, the return of additional cash to shareholders and low-cost property acquisitions.
"Our new three-year outlook provides visibility into the momentum we have built the last four years since the introduction of our premium return criteria," Thomas said. "EOG's long-term strategy and capital allocation priorities remain consistent. We are focused on high-return reinvestment in our growing stable of premium plays, which continues to improve in quality and drives increasing capital efficiency. With our disciplined capital allocation, we expect free cash flow growth, which will support sustainable dividend growth and further strengthen the balance sheet. Returning additional cash to shareholders also becomes more likely as oil prices continue to recover. Altogether, this balanced strategy leverages the competitive strengths of EOG and maximizes total shareholder value."
Financial Review
At September 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $3.1 billion of cash on the balance sheet at the end of the third quarter, EOG's net debt-to-total capitalization ratio was 12 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of September 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG divested its assets in the Marcellus Shale effective September 1, 2020 for proceeds of approximately $130 million. Current production from the divested assets is approximately 40 million cubic feet of natural gas per day and there were no premium locations associated with the assets.
Third Quarter 2020 Results Webcast
Friday, November 6, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
Category: Earnings
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
Income Statements
In thousands of USD, except per share data (Unaudited) | |||||||||||
3Q 2020 | 3Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | 1,394,622 | 2,418,989 | 4,074,747 | 7,148,258 | |||||||
Natural Gas Liquids | 184,771 | 164,736 | 439,215 | 569,748 | |||||||
Natural Gas | 183,790 | 269,625 | 535,250 | 874,489 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative | (3,978) | 85,902 | 1,075,433 | 242,622 | |||||||
Gathering, Processing and Marketing | 538,955 | 1,334,450 | 1,940,387 | 4,121,490 | |||||||
Gains (Losses) on Asset Dispositions, Net | (70,976) | (523) | (41,283) | 3,650 | |||||||
Other, Net | 18,300 | 30,276 | 42,801 | 99,470 | |||||||
Total | 2,245,484 | 4,303,455 | 8,066,550 | 13,059,727 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 227,473 | 348,883 | 802,478 | 1,032,455 | |||||||
Transportation Costs | 180,257 | 199,365 | 540,281 | 549,988 | |||||||
Gathering and Processing Costs | 114,790 | 127,549 | 340,039 | 351,487 | |||||||
Exploration Costs | 38,413 | 34,540 | 105,373 | 103,386 | |||||||
Dry Hole Costs | 12,604 | 24,138 | 13,063 | 28,001 | |||||||
Impairments | 78,990 | 105,275 | 1,957,340 | 289,761 | |||||||
Marketing Costs | 521,351 | 1,343,293 | 2,074,788 | 4,114,265 | |||||||
Depreciation, Depletion and Amortization | 823,050 | 953,597 | 2,529,789 | 2,790,496 | |||||||
General and Administrative | 124,460 | 135,758 | 370,588 | 364,210 | |||||||
Taxes Other Than Income | 126,810 | 203,098 | 364,489 | 600,418 | |||||||
Total | 2,248,198 | 3,475,496 | 9,098,228 | 10,224,467 | |||||||
Operating Income (Loss) | (2,714) | 827,959 | (1,031,678) | 2,835,260 | |||||||
Other Income, Net | 3,401 | 9,118 | 17,009 | 23,233 | |||||||
Income (Loss) Before Interest Expense and Income Taxes | 687 | 837,077 | (1,014,669) | 2,858,493 | |||||||
Interest Expense, Net | 53,242 | 39,620 | 152,145 | 144,434 | |||||||
Income (Loss) Before Income Taxes | (52,555) | 797,457 | (1,166,814) | 2,714,059 | |||||||
Income Tax Provision (Benefit) | (10,088) | 182,335 | (224,776) | 615,670 | |||||||
Net Income (Loss) | (42,467) | 615,122 | (942,038) | 2,098,389 | |||||||
Dividends Declared per Common Share | 0.3750 | 0.2875 | 1.1250 | 0.7950 | |||||||
Net Income (Loss) Per Share | |||||||||||
Basic | (0.07) | 1.06 | (1.63) | 3.63 | |||||||
Diluted | (0.07) | 1.06 | (1.63) | 3.61 | |||||||
Average Number of Common Shares | |||||||||||
Basic | 579,055 | 577,839 | 578,740 | 577,498 | |||||||
Diluted | 579,055 | 581,271 | 578,740 | 581,190 |
Wellhead Volumes and Prices
(Unaudited) | |||||||||||||||||
3Q 2020 | 3Q 2019 | % Change | YTD 2020 | YTD 2019 | % Change | ||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||||
United States | 376.6 | 463.2 | -19 | % | 396.6 | 451.2 | -12 | % | |||||||||
Trinidad | 1.0 | 0.8 | 25 | % | 0.5 | 0.7 | -29 | % | |||||||||
Other International (B) | — | 0.1 | -100 | % | 0.2 | 0.1 | 100 | % | |||||||||
Total | 377.6 | 464.1 | -19 | % | 397.3 | 452.0 | -12 | % | |||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||||
United States | 40.19 | 56.67 | -29 | % | 37.45 | 57.95 | -35 | % | |||||||||
Trinidad | 25.41 | 48.36 | -47 | % | 26.35 | 47.26 | -44 | % | |||||||||
Other International (B) | 25.29 | 59.87 | -58 | % | 45.09 | 58.43 | -23 | % | |||||||||
Composite | 40.15 | 56.66 | -29 | % | 37.44 | 57.93 | -35 | % | |||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||||
United States | 140.1 | 141.3 | -1 | % | 134.2 | 130.8 | 3 | % | |||||||||
Other International (B) | — | — | — | — | |||||||||||||
Total | 140.1 | 141.3 | -1 | % | 134.2 | 130.8 | 3 | % | |||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||||
United States | 14.34 | 12.67 | 13 | % | 11.95 | 15.96 | -25 | % | |||||||||
Other International (B) | — | — | — | — | |||||||||||||
Composite | 14.34 | 12.67 | 13 | % | 11.95 | 15.96 | -25 | % | |||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||||
United States | 1,008 | 1,079 | -7 | % | 1,029 | 1,043 | -1 | % | |||||||||
Trinidad | 151 | 260 | -42 | % | 175 | 267 | -34 | % | |||||||||
Other International (B) | 31 | 34 | -9 | % | 34 | 36 | -6 | % | |||||||||
Total | 1,190 | 1,373 | -13 | % | 1,238 | 1,346 | -8 | % | |||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||||
United States | 1.49 | 1.97 | -25 | % | 1.38 | 2.23 | -38 | % | |||||||||
Trinidad | 2.35 | 2.52 | -7 | % | 2.20 | 2.71 | -19 | % | |||||||||
Other International (B) | 4.73 | 4.25 | 11 | % | 4.45 | 4.29 | 4 | % | |||||||||
Composite | 1.68 | 2.13 | -21 | % | 1.58 | 2.38 | -34 | % | |||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||||
United States | 684.7 | 784.3 | -13 | % | 702.3 | 755.8 | -7 | % | |||||||||
Trinidad | 26.2 | 44.1 | -41 | % | 29.8 | 45.1 | -34 | % | |||||||||
Other International (B) | 5.1 | 5.8 | -12 | % | 5.7 | 6.2 | -8 | % | |||||||||
Total | 716.0 | 834.2 | -14 | % | 737.8 | 807.1 | -9 | % | |||||||||
Total MMBoe (D) | 65.9 | 76.7 | -14 | % | 202.2 | 220.3 | -8 | % | |||||||||
(A) | Thousand barrels per day or million cubic feet per day, as applicable. |
(B) | Other International includes EOG's China and Canada operations. |
(C) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2020). |
(D) | Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
Balance Sheets
In thousands of USD, except share data (Unaudited) | |||||
September 30, | December 31, | ||||
2020 | 2019 | ||||
Current Assets | |||||
Cash and Cash Equivalents | 3,065,556 | 2,027,972 | |||
Accounts Receivable, Net | 1,134,346 | 2,001,658 | |||
Inventories | 668,541 | 767,297 | |||
Assets from Price Risk Management Activities | 18,417 | 1,299 | |||
Income Taxes Receivable | 3,182 | 151,665 | |||
Other | 205,015 | 323,448 | |||
Total | 5,095,057 | 5,273,339 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 64,020,452 | 62,830,415 | |||
Other Property, Plant and Equipment | 4,402,091 | 4,472,246 | |||
Total Property, Plant and Equipment | 68,422,543 | 67,302,661 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (39,789,537) | (36,938,066) | |||
Total Property, Plant and Equipment, Net | 28,633,006 | 30,364,595 | |||
Deferred Income Taxes | 1,916 | 2,363 | |||
Other Assets | 1,344,039 | 1,484,311 | |||
Total Assets | 35,074,018 | 37,124,608 | |||
Current Liabilities | |||||
Accounts Payable | 1,245,029 | 2,429,127 | |||
Accrued Taxes Payable | 267,245 | 254,850 | |||
Dividends Payable | 217,334 | 166,273 | |||
Liabilities from Price Risk Management Activities | 23,486 | 20,194 | |||
Current Portion of Long-Term Debt | 770,831 | 1,014,524 | |||
Current Portion of Operating Lease Liabilities | 255,357 | 369,365 | |||
Other | 240,760 | 232,655 | |||
Total | 3,020,042 | 4,486,988 | |||
Long-Term Debt | 4,949,902 | 4,160,919 | |||
Other Liabilities | 2,151,092 | 1,789,884 | |||
Deferred Income Taxes | 4,804,656 | 5,046,101 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 583,668,294 | 205,837 | 205,822 | |||
Additional Paid in Capital | 5,916,213 | 5,817,475 | |||
Accumulated Other Comprehensive Loss | (7,930) | (4,652) | |||
Retained Earnings | 14,051,197 | 15,648,604 | |||
Common Stock Held in Treasury, 322,591 Shares at September 30, 2020 and | (16,991) | (26,533) | |||
Total Stockholders' Equity | 20,148,326 | 21,640,716 | |||
Total Liabilities and Stockholders' Equity | 35,074,018 | 37,124,608 |
Cash Flows Statements
In thousands of USD (Unaudited) | |||||||||||
3Q 2020 | 3Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Cash Flows from Operating Activities | |||||||||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: | |||||||||||
Net Income (Loss) | (42,467) | 615,122 | (942,038) | 2,098,389 | |||||||
Items Not Requiring (Providing) Cash | |||||||||||
Depreciation, Depletion and Amortization | 823,050 | 953,597 | 2,529,789 | 2,790,496 | |||||||
Impairments | 78,990 | 105,275 | 1,957,340 | 289,761 | |||||||
Stock-Based Compensation Expenses | 33,811 | 54,670 | 113,454 | 132,323 | |||||||
Deferred Income Taxes | (33,311) | 184,282 | (241,003) | 508,576 | |||||||
(Gains) Losses on Asset Dispositions, Net | 70,976 | 523 | 41,283 | (3,650) | |||||||
Other, Net | 1,465 | (1,284) | 1,636 | 4,155 | |||||||
Dry Hole Costs | 12,604 | 24,138 | 13,063 | 28,001 | |||||||
Mark-to-Market Commodity Derivative Contracts | |||||||||||
Total (Gains) Losses | 3,978 | (85,902) | (1,075,433) | (242,622) | |||||||
Net Cash Received from Settlements of Commodity Derivative | 275,133 | 108,418 | 998,894 | 139,708 | |||||||
Other, Net | (465) | (424) | (1,185) | 1,215 | |||||||
Changes in Components of Working Capital and Other Assets and | |||||||||||
Accounts Receivable | (260,829) | 63,891 | 930,628 | (5,855) | |||||||
Inventories | 7,439 | 66,857 | 92,014 | 55,598 | |||||||
Accounts Payable | (37,755) | 7,400 | (1,222,473) | 134,253 | |||||||
Accrued Taxes Payable | 73,482 | 34,767 | 12,395 | 88,047 | |||||||
Other Assets | 161,879 | (92,814) | 414,857 | 394,573 | |||||||
Other Liabilities | 51,664 | 39,791 | (12,739) | (18,315) | |||||||
Changes in Components of Working Capital Associated with | (6,091) | (16,643) | 276,063 | (38,677) | |||||||
Net Cash Provided by Operating Activities | 1,213,553 | 2,061,664 | 3,886,545 | 6,355,976 | |||||||
Investing Cash Flows | |||||||||||
Additions to Oil and Gas Properties | (468,487) | (1,420,385) | (2,458,520) | (4,866,882) | |||||||
Additions to Other Property, Plant and Equipment | (17,652) | (70,469) | (165,018) | (187,350) | |||||||
Proceeds from Sales of Assets | 145,575 | 17,767 | 188,943 | 35,409 | |||||||
Changes in Components of Working Capital Associated with | 6,091 | 16,621 | (276,063) | 38,677 | |||||||
Net Cash Used in Investing Activities | (334,473) | (1,456,466) | (2,710,658) | (4,980,146) | |||||||
Financing Cash Flows | |||||||||||
Long-Term Debt Borrowings | — | — | 1,483,852 | — | |||||||
Long-Term Debt Repayments | — | — | (1,000,000) | (900,000) | |||||||
Dividends Paid | (217,142) | (166,170) | (601,242) | (420,851) | |||||||
Treasury Stock Purchased | (9,764) | (13,835) | (14,821) | (22,238) | |||||||
Proceeds from Stock Options Exercised and Employee Stock | — | 863 | 8,614 | 9,558 | |||||||
Debt Issuance Costs | — | (114) | (2,635) | (5,016) | |||||||
Repayment of Finance Lease Liabilities | (4,864) | (3,235) | (13,309) | (9,638) | |||||||
Changes in Components of Working Capital Associated with | — | 22 | — | — | |||||||
Net Cash Used in Financing Activities | (231,770) | (182,469) | (139,541) | (1,348,185) | |||||||
Effect of Exchange Rate Changes on Cash | 1,745 | (109) | 1,238 | (174) | |||||||
Increase in Cash and Cash Equivalents | 649,055 | 422,620 | 1,037,584 | 27,471 | |||||||
Cash and Cash Equivalents at Beginning of Period | 2,416,501 | 1,160,485 | 2,027,972 | 1,555,634 | |||||||
Cash and Cash Equivalents at End of Period | 3,065,556 | 1,583,105 | 3,065,556 | 1,583,105 |
Non-GAAP Financial Measures
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics. |
A reconciliation of each of these measures to their most directly comparable GAAP financial measure is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com. |
EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance. |
EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods. |
The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Total Debt, Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. |
In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) | |||||||||||
3Q 2020 | |||||||||||
Before Tax | Income Tax | After Tax | Diluted | ||||||||
Reported Net Loss (GAAP) | (52,555) | 10,088 | (42,467) | (0.07) | |||||||
Adjustments: | |||||||||||
Losses on Mark-to-Market Commodity Derivative Contracts | 3,978 | (873) | 3,105 | (0.01) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 275,133 | (60,386) | 214,747 | 0.37 | |||||||
Add: Losses on Asset Dispositions, Net | 70,976 | (15,600) | 55,376 | 0.10 | |||||||
Add: Certain Impairments | 26,531 | (5,636) | 20,895 | 0.04 | |||||||
Adjustments to Net Income (Loss) | 376,618 | (82,495) | 294,123 | 0.50 | |||||||
Adjusted Net Income (Non-GAAP) | 324,063 | (72,407) | 251,656 | 0.43 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 579,055 | ||||||||||
Diluted | 579,055 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 579,055 | ||||||||||
Diluted | 580,609 | ||||||||||
3Q 2019 | |||||||||||
Before Tax | Income Tax | After Tax | Diluted Earnings | ||||||||
Reported Net Income (GAAP) | 797,457 | (182,335) | 615,122 | 1.06 | |||||||
Adjustments: | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (85,902) | 18,854 | (67,048) | (0.12) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 108,418 | (23,796) | 84,622 | 0.15 | |||||||
Add: Losses on Asset Dispositions, Net | 523 | (89) | 434 | — | |||||||
Add: Certain Impairments | 27,215 | (5,973) | 21,242 | 0.04 | |||||||
Adjustments to Net Income (Loss) | 50,254 | (11,004) | 39,250 | 0.07 | |||||||
Adjusted Net Income (Non-GAAP) | 847,711 | (193,339) | 654,372 | 1.13 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 577,839 | ||||||||||
Diluted | 581,271 | ||||||||||
Average Number of Common Shares (Non-GAAP) | 577,839 | ||||||||||
Basic | 581,271 | ||||||||||
Diluted |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) | |||||||||||
YTD 2020 | |||||||||||
Before Tax | Income Tax | After Tax | Diluted Earnings | ||||||||
Reported Net Loss (GAAP) | (1,166,814) | 224,776 | (942,038) | (1.63) | |||||||
Adjustments: | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (1,075,433) | 236,036 | (839,397) | (1.45) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 998,894 | (219,237) | 779,657 | 1.35 | |||||||
Add: Losses on Asset Dispositions, Net | 41,283 | (9,057) | 32,226 | 0.06 | |||||||
Add: Certain Impairments | 1,782,014 | (373,960) | 1,408,054 | 2.43 | |||||||
Adjustments to Net Income (Loss) | 1,746,758 | (366,218) | 1,380,540 | 2.39 | |||||||
Adjusted Net Income (Non-GAAP) | 579,944 | (141,442) | 438,502 | 0.76 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 578,740 | ||||||||||
Diluted | 578,740 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 578,740 | ||||||||||
Diluted | 580,301 | ||||||||||
YTD 2019 | |||||||||||
Before Tax | Income Tax | After Tax | Diluted | ||||||||
Reported Net Income (GAAP) | 2,714,059 | (615,670) | 2,098,389 | 3.61 | |||||||
Adjustments: | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (242,622) | 53,251 | (189,371) | (0.34) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 139,708 | (30,663) | 109,045 | 0.19 | |||||||
Add: Gains on Asset Dispositions, Net | (3,650) | 910 | (2,740) | — | |||||||
Add: Certain Impairments | 116,249 | (25,514) | 90,735 | 0.16 | |||||||
Adjustments to Net Income (Loss) | 9,685 | (2,016) | 7,669 | 0.01 | |||||||
Adjusted Net Income (Non-GAAP) | 2,723,744 | (617,686) | 2,106,058 | 3.62 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 577,498 | ||||||||||
Diluted | 581,190 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 577,498 | ||||||||||
Diluted | 581,190 |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | |||||||||||
3Q 2020 | 3Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Net Cash Provided by Operating Activities (GAAP) | 1,213,553 | 2,061,664 | 3,886,545 | 6,355,976 | |||||||
Adjustments: | |||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 37,380 | 29,374 | 90,346 | 85,250 | |||||||
Other Non-Current Income Taxes - Net Receivable | — | 33,855 | 112,704 | 179,537 | |||||||
Changes in Components of Working Capital and Other Assets and | |||||||||||
Accounts Receivable | 260,829 | (63,891) | (930,628) | 5,855 | |||||||
Inventories | (7,439) | (66,857) | (92,014) | (55,598) | |||||||
Accounts Payable | 37,755 | (7,400) | 1,222,473 | (134,253) | |||||||
Accrued Taxes Payable | (73,482) | (34,767) | (12,395) | (88,047) | |||||||
Other Assets | (161,879) | 92,814 | (414,857) | (394,573) | |||||||
Other Liabilities | (51,664) | (39,791) | 12,739 | 18,315 | |||||||
Changes in Components of Working Capital Associated with | 6,091 | 16,643 | (276,063) | 38,677 | |||||||
Discretionary Cash Flow (Non-GAAP) | 1,261,144 | 2,021,644 | 3,598,850 | 6,011,139 | |||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -38 | % | -40 | % | |||||||
Discretionary Cash Flow (Non-GAAP) | 1,261,144 | 2,021,644 | 3,598,850 | 6,011,139 | |||||||
Less: | |||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (499,305) | (1,518,019) | (2,661,641) | (4,846,221) | |||||||
Free Cash Flow (Non-GAAP) (b) | 761,839 | 503,625 | 937,209 | 1,164,918 | |||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and nine-month periods ended September 30, 2020 and 2019: | |||||||||||
Total Expenditures (GAAP) | 645,534 | 1,629,343 | 3,005,723 | 5,394,389 | |||||||
Less: | |||||||||||
Asset Retirement Costs | (42,650) | (90,970) | (68,213) | (151,551) | |||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | — | — | (60) | (586) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | (80,757) | (10,666) | (128,488) | (64,387) | |||||||
Non-Cash Finance Leases | — | — | (73,277) | — | |||||||
Acquisition Costs of Proved Properties | (22,822) | (9,688) | (74,044) | (331,644) | |||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 499,305 | 1,518,019 | 2,661,641 | 4,846,221 | |||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the three-month and nine-month periods ending September 30, 2020. The comparative prior periods shown have been revised to conform to this presentation. | |||||||||||
Maintenance Capital Expenditures | |||||||||||
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to anticipated 4Q 2020 U.S. oil production. |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | ||||||||
FY 2019 | FY 2018 | FY 2017 | ||||||
Net Cash Provided by Operating Activities (GAAP) | 8,163,180 | 7,768,608 | 4,265,336 | |||||
Adjustments: | ||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 113,733 | 123,986 | 122,688 | |||||
Other Non-Current Income Taxes - Net (Payable) Receivable | 238,711 | 148,993 | (513,404) | |||||
Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||
Accounts Receivable | 91,792 | 368,180 | 392,131 | |||||
Inventories | (90,284) | 395,408 | 174,548 | |||||
Accounts Payable | (168,539) | (439,347) | (324,192) | |||||
Accrued Taxes Payable | (40,122) | 92,461 | 63,937 | |||||
Other Assets | (358,001) | 125,435 | 658,609 | |||||
Other Liabilities | 56,619 | (10,949) | 89,871 | |||||
Changes in Components of Working Capital Associated with Investing and | 115,061 | (301,083) | (89,992) | |||||
Discretionary Cash Flow (Non-GAAP) | 8,122,150 | 8,271,692 | 4,839,532 | |||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease) | -2 | % | 71 | % | 76 | % | ||
Discretionary Cash Flow (Non-GAAP) | 8,122,150 | 8,271,692 | 4,839,532 | |||||
Less: | ||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (6,234,454) | (6,172,950) | (4,228,859) | |||||
Free Cash Flow (Non-GAAP) (b) | 1,887,696 | 2,098,742 | 610,673 | |||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017: | ||||||||
Total Expenditures (GAAP) | 6,900,450 | 6,706,359 | 4,612,746 | |||||
Less: | ||||||||
Asset Retirement Costs | (186,088) | (69,699) | (55,592) | |||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (2,266) | (49,484) | — | |||||
Non-Cash Acquisition Costs of Unproved Properties | (97,704) | (290,542) | (255,711) | |||||
Acquisition Costs of Proved Properties | (379,938) | (123,684) | (72,584) | |||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 6,234,454 | 6,172,950 | 4,228,859 | |||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. The comparative prior periods shown have been revised to conform to this presentation. |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | ||||||||||||||
FY 2016 | FY 2015 | FY 2014 | FY 2013 | FY 2012 | ||||||||||
Net Cash Provided by Operating Activities (GAAP) | 2,359,063 | 3,595,165 | 8,649,155 | 7,329,414 | 5,236,777 | |||||||||
Adjustments: | ||||||||||||||
Exploration Costs (excluding Stock-Based | 104,199 | 124,011 | 157,453 | 134,531 | 159,182 | |||||||||
Excess Tax Benefits from Stock-Based Compensation | 29,357 | 26,058 | 99,459 | 55,831 | 67,035 | |||||||||
Changes in Components of Working Capital and | ||||||||||||||
Accounts Receivable | 232,799 | (641,412) | (84,982) | 23,613 | 178,683 | |||||||||
Inventories | (170,694) | (58,450) | 161,958 | (53,402) | 156,762 | |||||||||
Accounts Payable | 74,048 | 1,409,197 | (543,630) | (178,701) | 17,150 | |||||||||
Accrued Taxes Payable | (92,782) | (11,798) | (16,486) | (75,142) | (78,094) | |||||||||
Other Assets | 40,636 | (118,143) | 14,448 | 109,567 | 118,520 | |||||||||
Other Liabilities | 16,225 | 66,257 | (75,420) | 20,382 | (36,114) | |||||||||
Changes in Components of Working Capital | 156,102 | (499,767) | 103,414 | 51,361 | (74,158) | |||||||||
Discretionary Cash Flow (Non-GAAP) | 2,748,953 | 3,891,118 | 8,465,369 | 7,417,454 | 5,745,743 | |||||||||
Discretionary Cash Flow (Non-GAAP) - Percentage | -29 | % | -54 | % | 14 | % | 29 | % | ||||||
Discretionary Cash Flow (Non-GAAP) | 2,748,953 | 3,891,118 | 8,465,369 | 7,417,454 | 5,745,743 | |||||||||
Less: | ||||||||||||||
Total Cash Capital Expenditures Before Acquisitions | (2,706,397) | (4,682,326) | (8,292,090) | (7,101,791) | (7,539,994) | |||||||||
Free Cash Flow (Non-GAAP) (b) | 42,556 | (791,208) | 173,279 | 315,663 | (1,794,251) | |||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2016, 2015, 2014, 2013 and 2012: | ||||||||||||||
Total Expenditures (GAAP) | 6,554,053 | 5,216,413 | 8,631,906 | 7,361,457 | 7,753,828 | |||||||||
Less: | ||||||||||||||
Asset Retirement Costs | 19,865 | (53,470) | (195,630) | (134,445) | (126,987) | |||||||||
Non-Cash Expenditures of Other Property, Plant | (16,585) | — | — | — | (65,791) | |||||||||
Non-Cash Acquisition Costs of Unproved Properties | (3,101,913) | — | (5,085) | (5,007) | (20,317) | |||||||||
Acquisition Costs of Proved Properties | (749,023) | (480,617) | (139,101) | (120,214) | (739) | |||||||||
Total Cash Capital Expenditures Before Acquisitions | 2,706,397 | 4,682,326 | 8,292,090 | 7,101,791 | 7,539,994 | |||||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item. |
Total Expenditures
In millions of USD (Unaudited) | ||||||||||||||
3Q 2020 | 3Q 2019 | FY 2019 | FY 2018 | FY 2017 | ||||||||||
Exploration and Development Drilling | 378 | 1,173 | 4,951 | 4,935 | 3,132 | |||||||||
Facilities | 38 | 161 | 629 | 625 | 575 | |||||||||
Leasehold Acquisitions | 88 | 56 | 276 | 488 | 427 | |||||||||
Property Acquisitions | 23 | 10 | 380 | 124 | 73 | |||||||||
Capitalized Interest | 7 | 10 | 38 | 24 | 27 | |||||||||
Subtotal | 534 | 1,410 | 6,274 | 6,196 | 4,234 | |||||||||
Exploration Costs | 38 | 34 | 140 | 149 | 145 | |||||||||
Dry Hole Costs | 13 | 24 | 28 | 5 | 5 | |||||||||
Exploration and Development Expenditures | 585 | 1,468 | 6,442 | 6,350 | 4,384 | |||||||||
Asset Retirement Costs | 44 | 91 | 186 | 70 | 56 | |||||||||
Total Exploration and Development Expenditures | 629 | 1,559 | 6,628 | 6,420 | 4,440 | |||||||||
Other Property, Plant and Equipment | 17 | 70 | 272 | 286 | 173 | |||||||||
Total Expenditures | 646 | 1,629 | 6,900 | 6,706 | 4,613 |
EBITDAX and Adjusted EBITDAX
In thousands of USD (Unaudited) | |||||||||||
3Q 2020 | 3Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Net Income (Loss) (GAAP) | (42,467) | 615,122 | (942,038) | 2,098,389 | |||||||
Adjustments: | |||||||||||
Interest Expense, Net | 53,242 | 39,620 | 152,145 | 144,434 | |||||||
Income Tax Provision (Benefit) | (10,088) | 182,335 | (224,776) | 615,670 | |||||||
Depreciation, Depletion and Amortization | 823,050 | 953,597 | 2,529,789 | 2,790,496 | |||||||
Exploration Costs | 38,413 | 34,540 | 105,373 | 103,386 | |||||||
Dry Hole Costs | 12,604 | 24,138 | 13,063 | 28,001 | |||||||
Impairments | 78,990 | 105,275 | 1,957,340 | 289,761 | |||||||
EBITDAX (Non-GAAP) | 953,744 | 1,954,627 | 3,590,896 | 6,070,137 | |||||||
(Gains) Losses on MTM Commodity Derivative Contracts | 3,978 | (85,902) | (1,075,433) | (242,622) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 275,133 | 108,418 | 998,894 | 139,708 | |||||||
(Gains) Losses on Asset Dispositions, Net | 70,976 | 523 | 41,283 | (3,650) | |||||||
Adjusted EBITDAX (Non-GAAP) | 1,303,831 | 1,977,666 | 3,555,640 | 5,963,573 | |||||||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -34 | % | -40 | % | |||||||
Definitions | |||||||||||
EBITDAX - Earnings Before Interest Expense, Net; Income Tax Provision (Benefit); Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | ||||||||
September 30, 2020 | June 30, 2020 | March 31, 2020 | ||||||
Total Stockholders' Equity - (a) | 20,148 | 20,388 | 21,471 | |||||
Current and Long-Term Debt (GAAP) - (b) | 5,721 | 5,724 | 5,222 | |||||
Less: Cash | (3,066) | (2,417) | (2,907) | |||||
Net Debt (Non-GAAP) - (c) | 2,655 | 3,307 | 2,315 | |||||
Total Capitalization (GAAP) - (a) + (b) | 25,869 | 26,112 | 26,693 | |||||
Total Capitalization (Non-GAAP) - (a) + (c) | 22,803 | 23,695 | 23,786 | |||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 22 | % | 22 | % | 20 | % | ||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 12 | % | 14 | % | 10 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||
December 31, | September 30, | June 30, 2019 | March 31, 2019 | ||||||||
Total Stockholders' Equity - (a) | 21,641 | 21,124 | 20,630 | 19,904 | |||||||
Current and Long-Term Debt (GAAP) - (b) | 5,175 | 5,177 | 5,179 | 6,081 | |||||||
Less: Cash | (2,028) | (1,583) | (1,160) | (1,136) | |||||||
Net Debt (Non-GAAP) - (c) | 3,147 | 3,594 | 4,019 | 4,945 | |||||||
Total Capitalization (GAAP) - (a) + (b) | 26,816 | 26,301 | 25,809 | 25,985 | |||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 24,788 | 24,718 | 24,649 | 24,849 | |||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 19 | % | 20 | % | 20 | % | 23 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 13 | % | 15 | % | 16 | % | 20 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||
December 31, 2018 | September 30, 2018 | June 30, 2018 | March 31, 2018 | ||||||||
Total Stockholders' Equity - (a) | 19,364 | 18,538 | 17,452 | 16,841 | |||||||
Current and Long-Term Debt (GAAP) - (b) | 6,083 | 6,435 | 6,435 | 6,435 | |||||||
Less: Cash | (1,556) | (1,274) | (1,008) | (816) | |||||||
Net Debt (Non-GAAP) - (c) | 4,527 | 5,161 | 5,427 | 5,619 | |||||||
Total Capitalization (GAAP) - (a) + (b) | 25,447 | 24,973 | 23,887 | 23,276 | |||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 23,891 | 23,699 | 22,879 | 22,460 | |||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 24 | % | 26 | % | 27 | % | 28 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 19 | % | 22 | % | 24 | % | 25 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||
December 31, 2017 | September 30, 2017 | June 30, 2017 | March 31, 2017 | ||||||||
Total Stockholders' Equity - (a) | 16,283 | 13,922 | 13,902 | 13,928 | |||||||
Current and Long-Term Debt (GAAP) - (b) | 6,387 | 6,387 | 6,987 | 6,987 | |||||||
Less: Cash | (834) | (846) | (1,649) | (1,547) | |||||||
Net Debt (Non-GAAP) - (c) | 5,553 | 5,541 | 5,338 | 5,440 | |||||||
Total Capitalization (GAAP) - (a) + (b) | 22,670 | 20,309 | 20,889 | 20,915 | |||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 21,836 | 19,463 | 19,240 | 19,368 | |||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 28 | % | 31 | % | 33 | % | 33 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 25 | % | 28 | % | 28 | % | 28 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
December 31, | September 30, | June 30, 2016 | March 31, 2016 | December 31, 2015 | ||||||||||
Total Stockholders' Equity - (a) | 13,982 | 11,798 | 12,057 | 12,405 | 12,943 | |||||||||
Current and Long-Term Debt (GAAP) - (b) | 6,986 | 6,986 | 6,986 | 6,986 | 6,660 | |||||||||
Less: Cash | (1,600) | (1,049) | (780) | (668) | (719) | |||||||||
Net Debt (Non-GAAP) - (c) | 5,386 | 5,937 | 6,206 | 6,318 | 5,941 | |||||||||
Total Capitalization (GAAP) - (a) + (b) | 20,968 | 18,784 | 19,043 | 19,391 | 19,603 | |||||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 19,368 | 17,735 | 18,263 | 18,723 | 18,884 | |||||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + | 33 | % | 37 | % | 37 | % | 36 | % | 34 | % | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) | 28 | % | 33 | % | 34 | % | 34 | % | 31 | % |
Reserve Replacement Cost Data
In millions of USD, except reserves and ratio data (Unaudited) | |||||||||||||||||
2019 | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||
Total Costs Incurred in Exploration and Development | 6,628.2 | 6,419.7 | 4,439.4 | 6,445.2 | 4,928.3 | 7,904.8 | |||||||||||
Less: Asset Retirement Costs | (186.1) | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | |||||||||||
Non-Cash Acquisition Costs of Unproved | (97.7) | (290.5) | (255.7) | (3,101.8) | — | — | |||||||||||
Acquisition Costs of Proved Properties | (379.9) | (123.7) | (72.6) | (749.0) | (480.6) | (139.1) | |||||||||||
Total Exploration and Development Expenditures for | 5,964.5 | 5,935.8 | 4,055.5 | 2,614.3 | 4,394.2 | 7,570.1 | |||||||||||
Total Costs Incurred in Exploration and Development | 6,628.2 | 6,419.7 | 4,439.4 | 6,445.2 | 4,928.3 | 7,904.8 | |||||||||||
Less: Asset Retirement Costs | (186.1) | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | |||||||||||
Non-Cash Acquisition Costs of Unproved | (97.7) | (290.5) | (255.7) | (3,101.8) | — | — | |||||||||||
Non-Cash Acquisition Costs of Proved Properties | (52.3) | (70.9) | (26.2) | (732.3) | — | — | |||||||||||
Total Exploration and Development Expenditures | 6,292.1 | 5,988.6 | 4,101.9 | 2,631.0 | 4,874.8 | 7,709.2 | |||||||||||
Net Proved Reserve Additions From All Sources - Oil | |||||||||||||||||
Revisions Due to Price - (c) | (59.7) | 34.8 | 154.0 | (100.7) | (573.8) | 52.2 | |||||||||||
Revisions Other Than Price | (0.3) | (39.5) | 48.0 | 252.9 | 107.2 | 48.4 | |||||||||||
Purchases in Place | 16.8 | 11.6 | 2.3 | 42.3 | 56.2 | 14.4 | |||||||||||
Extensions, Discoveries and Other Additions - (d) | 750.0 | 669.7 | 420.8 | 209.0 | 245.9 | 519.2 | |||||||||||
Total Proved Reserve Additions - (e) | 706.8 | 676.6 | 625.1 | 403.5 | (164.5) | 634.2 | |||||||||||
Sales in Place | (4.6) | (10.8) | (20.7) | (167.6) | (3.5) | (36.3) | |||||||||||
Net Proved Reserve Additions From All Sources | 702.2 | 665.8 | 604.4 | 235.9 | (168.0) | 597.9 | |||||||||||
Production | 300.9 | 265.0 | 224.4 | 207.1 | 211.2 | 219.1 | |||||||||||
Reserve Replacement Costs ($ / Boe) | |||||||||||||||||
Total Drilling, Before Revisions - (a / d) | 7.95 | 8.86 | 9.64 | 12.51 | 17.87 | 14.58 | |||||||||||
All-in Total, Net of Revisions - (b / e) | 8.90 | 8.85 | 6.56 | 6.52 | (29.63) | 12.16 | |||||||||||
All-in Total, Excluding Revisions Due to Price - | 8.21 | 9.33 | 8.71 | 5.22 | 11.91 | 13.25 |
Definitions
$/Boe | U.S. Dollars per barrel of oil equivalent |
MMBoe | Million barrels of oil equivalent |
Financial Commodity Derivative Contracts
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||||
ICE Brent Differential Basis Swap Contracts | |||||||
Prices received by EOG for its crude oil production generally vary from NYMEX WTI prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between ICE Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||
2020 | Volume | Weighted ($/Bbl) | |||||
May 2020 (CLOSED) | 10,000 | 4.92 | |||||
Houston Differential Basis Swap Contracts | |||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||
2020 | Volume | Weighted Average Price Differential ($/Bbl) | |||||
May 2020 (CLOSED) | 10,000 | 1.55 | |||||
Roll Differential Swap Contracts | |||||||
EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through October 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. | |||||||
2020 | Volume | Weighted ($/Bbl) | |||||
February 1, 2020 through June 30, 2020 (CLOSED) | 10,000 | 0.70 | |||||
July 1, 2020 through September 30, 2020 (CLOSED) | 88,000 | (1.16) | |||||
October 1, 2020 through November 30, 2020 (CLOSED) | 66,000 | (1.16) | |||||
December 2020 | 66,000 | (1.16) | |||||
In May 2020, EOG entered into crude oil Roll Differential swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG paid net cash of $2.6 million through October 30, 2020, for the settlement of certain of these contracts and expects to pay $0.6 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table. | |||||||
Crude Oil NYMEX WTI Price Swap Contracts | |||||||
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||
2020 | Volume | Weighted | |||||
January 1, 2020 through March 31, 2020 (CLOSED) | 200,000 | 59.33 | |||||
April 1, 2020 through May 31, 2020 (CLOSED) | 265,000 | 51.36 | |||||
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG received net cash of $359.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $4.1 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table. | |||||||
Crude Oil ICE Brent Price Swap Contracts | |||||||
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||
2020 | Volume | Weighted | |||||
April 2020 (CLOSED) | 75,000 | 25.66 | |||||
May 2020 (CLOSED) | 35,000 | 26.53 | |||||
Mont Belvieu Propane Price Swap Contracts | |||||||
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through October 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||
2020 | Volume | Weighted | |||||
January 1, 2020 through February 29, 2020 (CLOSED) | 4,000 | 21.34 | |||||
March 1, 2020 through April 30, 2020 (CLOSED) | 25,000 | 17.92 | |||||
In April and May 2020, EOG entered into Mont Belvieu Propane Price Swap Contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu Propane Price Swap Contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG received net cash of $5.7 million through October 30, 2020, for the settlement of certain of these contracts, and expects to receive net cash of $3.5 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table. | |||||||
Natural Gas Price Swap Contracts | |||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||
2021 | Volume | Weighted ($/MMBtu) | |||||
January 1, 2021 through December 31, 2021 | 500,000 | 2.99 | |||||
Natural Gas Collar Contracts | ||||||||||
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. EOG received net cash of $7.8 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's natural gas collar contracts through October 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||||||||
2020 | Volume | Weighted Ceiling Price ($/MMBtu) | Weighted | |||||||
April 1, 2020 through July 31, 2020 (CLOSED) | 250,000 | 2.50 | 2.00 | |||||||
In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG received net cash of $1.1 million through October 30, 2020, for the settlement of these contracts. The offsetting contracts were excluded from the above table. | ||||||||||
Rockies Differential Basis Swap Contracts | |||||||
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||
2020 | Volume | Weighted | |||||
January 1, 2020 through October 31, 2020 (CLOSED) | 30,000 | 0.55 | |||||
November 1, 2020 through December 31, 2020 | 30,000 | 0.55 | |||||
HSC Differential Basis Swap Contracts | |||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. EOG paid net cash of $0.4 million for the settlement of these contracts. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||
2020 | Volume | Weighted | |||||
January 1, 2020 through December 31, 2020 (CLOSED) | 60,000 | 0.05 | |||||
Waha Differential Basis Swap Contracts | |||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through October 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||
2020 | Volume | Weighted | |||||
January 1, 2020 through April 30, 2020 (CLOSED) | 50,000 | 1.40 | |||||
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG paid net cash of $8.9 million through October 30, 2020, for the settlement of certain of these contracts, and expects to pay net cash of $3.0 million during the remainder of 2020 for the settlement of the remaining contracts. The offsetting contracts were excluded from the above table. | |||||||
Definitions
Bbld | Barrels per day | ||
$/Bbl | Dollars per barrel | ||
ICE | Intercontinental Exchange | ||
MMBtud | Million British thermal units per day | ||
$/MMBtu | Dollars per million British thermal units | ||
NYMEX | U.S. New York Mercantile Exchange | ||
WTI | West Texas Intermediate |
Direct After-Tax Rate of Return
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. | |
Direct ATROR | |
Based on Cash Flow and Time Value of Money | |
- Estimated future commodity prices and operating costs | |
- Costs incurred to drill, complete and equip a well, including facilities | |
Excludes Indirect Capital | |
- Gathering and Processing and other Midstream | |
- Land, Seismic, Geological and Geophysical | |
Payback ~12 Months on 100% Direct ATROR Wells | |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured | |
Return on Equity / Return on Capital Employed | |
Based on GAAP Accrual Accounting | |
Includes All Indirect Capital and Growth Capital for Infrastructure | |
- Eagle Ford, Bakken, Permian Facilities | |
- Gathering and Processing | |
Includes Legacy Gas Capital and Capital from Mature Wells |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Net Interest Expense (GAAP) | 185 | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (39) | (51) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 146 | 194 | ||||||
Net Income (GAAP) - (b) | 2,735 | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Below Detail) (1) | 158 | (201) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | 2,893 | 3,218 | ||||||
Total Stockholders' Equity - (d) | 21,641 | 19,364 | 16,283 | |||||
Average Total Stockholders' Equity * - (e) | 20,503 | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | 5,175 | 6,083 | 6,387 | |||||
Less: Cash | (2,028) | (1,556) | (834) | |||||
Net Debt (Non-GAAP) - (g) | 3,147 | 4,527 | 5,553 | |||||
Total Capitalization (GAAP) - (d) + (f) | 26,816 | 25,447 | 22,670 | |||||
Total Capitalization (Non-GAAP) - (d) + (g) | 24,788 | 23,891 | 21,836 | |||||
Average Total Capitalization (Non-GAAP) * - (h) | 24,340 | 22,864 | ||||||
Return on Capital Employed (ROCE) | ||||||||
GAAP Net Income - [(a) + (b)] / (h) | 11.8 | % | 15.8 | % | ||||
Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) | 12.5 | % | 14.9 | % | ||||
Return on Equity (ROE) | ||||||||
GAAP Net Income - (b) / (e) | 13.3 | % | 19.2 | % | ||||
Non-GAAP Adjusted Net Income - (c) / (e) | 14.1 | % | 18.1 | % | ||||
* Average for the current and immediately preceding year | ||||||||
(1) Detail of adjustments to Net Income (GAAP): | ||||||||
Before | Income Tax Impact | After | ||||||
Year Ended December 31, 2019 | ||||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | 51 | (11) | 40 | |||||
Add: Impairments of Certain Assets | 275 | (60) | 215 | |||||
Less: Net Gains on Asset Dispositions | (124) | 27 | (97) | |||||
Total | 202 | (44) | 158 | |||||
Year Ended December 31, 2018 | ||||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | (93) | 20 | (73) | |||||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | — | (110) | (110) | |||||
Total | (115) | (86) | (201) |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||
Net Interest Expense (GAAP) | 274 | 282 | 237 | 201 | 235 | |||||||||
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 178 | 183 | 154 | 131 | 153 | |||||||||
Net Income (Loss) (GAAP) - (b) | 2,583 | (1,097) | (4,525) | 2,915 | 2,197 | |||||||||
Total Stockholders' Equity - (d) | 16,283 | 13,982 | 12,943 | 17,713 | 15,418 | |||||||||
Average Total Stockholders' Equity* - (e) | 15,133 | 13,463 | 15,328 | 16,566 | 14,352 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 6,387 | 6,986 | 6,655 | 5,906 | 5,909 | |||||||||
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||||||
Net Debt (Non-GAAP) - (g) | 5,553 | 5,386 | 5,936 | 3,819 | 4,591 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 22,670 | 20,968 | 19,598 | 23,619 | 21,327 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 21,836 | 19,368 | 18,879 | 21,532 | 20,009 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 20,602 | 19,124 | 20,206 | 20,771 | 19,365 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income (Loss) - [(a) + (b)] / (h) | 13.4 | % | -4.8 | % | -21.6 | % | 14.7 | % | 12.1 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income (Loss) - (b) / (e) | 17.1 | % | -8.1 | % | -29.5 | % | 17.6 | % | 15.3 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||
Net Interest Expense (GAAP) | 214 | 210 | 130 | 101 | 52 | |||||||||
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 139 | 136 | 84 | 66 | 34 | |||||||||
Net Income (GAAP) - (b) | 570 | 1,091 | 161 | 547 | 2,437 | |||||||||
Total Stockholders' Equity - (d) | 13,285 | 12,641 | 10,232 | 9,998 | 9,015 | |||||||||
Average Total Stockholders' Equity* - (e) | 12,963 | 11,437 | 10,115 | 9,507 | 8,003 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 6,312 | 5,009 | 5,223 | 2,797 | 1,897 | |||||||||
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||||||
Net Debt (Non-GAAP) - (g) | 5,436 | 4,393 | 4,434 | 2,111 | 1,566 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 19,597 | 17,650 | 15,455 | 12,795 | 10,912 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 18,721 | 17,034 | 14,666 | 12,109 | 10,581 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 17,878 | 15,850 | 13,388 | 11,345 | 9,351 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 4.0 | % | 7.7 | % | 1.8 | % | 5.4 | % | 26.4 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 4.4 | % | 9.5 | % | 1.6 | % | 5.8 | % | 30.5 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||
Net Interest Expense (GAAP) | 47 | 43 | 63 | 63 | 59 | |||||||||
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 31 | 28 | 41 | 41 | 38 | |||||||||
Net Income (GAAP) - (b) | 1,090 | 1,300 | 1,260 | 625 | 430 | |||||||||
Total Stockholders' Equity - (d) | 6,990 | 5,600 | 4,316 | 2,945 | 2,223 | |||||||||
Average Total Stockholders' Equity* - (e) | 6,295 | 4,958 | 3,631 | 2,584 | 1,948 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 1,185 | 733 | 985 | 1,078 | 1,109 | |||||||||
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||||||
Net Debt (Non-GAAP) - (g) | 1,131 | 515 | 341 | 1,057 | 1,105 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 8,175 | 6,333 | 5,301 | 4,023 | 3,332 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 8,121 | 6,115 | 4,657 | 4,002 | 3,328 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 7,118 | 5,386 | 4,330 | 3,665 | 3,068 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 15.7 | % | 24.7 | % | 30.0 | % | 18.2 | % | 15.3 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 17.3 | % | 26.2 | % | 34.7 | % | 24.2 | % | 22.1 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||
Net Interest Expense (GAAP) | 60 | 45 | 61 | 62 | ||||||||||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 39 | 29 | 40 | 40 | ||||||||||
Net Income (GAAP) - (b) | 87 | 399 | 397 | 569 | ||||||||||
Total Stockholders' Equity - (d) | 1,672 | 1,643 | 1,381 | 1,130 | 1,280 | |||||||||
Average Total Stockholders' Equity* - (e) | 1,658 | 1,512 | 1,256 | 1,205 | ||||||||||
Current and Long-Term Debt (GAAP) - (f) | 1,145 | 856 | 859 | 990 | 1,143 | |||||||||
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||||||
Net Debt (Non-GAAP) - (g) | 1,135 | 853 | 839 | 965 | 1,137 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 2,817 | 2,499 | 2,240 | 2,120 | 2,423 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 2,807 | 2,496 | 2,220 | 2,095 | 2,417 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 2,652 | 2,358 | 2,158 | 2,256 | ||||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 4.8 | % | 18.2 | % | 20.2 | % | 27.0 | % | ||||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 5.2 | % | 26.4 | % | 31.6 | % | 47.2 | % | ||||||
* Average for the current and immediately preceding year |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | |||||||||||
1Q 2020 | 2Q 2020 | 3Q 2020 | YTD 2020 | ||||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | |||||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 79,548 | 56,733 | 65,873 | 202,153 | |||||||
Crude Oil and Condensate | 2,065,498 | 614,627 | 1,394,622 | 4,074,747 | |||||||
Natural Gas Liquids | 160,535 | 93,909 | 184,771 | 439,215 | |||||||
Natural Gas | 209,764 | 141,696 | 183,790 | 535,250 | |||||||
Total Wellhead Revenues - (b) | 2,435,797 | 850,232 | 1,763,183 | 5,049,212 | |||||||
Operating Costs | |||||||||||
Lease and Well | 329,659 | 245,346 | 227,473 | 802,478 | |||||||
Transportation Costs | 208,296 | 151,728 | 180,257 | 540,281 | |||||||
Gathering and Processing Costs | 128,482 | 96,767 | 114,790 | 340,039 | |||||||
General and Administrative | 114,273 | 131,855 | 124,460 | 370,588 | |||||||
Taxes Other Than Income | 157,360 | 80,319 | 126,810 | 364,489 | |||||||
Interest Expense, Net | 44,690 | 54,213 | 53,242 | 152,145 | |||||||
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) | 982,760 | 760,228 | 827,032 | 2,570,020 | |||||||
Depreciation, Depletion and Amortization (DD&A) | 1,000,060 | 706,679 | 823,050 | 2,529,789 | |||||||
Total Operating Cost (excluding Total Exploration Costs) - (d) | 1,982,820 | 1,466,907 | 1,650,082 | 5,099,809 | |||||||
Exploration Costs | 39,677 | 27,283 | 38,413 | 105,373 | |||||||
Dry Hole Costs | 372 | 87 | 12,604 | 13,063 | |||||||
Impairments | 1,572,935 | 305,415 | 78,990 | 1,957,340 | |||||||
Total Exploration Costs | 1,612,984 | 332,785 | 130,007 | 2,075,776 | |||||||
Less: Certain Impairments (Non-GAAP) | (1,516,316) | (239,167) | (26,531) | (1,782,014) | |||||||
Total Exploration Costs (Non-GAAP) | 96,668 | 93,618 | 103,476 | 293,762 | |||||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 2,079,488 | 1,560,525 | 1,753,558 | 5,393,571 | |||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 30.62 | 14.99 | 26.77 | 24.98 | |||||||
Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a) | 12.36 | 13.40 | 12.56 | 12.70 | |||||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration | 18.26 | 1.59 | 14.21 | 12.28 | |||||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) | 24.93 | 25.86 | 25.05 | 25.21 | |||||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / | 5.69 | (10.87) | 1.72 | (0.23) | |||||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - | 26.15 | 27.51 | 26.62 | 26.66 | |||||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration | 4.47 | (12.52) | 0.15 | (1.68) |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | ||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 298,565 | 262,516 | 222,251 | |||||
Crude Oil and Condensate | 9,612,532 | 9,517,440 | 6,256,396 | |||||
Natural Gas Liquids | 784,818 | 1,127,510 | 729,561 | |||||
Natural Gas | 1,184,095 | 1,301,537 | 921,934 | |||||
Total Wellhead Revenues - (b) | 11,581,445 | 11,946,487 | 7,907,891 | |||||
Operating Costs | ||||||||
Lease and Well | 1,366,993 | 1,282,678 | 1,044,847 | |||||
Transportation Costs | 758,300 | 746,876 | 740,352 | |||||
Gathering and Processing Costs | 479,102 | 436,973 | 148,775 | |||||
General and Administrative | 489,397 | 426,969 | 434,467 | |||||
Less: Legal Settlement - Early Leasehold Termination | — | — | (10,202) | |||||
Less: Joint Venture Transaction Costs | — | — | (3,056) | |||||
Less: Joint Interest Billings Deemed Uncollectible | — | — | (4,528) | |||||
General and Administrative (Non-GAAP) | 489,397 | 426,969 | 416,681 | |||||
Taxes Other Than Income | 800,164 | 772,481 | 544,662 | |||||
Interest Expense, Net | 185,129 | 245,052 | 274,372 | |||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | 4,079,085 | 3,911,029 | 3,169,689 | |||||
Depreciation, Depletion and Amortization (DD&A) | 3,749,704 | 3,435,408 | 3,409,387 | |||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | 7,828,789 | 7,346,437 | 6,579,076 | |||||
Exploration Costs | 139,881 | 148,999 | 145,342 | |||||
Dry Hole Costs | 28,001 | 5,405 | 4,609 | |||||
Impairments | 517,896 | 347,021 | 479,240 | |||||
Total Exploration Costs | 685,778 | 501,425 | 629,191 | |||||
Less: Certain Impairments (Non-GAAP) | (274,974) | (152,671) | (261,452) | |||||
Total Exploration Costs (Non-GAAP) | 410,804 | 348,754 | 367,739 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 8,239,593 | 7,695,191 | 6,946,815 |
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 38.79 | 45.51 | 35.58 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | 13.66 | 14.90 | 14.25 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration | 25.13 | 30.61 | 21.33 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - | 26.22 | 27.99 | 29.59 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - | 12.57 | 17.52 | 5.99 | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - | 27.60 | 29.32 | 31.24 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | 11.19 | 16.19 | 4.34 |
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||||||||||||||||||||
2016 | 2015 | 2014 | ||||||||||||||||||||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | ||||||||||||||||||||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 204,929 | 208,862 | 217,073 | |||||||||||||||||||||||
Crude Oil and Condensate | 4,317,341 | 4,934,562 | 9,742,480 | |||||||||||||||||||||||
Natural Gas Liquids | 437,250 | 407,658 | 934,051 | |||||||||||||||||||||||
Natural Gas | 742,152 | 1,061,038 | 1,916,386 | |||||||||||||||||||||||
Total Wellhead Revenues - (b) | 5,496,743 | 6,403,258 | 12,592,917 | |||||||||||||||||||||||
Operating Costs | ||||||||||||||||||||||||||
Lease and Well | 927,452 | 1,182,282 | 1,416,413 | |||||||||||||||||||||||
Transportation Costs | 764,106 | 849,319 | 972,176 | |||||||||||||||||||||||
Gathering and Processing Costs | 122,901 | 146,156 | 145,800 | |||||||||||||||||||||||
General and Administrative | 394,815 | 366,594 | 402,010 | |||||||||||||||||||||||
Less: Voluntary Retirement Expense | (42,054) | — | — | |||||||||||||||||||||||
Less: Acquisition Costs | (5,100) | — | — | |||||||||||||||||||||||
Less: Legal Settlement - Early Leasehold Termination | — | (19,355) | — | |||||||||||||||||||||||
General and Administrative (Non-GAAP) | 347,661 | 347,239 | 402,010 | |||||||||||||||||||||||
Taxes Other Than Income | 349,710 | 421,744 | 757,564 | |||||||||||||||||||||||
Interest Expense, Net | 281,681 | 237,393 | 201,458 | |||||||||||||||||||||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | 2,793,511 | 3,184,133 | 3,895,421 | |||||||||||||||||||||||
Depreciation, Depletion and Amortization (DD&A) | 3,553,417 | 3,313,644 | 3,997,041 | |||||||||||||||||||||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | 6,346,928 | 6,497,777 | 7,892,462 | |||||||||||||||||||||||
Exploration Costs | 124,953 | 149,494 | 184,388 | |||||||||||||||||||||||
Dry Hole Costs | 10,657 | 14,746 | 48,490 | |||||||||||||||||||||||
Impairments | 620,267 | 6,613,546 | 743,575 | |||||||||||||||||||||||
Total Exploration Costs | 755,877 | 6,777,786 | 976,453 | |||||||||||||||||||||||
Less: Certain Impairments (Non-GAAP) | (320,617) | (6,307,593) | (824,312) | |||||||||||||||||||||||
Total Exploration Costs (Non-GAAP) | 435,260 | 470,193 | 152,141 | |||||||||||||||||||||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 6,782,188 | 6,967,970 | 8,044,603 | |||||||||||||||||||||||
Cost per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2016 | 2015 | 2014 | ||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 26.82 | 30.66 | 58.01 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration | 13.64 | 15.25 | 17.95 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration | 13.18 | 15.41 | 40.06 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - | 30.98 | 31.11 | 36.38 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - | (4.16) | (0.45) | 21.63 | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - | 33.10 | 33.36 | 37.08 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - | (6.28) | (2.70) | 20.93 |
Quarter and Full Year Guidance
(Unaudited) | |||||||||||||||
(a) Fourth Quarter and Full Year 2020 Forecast | |||||||||||||||
The forecast items for the fourth quarter and full year 2020 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||||||
(b) Capital Expenditures | |||||||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions. | |||||||||||||||
(c) Benchmark Commodity Pricing | |||||||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||||||
Estimated Ranges for Fourth Quarter and Full Year 2020 | 4Q 2020 | FY 2020 | |||||||||||||
Daily Sales Volumes | |||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||
United States | 435.0 | - | 445.0 | 406.3 | - | 408.8 | |||||||||
Trinidad | 1.6 | - | 2.0 | 0.8 | - | 0.9 | |||||||||
Other International | 0.0 | - | 0.2 | 0.1 | - | 0.1 | |||||||||
Total | 436.6 | - | 447.2 | 407.2 | - | 409.8 | |||||||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||||||
Total | 140.0 | - | 150.0 | 137.2 | - | 139.7 | |||||||||
Natural Gas Volumes (MMcfd) | |||||||||||||||
United States | 1,040 | - | 1,100 | 1,032 | - | 1,047 | |||||||||
Trinidad | 170 | - | 190 | 174 | - | 179 | |||||||||
Other International | 20 | - | 30 | 30 | - | 33 | |||||||||
Total | 1,230 | - | 1,320 | 1,236 | - | 1,259 | |||||||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||
United States | 748.3 | - | 778.3 | 715.4 | - | 722.9 | |||||||||
Trinidad | 29.9 | - | 33.7 | 29.8 | - | 30.8 | |||||||||
Other International | 3.3 | - | 5.2 | 5.1 | - | 5.6 | |||||||||
Total | 781.5 | - | 817.2 | 750.3 | - | 759.3 | |||||||||
Capital Expenditures ($MM) | 830 | - | 930 | 3,400 | 3,600 |
Quarter and Full Year Guidance
(Unaudited) | |||||||||||||||||||
Estimated Ranges for Fourth Quarter and Full Year 2020 | 4Q 2020 | FY 2020 | |||||||||||||||||
Operating Costs | |||||||||||||||||||
Unit Costs ($/Boe) | |||||||||||||||||||
Lease and Well | 3.80 | - | 4.30 | 3.92 | - | 4.05 | |||||||||||||
Transportation Costs | 2.55 | - | 2.95 | 2.64 | - | 2.74 | |||||||||||||
Gathering and Processing | 1.75 | - | 1.85 | 1.70 | - | 1.72 | |||||||||||||
Depreciation, Depletion and Amortization | 12.20 | - | 12.70 | 12.41 | - | 12.54 | |||||||||||||
General and Administrative | 1.80 | - | 1.90 | 1.82 | - | 1.85 | |||||||||||||
Expenses ($MM) | |||||||||||||||||||
Exploration and Dry Hole | 45 | - | 55 | 163 | - | 173 | |||||||||||||
Impairment | 100 | - | 150 | 265 | - | 315 | |||||||||||||
Capitalized Interest | 5 | - | 10 | 29 | - | 34 | |||||||||||||
Net Interest | 51 | - | 56 | 203 | - | 208 | |||||||||||||
Taxes Other Than Income (% of Wellhead Revenue) | 6.0 | % | - | 8.0 | % | 6.7 | % | - | 7.8 | % | |||||||||
Income Taxes | |||||||||||||||||||
Effective Rate | 20 | % | - | 25 | % | 16 | % | - | 21 | % | |||||||||
Current Tax (Benefit) / Expense ($MM) | 10 | - | 50 | (85) | - | (45) | |||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) WTI | (1.85) | - | 0.15 | (1.07) | - | (0.52) | |||||||||||||
Trinidad - above (below) WTI | (14.40) | - | (12.40) | (12.52) | - | (11.40) | |||||||||||||
Other International - above (below) WTI | (8.00) | - | (2.00) | 2.18 | - | 3.68 | |||||||||||||
Natural Gas Liquids | |||||||||||||||||||
Realizations as % of WTI | 34 | % | - | 46 | % | 32 | % | - | 35 | % | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) NYMEX Henry Hub | (0.60) | - | (0.20) | (0.54) | - | (0.43) | |||||||||||||
Realizations | |||||||||||||||||||
Trinidad | 3.15 | - | 3.65 | 2.44 | - | 2.59 | |||||||||||||
Other International | 4.35 | - | 4.85 | 4.44 | - | 4.54 |
Definitions
$/Bbl | U.S. Dollars per barrel | ||||||||||||
$/Boe | U.S. Dollars per barrel of oil equivalent | ||||||||||||
$/Mcf | U.S. Dollars per thousand cubic feet | ||||||||||||
$MM | U.S. Dollars in millions | ||||||||||||
MBbld | Thousand barrels per day | ||||||||||||
MBoed | Thousand barrels of oil equivalent per day | ||||||||||||
MMcfd | Million cubic feet per day | ||||||||||||
NYMEX | U.S. New York Mercantile Exchange | ||||||||||||
WTI | West Texas Intermediate |
View original content to download multimedia:http://www.prnewswire.com/news-releases/eog-resources-reports-third-quarter-2020-results-adds-premium-natural-gas-play-in-south-texas-provides-three-year-outlook-301167529.html
SOURCE EOG Resources, Inc.
HOUSTON, Oct. 28, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the BofA Securities Global Energy Conference at 8:00 a.m. Central time (9:00 a.m. Eastern time) on Wednesday, November 11. Ezra Y. Yacob, Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the Bernstein Operational Decisions Conference at 10:00 a.m. Central time (11:00 a.m. Eastern time) on Tuesday, November 17. Lloyd W. "Billy" Helms, Jr., Chief Operating Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcasts. If you are unable to listen live, a replay will be available for one year.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conferences-301162213.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 29, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) today published its 2019 Sustainability Report, highlighting the company's innovative leadership in sustainability and demonstrating its commitment to environmental stewardship, social engagement and corporate governance. The report can be found at www.eogresources.com/sustainability.
"EOG is a resilient company with a commitment to being an innovative leader in sustainability," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We have a history of successfully adapting to changing industry conditions. As we respond to the historic oil price collapse caused by the COVID-19 pandemic, we believe we will demonstrate once again just how resilient, innovative and committed to sustainability we are.
"What drives our confidence is the EOG culture – it is our number one competitive advantage. The expanded commitments and disclosures announced today demonstrate our resolve to drive continuous improvement in environmental, social and governance performance. I'm excited to see how EOG's culture of innovation and technology will keep delivering creative solutions to responsibly provide reliable, affordable energy to a growing global population."
Highlights of the 2019 Sustainability Report Include:
For more information about these metrics and other performance data, please consult our 2019 Sustainability Report at www.eogresources.com/sustainability.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-publishes-2019-sustainability-report-301140366.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 23, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) today announced the appointment of Michael T. Kerr to its Board of Directors, effective October 5, 2020.
Kerr has over 36 years of investment experience, including 35 years with Capital Group, home of American Funds®, and one of the world's oldest and largest investment management organizations. During his tenure with Capital Group, Kerr has managed multiple funds as an equity portfolio manager after covering global oil and gas companies and U.S. utilities as an analyst earlier in his career. Kerr will be retiring from Capital Group, effective October 1, 2020. Prior to joining Capital Group, Kerr was an exploration geophysicist with Cities Service Company.
"We are excited to add someone with Mike's extensive portfolio management experience to the EOG Board of Directors," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Mike will provide a unique perspective and add valuable insight drawing upon years of experience as an investor in both the oil and gas industry and the broader market. We are pleased to welcome Mike to the EOG team."
Dividend
The Board of Directors declared a dividend of $0.375 per share on EOG's Common Stock, payable October 30, 2020, to stockholders of record as of October 16, 2020. The indicated annual rate is $1.50.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-appoints-michael-t-kerr-to-board-of-directors-declares-quarterly-dividend-on-common-stock-301136966.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 22, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss third quarter 2020 results on Friday, November 6, 2020, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-third-quarter-2020-results-for-november-6-2020-301136092.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 2, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the Barclays CEO Energy-Power Conference at 8:45 a.m. Central time (9:45 a.m. Eastern time) on Wednesday, September 9. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available for one year.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conference-301123355.html
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 6, 2020 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported a second quarter 2020 net loss of $909 million, or $1.57 per share, compared with second quarter 2019 net income of $848 million, or $1.46 per share.
Adjusted non-GAAP net loss for the second quarter 2020 was $131 million, or $0.23 per share, compared with adjusted non-GAAP net income of $762 million, or $1.31 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Second Quarter 2020 Review
Earnings in the second quarter 2020 were lower than the same prior year period due to lower commodity prices and production volumes, partially offset by reduced operating costs. EOG adjusted quickly to the decline in commodity prices – a result of COVID-19's impact on demand – by slowing drilling activity and lowering both capital expenditures and operating costs. EOG also deferred production by delaying initial production from most new wells and shutting in production from lower-margin, existing wells across multiple basins. Deferring production volumes into higher-priced time periods is a return-based decision designed to maximize net present value.
As a result of EOG's actions to address the rapid change in market conditions, total company crude oil volumes were 331,100 barrels of oil per day (Bopd), 27 percent below the second quarter 2019. Natural gas liquids production was 23 percent lower and natural gas volumes were 15 percent lower, contributing to 23 percent lower total company daily production.
Net crude oil volumes associated with the shut-in of existing wells peaked at approximately 107,000 Bopd in May, with an average of approximately 73,000 Bopd shut in during the second quarter. The company estimates that approximately 25,000 Bopd will remain shut-in on average during the third quarter 2020. EOG began to return shut-in volumes to production in June, and expects nearly all shut-in wells to begin production before the end of the third quarter. EOG also deferred initial production from most new wells until late June, with ten net new wells contributing less than 1,000 Bopd of production in the second quarter. EOG continues to closely monitor market conditions and retains flexibility to adjust its plans in response to changes in commodity prices.
Lease and well, transportation, and gathering and processing costs each declined in the second quarter compared with the prior year period. Lease and well costs were the largest contributor to the overall cost reduction and were down eight percent on a per-unit basis. Sustainable efficiency improvements and service cost reductions contributed to the savings. These factors also contributed to an improved well cost reduction target of 12 percent for 2020, an increase from the forecast at the start of the year of eight percent.
During the second quarter, EOG received net cash from settlements of financial commodity derivative contracts of $639 million. The company also elected to sell a portion of its crude oil production in May and June under fixed-price agreements to further limit its exposure to commodity price volatility. This contributed to lower average crude oil prices compared with the prior year period and reduced revenues from gathering, processing and marketing relative to marketing costs.
Net cash provided by operating activities was $88 million. Changes in working capital and other assets and liabilities generated a net cash outflow of $1.0 billion in the second quarter 2020 and a net cash inflow of $0.2 billion in the first six months of 2020. Excluding changes in working capital and certain other items, EOG generated $672 million of discretionary cash flow in the second quarter 2020. The company incurred total expenditures of $534 million, including $478 million of capital expenditures before acquisitions, non–cash transactions and asset retirement costs, resulting in $194 million of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG generated positive free cash flow in the second quarter, made possible by our ability to quickly reduce activity and cut operating costs in all of our operating areas in response to historically low oil prices," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "This is a testament to EOG's unique culture and the flexibility provided by a decentralized organizational structure. In addition, our focus on safety, innovation, technical advancements and continuous improvement has not wavered. Our talented employees quickly and safely adapted to these volatile conditions, and I want to thank them for their dedication and commitment to EOG.
"Going forward, we will remain flexible and ready to respond to changes in market conditions with the goal of maximizing long-term shareholder value. Our priorities are unchanged: generate high returns on any capital invested and generate free cash flow to fund the dividend and protect our strong balance sheet. The sustainable improvements we are making across the company will support improved capital efficiency in the future, enabling EOG to maintain production at lower oil prices. We are confident EOG will emerge from the downturn an even better company."
Trinidad Exploration Success
EOG announced significant discoveries from its drilling campaign in Trinidad that have estimated gross resource potential of up to 1.0 trillion cubic feet of natural gas, or 500 billion cubic feet, net to EOG. The discoveries are based on results from four wells drilled in the past year located on three different blocks in shallow water off the southeast coast of Trinidad. The discoveries will support the installation of two new production platforms and development programs for the next three to five years. EOG plans to drill two additional wells over the remainder of 2020. Additional resource potential could be confirmed through further evaluation of the discovery wells and subsequent development. The exploration success supports EOG's long-term strategy in Trinidad of generating high returns and strong free cash flow through low-cost operations and targeted exploration.
Financial Review
EOG retains exceptional financial flexibility, with strong investment-grade credit ratings, low leverage ratios and ample liquidity. At June 30, 2020, total debt outstanding was $5.7 billion for a debt-to-total capitalization ratio of 22 percent. Considering $2.4 billion of cash on the balance sheet at the end of the second quarter, EOG's net debt was $3.3 billion for a net debt-to-total capitalization ratio of 14 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of June 30, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
On April 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 that matured on that date. In addition, on April 14, 2020, EOG closed its offering of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050. EOG received aggregate net proceeds from the sale, after deducting underwriting discounts and offering expenses, of approximately $1.48 billion. On June 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 4.40% Senior Notes due 2020 that matured on that date.
During the second quarter, EOG entered into offsetting contracts to lock-in the value of outstanding crude oil NYMEX WTI price swap contracts and other financial commodity derivative contracts effective from June through December 2020. As of June 30, EOG expects to receive net cash payments of $360 million from the settlement of these contracts over the remainder of 2020.
Second Quarter 2020 Results Webcast
Friday, August 7, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
Category: Earnings
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
Income Statements
In thousands of USD, except per share data (Unaudited) | |||||||||||
2Q 2020 | 2Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | 614,627 | 2,528,866 | 2,680,125 | 4,729,269 | |||||||
Natural Gas Liquids | 93,909 | 186,374 | 254,444 | 405,012 | |||||||
Natural Gas | 141,696 | 269,892 | 351,460 | 604,864 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative | (126,362) | 177,300 | 1,079,411 | 156,720 | |||||||
Gathering, Processing and Marketing | 362,786 | 1,501,386 | 1,401,432 | 2,787,040 | |||||||
Gains on Asset Dispositions, Net | 13,233 | 8,009 | 29,693 | 4,173 | |||||||
Other, Net | 3,485 | 25,803 | 24,501 | 69,194 | |||||||
Total | 1,103,374 | 4,697,630 | 5,821,066 | 8,756,272 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 245,346 | 347,281 | 575,005 | 683,572 | |||||||
Transportation Costs | 151,728 | 174,101 | 360,024 | 350,623 | |||||||
Gathering and Processing Costs | 96,767 | 112,643 | 225,249 | 223,938 | |||||||
Exploration Costs | 27,283 | 32,522 | 66,960 | 68,846 | |||||||
Dry Hole Costs | 87 | 3,769 | 459 | 3,863 | |||||||
Impairments | 305,415 | 112,130 | 1,878,350 | 184,486 | |||||||
Marketing Costs | 444,444 | 1,500,915 | 1,553,437 | 2,770,972 | |||||||
Depreciation, Depletion and Amortization | 706,679 | 957,304 | 1,706,739 | 1,836,899 | |||||||
General and Administrative | 131,855 | 121,780 | 246,128 | 228,452 | |||||||
Taxes Other Than Income | 80,319 | 204,414 | 237,679 | 397,320 | |||||||
Total | 2,189,923 | 3,566,859 | 6,850,030 | 6,748,971 | |||||||
Operating Income (Loss) | (1,086,549) | 1,130,771 | (1,028,964) | 2,007,301 | |||||||
Other Income (Expense), Net | (4,500) | 8,503 | 13,608 | 14,115 | |||||||
Income (Loss) Before Interest Expense and Income Taxes | (1,091,049) | 1,139,274 | (1,015,356) | 2,021,416 | |||||||
Interest Expense, Net | 54,213 | 49,908 | 98,903 | 104,814 | |||||||
Income (Loss) Before Income Taxes | (1,145,262) | 1,089,366 | (1,114,259) | 1,916,602 | |||||||
Income Tax Provision (Benefit) | (235,878) | 241,525 | (214,688) | 433,335 | |||||||
Net Income (Loss) | (909,384) | 847,841 | (899,571) | 1,483,267 | |||||||
Dividends Declared per Common Share | 0.3750 | 0.2875 | 0.7500 | 0.5075 | |||||||
Net Income (Loss) Per Share | |||||||||||
Basic | (1.57) | 1.47 | (1.55) | 2.57 | |||||||
Diluted | (1.57) | 1.46 | (1.55) | 2.56 | |||||||
Average Number of Common Shares | |||||||||||
Basic | 578,719 | 577,460 | 578,581 | 577,333 | |||||||
Diluted | 578,719 | 580,247 | 578,581 | 580,204 |
Wellhead Volumes and Prices
(Unaudited) | |||||||||||||||||
2Q 2020 | 2Q 2019 | % Change | YTD 2020 | YTD 2019 | % Change | ||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||||
United States | 330.9 | 454.9 | -27 | % | 406.8 | 445.1 | -9 | % | |||||||||
Trinidad | 0.1 | 0.6 | -83 | % | 0.3 | 0.7 | -57 | % | |||||||||
Other International (B) | 0.1 | 0.2 | -50 | % | 0.1 | — | |||||||||||
Total | 331.1 | 455.7 | -27 | % | 407.2 | 445.8 | -9 | % | |||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||||
United States | 20.40 | 61.01 | -67 | % | 36.17 | 58.63 | -38 | % | |||||||||
Trinidad | 0.60 | 49.56 | -99 | % | 27.75 | 46.62 | -40 | % | |||||||||
Other International (B) | 48.78 | 55.07 | -11 | % | 53.41 | 57.78 | -8 | % | |||||||||
Composite | 20.40 | 60.99 | -67 | % | 36.16 | 58.61 | -38 | % | |||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||||
United States | 101.2 | 131.1 | -23 | % | 131.2 | 125.4 | 5 | % | |||||||||
Other International (B) | — | — | — | — | |||||||||||||
Total | 101.2 | 131.1 | -23 | % | 131.2 | 125.4 | 5 | % | |||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||||
United States | 10.20 | 15.63 | -35 | % | 10.65 | 17.84 | -40 | % | |||||||||
Other International (B) | — | — | — | — | |||||||||||||
Composite | 10.20 | 15.63 | -35 | % | 10.65 | 17.84 | -40 | % | |||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||||
United States | 939 | 1,047 | -10 | % | 1,039 | 1,025 | 1 | % | |||||||||
Trinidad | 174 | 273 | -36 | % | 188 | 270 | -30 | % | |||||||||
Other International (B) | 34 | 36 | -6 | % | 35 | 37 | -5 | % | |||||||||
Total | 1,147 | 1,356 | -15 | % | 1,262 | 1,332 | -5 | % | |||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||||
United States | 1.11 | 1.98 | -44 | % | 1.32 | 2.37 | -44 | % | |||||||||
Trinidad | 2.13 | 2.69 | -21 | % | 2.15 | 2.80 | -23 | % | |||||||||
Other International (B) | 4.36 | 4.25 | 2 | % | 4.34 | 4.31 | 1 | % | |||||||||
Composite | 1.36 | 2.19 | -38 | % | 1.53 | 2.51 | -39 | % | |||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||||
United States | 588.5 | 760.4 | -23 | % | 711.1 | 741.3 | -4 | % | |||||||||
Trinidad | 29.2 | 46.1 | -37 | % | 31.6 | 45.6 | -31 | % | |||||||||
Other International (B) | 5.7 | 6.3 | -10 | % | 6.1 | 6.4 | -5 | % | |||||||||
Total | 623.4 | 812.8 | -23 | % | 748.8 | 793.3 | -6 | % | |||||||||
Total MMBoe (D) | 56.7 | 74.0 | -23 | % | 136.3 | 143.6 | -5 | % | |||||||||
(A) | Thousand barrels per day or million cubic feet per day, as applicable. |
(B) | Other International includes EOG's China and Canada operations. |
(C) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2020). |
(D) | Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
Balance Sheets
In thousands of USD, except per share data (Unaudited) | |||||
June 30, | December 31, | ||||
2020 | 2019 | ||||
Current Assets | |||||
Cash and Cash Equivalents | 2,416,501 | 2,027,972 | |||
Accounts Receivable, Net | 943,354 | 2,001,658 | |||
Inventories | 676,580 | 767,297 | |||
Assets from Price Risk Management Activities | 207,019 | 1,299 | |||
Income Taxes Receivable | 196,958 | 151,665 | |||
Other | 156,979 | 323,448 | |||
Total | 4,597,391 | 5,273,339 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 64,406,245 | 62,830,415 | |||
Other Property, Plant and Equipment | 4,665,815 | 4,472,246 | |||
Total Property, Plant and Equipment | 69,072,060 | 67,302,661 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (39,838,595) | (36,938,066) | |||
Total Property, Plant and Equipment, Net | 29,233,465 | 30,364,595 | |||
Deferred Income Taxes | 1,846 | 2,363 | |||
Other Assets | 1,388,969 | 1,484,311 | |||
Total Assets | 35,221,671 | 37,124,608 | |||
Current Liabilities | |||||
Accounts Payable | 1,281,166 | 2,429,127 | |||
Accrued Taxes Payable | 193,763 | 254,850 | |||
Dividends Payable | 217,004 | 166,273 | |||
Liabilities from Price Risk Management Activities | — | 20,194 | |||
Current Portion of Long-Term Debt | 21,121 | 1,014,524 | |||
Current Portion of Operating Lease Liabilities | 252,642 | 369,365 | |||
Other | 188,685 | 232,655 | |||
Total | 2,154,381 | 4,486,988 | |||
Long-Term Debt | 5,703,141 | 4,160,919 | |||
Other Liabilities | 2,138,696 | 1,789,884 | |||
Deferred Income Taxes | 4,837,896 | 5,046,101 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,386,649 | 205,824 | 205,822 | |||
Additional Paid in Capital | 5,886,298 | 5,817,475 | |||
Accumulated Other Comprehensive Loss | (6,130) | (4,652) | |||
Retained Earnings | 14,312,493 | 15,648,604 | |||
Common Stock Held in Treasury, 142,025 Shares at June 30, 2020 and 298,820 | (10,928) | (26,533) | |||
Total Stockholders' Equity | 20,387,557 | 21,640,716 | |||
Total Liabilities and Stockholders' Equity | 35,221,671 | 37,124,608 |
Cash Flows Statements
In thousands of USD (Unaudited) | |||||||||||
2Q 2020 | 2Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Cash Flows from Operating Activities | |||||||||||
Reconciliation of Net Income (Loss) to Net Cash Provided by | |||||||||||
Net Income (Loss) | (909,384) | 847,841 | (899,571) | 1,483,267 | |||||||
Items Not Requiring (Providing) Cash | |||||||||||
Depreciation, Depletion and Amortization | 706,679 | 957,304 | 1,706,739 | 1,836,899 | |||||||
Impairments | 305,415 | 112,130 | 1,878,350 | 184,486 | |||||||
Stock-Based Compensation Expenses | 39,571 | 38,566 | 79,643 | 77,653 | |||||||
Deferred Income Taxes | (252,466) | 217,970 | (207,692) | 324,294 | |||||||
Gains on Asset Dispositions, Net | (13,233) | (8,009) | (29,693) | (4,173) | |||||||
Other, Net | 8,986 | 2,487 | 171 | 5,439 | |||||||
Dry Hole Costs | 87 | 3,769 | 459 | 3,863 | |||||||
Mark-to-Market Commodity Derivative Contracts | |||||||||||
Total (Gains) Losses | 126,362 | (177,300) | (1,079,411) | (156,720) | |||||||
Net Cash Received from Settlements of Commodity | 639,388 | 10,444 | 723,761 | 31,290 | |||||||
Other, Net | (365) | 663 | (720) | 1,639 | |||||||
Changes in Components of Working Capital and Other Assets and | |||||||||||
Accounts Receivable | 469,294 | 239,250 | 1,191,457 | (69,746) | |||||||
Inventories | (18,095) | 7,720 | 84,575 | (11,259) | |||||||
Accounts Payable | (1,618,276) | (67,229) | (1,184,718) | 126,853 | |||||||
Accrued Taxes Payable | (6,482) | (61,718) | (61,087) | 53,280 | |||||||
Other Assets | 194,682 | 494,322 | 252,978 | 487,387 | |||||||
Other Liabilities | 1,675 | (4,014) | (64,403) | (58,106) | |||||||
Changes in Components of Working Capital Associated with | 414,236 | 72,347 | 282,154 | (22,034) | |||||||
Net Cash Provided by Operating Activities | 88,074 | 2,686,543 | 2,672,992 | 4,294,312 | |||||||
Investing Cash Flows | |||||||||||
Additions to Oil and Gas Properties | (423,982) | (1,507,024) | (1,990,033) | (3,446,497) | |||||||
Additions to Other Property, Plant and Equipment | (24,591) | (55,918) | (147,366) | (116,881) | |||||||
Proceeds from Sales of Assets | 17,567 | 2,593 | 43,368 | 17,642 | |||||||
Changes in Components of Working Capital Associated with | (414,236) | (72,325) | (282,154) | 22,056 | |||||||
Net Cash Used in Investing Activities | (845,242) | (1,632,674) | (2,376,185) | (3,523,680) | |||||||
Financing Cash Flows | |||||||||||
Long-Term Debt Borrowings | 1,483,852 | — | 1,483,852 | — | |||||||
Long-Term Debt Repayments | (1,000,000) | (900,000) | (1,000,000) | (900,000) | |||||||
Dividends Paid | (217,042) | (127,135) | (384,100) | (254,681) | |||||||
Treasury Stock Purchased | (402) | (2,155) | (5,057) | (8,403) | |||||||
Proceeds from Stock Options Exercised and Employee Stock | 8,548 | 8,292 | 8,614 | 8,695 | |||||||
Debt Issuance Costs | (2,635) | (4,902) | (2,635) | (4,902) | |||||||
Repayment of Finance Lease Liabilities | (4,824) | (3,213) | (8,445) | (6,403) | |||||||
Changes in Components of Working Capital Associated with | — | (22) | — | (22) | |||||||
Net Cash Provided by (Used in) Financing Activities | 267,497 | (1,029,135) | 92,229 | (1,165,716) | |||||||
Effect of Exchange Rate Changes on Cash | (680) | (59) | (507) | (65) | |||||||
Increase (Decrease) in Cash and Cash Equivalents | (490,351) | 24,675 | 388,529 | (395,149) | |||||||
Cash and Cash Equivalents at Beginning of Period | 2,906,852 | 1,135,810 | 2,027,972 | 1,555,634 | |||||||
Cash and Cash Equivalents at End of Period | 2,416,501 | 1,160,485 | 2,416,501 | 1,160,485 |
Non-GAAP Financial Measures
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Discretionary Cash Flow, Free Cash Flow, Adjusted EBITDAX, Net Debt and related statistics. |
A reconciliation of each of these measures to their most directly comparable GAAP financial measure is included in the tables below and can also be found in the "Reconciliations & Guidance" section of the "Investors" page of the EOG website at www.eogresources.com. |
EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance. |
EOG believes that the non-GAAP measures presented, when viewed in combination with its financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial and operating performance with the financial and operating performance of other companies in the industry and (ii) analyzing EOG's financial and operating performance across periods. |
The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Total Debt, Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. |
In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) | |||||||||||
2Q 2020 | |||||||||||
Before Tax | Income Tax Impact | After Tax | Diluted Earnings | ||||||||
Reported Net Loss (GAAP) | (1,145,262) | 235,878 | (909,384) | (1.57) | |||||||
Adjustments: | |||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | 126,362 | (27,734) | 98,628 | 0.17 | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 639,388 | (140,333) | 499,055 | 0.86 | |||||||
Less: Gains on Asset Dispositions, Net | (13,233) | 2,930 | (10,303) | (0.02) | |||||||
Add: Certain Impairments | 239,167 | (48,351) | 190,816 | 0.33 | |||||||
Adjustments to Net Loss | 991,684 | (213,488) | 778,196 | 1.34 | |||||||
Adjusted Net Loss (Non-GAAP) | (153,578) | 22,390 | (131,188) | (0.23) | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 578,719 | ||||||||||
Diluted | 578,719 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 578,719 | ||||||||||
Diluted | 578,719 | ||||||||||
2Q 2019 | |||||||||||
Before Tax | Income Tax | After Tax | Diluted Earnings | ||||||||
Reported Net Income (GAAP) | 1,089,366 | (241,525) | 847,841 | 1.46 | |||||||
Adjustments: | |||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | (177,300) | 38,930 | (138,370) | (0.24) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 10,444 | (2,276) | 8,168 | 0.01 | |||||||
Less: Gains on Asset Dispositions, Net | (8,009) | 1,734 | (6,275) | (0.01) | |||||||
Add: Certain Impairments | 65,289 | (14,311) | 50,978 | 0.09 | |||||||
Adjustments to Net Income | (109,576) | 24,077 | (85,499) | (0.15) | |||||||
Adjusted Net Income (Non-GAAP) | 979,790 | (217,448) | 762,342 | 1.31 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 577,460 | ||||||||||
Diluted | 580,247 | ||||||||||
Average Number of Common Shares (Non-GAAP) | 577,460 | ||||||||||
Basic | 580,247 | ||||||||||
Diluted |
Adjusted Net Income (Loss)
In thousands of USD, except per share data (Unaudited) | |||||||||||
YTD 2020 | |||||||||||
Before Tax | Income Tax Impact | After Tax | Diluted Earnings per Share | ||||||||
Reported Net Loss (GAAP) | (1,114,259) | 214,688 | (899,571) | (1.55) | |||||||
Adjustments: | |||||||||||
Gains Mark-to-Market Commodity Derivative Contracts | (1,079,411) | 236,909 | (842,502) | (1.47) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 723,761 | (158,851) | 564,910 | 0.98 | |||||||
Less: Gains on Asset Dispositions, Net | (29,693) | 6,543 | (23,150) | (0.04) | |||||||
Add: Certain Impairments | 1,755,483 | (368,324) | 1,387,159 | 2.40 | |||||||
Adjustments to Net Loss | 1,370,140 | (283,723) | 1,086,417 | 1.87 | |||||||
Adjusted Net Income (Non-GAAP) | 255,881 | (69,035) | 186,846 | 0.32 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 578,581 | ||||||||||
Diluted | 578,581 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 578,581 | ||||||||||
Diluted | 580,179 | ||||||||||
YTD 2019 | |||||||||||
Before Tax | Income Tax Impact | After Tax | Diluted Earnings per Share | ||||||||
Reported Net Income (GAAP) | 1,916,602 | (433,335) | 1,483,267 | 2.56 | |||||||
Adjustments: | |||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts | (156,720) | 34,397 | (122,323) | (0.21) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 31,290 | (6,868) | 24,422 | 0.04 | |||||||
Less: Gains on Asset Dispositions, Net | (4,173) | 998 | (3,175) | (0.01) | |||||||
Add: Certain Impairments | 89,034 | (19,541) | 69,493 | 0.12 | |||||||
Adjustments to Net Income | (40,569) | 8,986 | (31,583) | (0.06) | |||||||
Adjusted Net Income (Non-GAAP) | 1,876,033 | (424,349) | 1,451,684 | 2.50 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||
Basic | 577,333 | ||||||||||
Diluted | 580,204 | ||||||||||
Average Number of Common Shares (Non-GAAP) | |||||||||||
Basic | 577,333 | ||||||||||
Diluted | 580,204 |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | |||||||||||||||||
2Q 2020 | 2Q 2019 | YTD 2020 | YTD 2019 | ||||||||||||||
Net Cash Provided by Operating Activities (GAAP) | 88,074 | 2,686,543 | 2,672,992 | 4,294,312 | |||||||||||||
Adjustments: | |||||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 20,484 | 26,089 | 52,966 | 55,876 | |||||||||||||
Other Non-Current Income Taxes - Net Receivable | — | 42,764 | 112,704 | 145,682 | |||||||||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||||||||
Accounts Receivable | (469,294) | (239,250) | (1,191,457) | 69,746 | |||||||||||||
Inventories | 18,095 | (7,720) | (84,575) | 11,259 | |||||||||||||
Accounts Payable | 1,618,276 | 67,229 | 1,184,718 | (126,853) | |||||||||||||
Accrued Taxes Payable | 6,482 | 61,718 | 61,087 | (53,280) | |||||||||||||
Other Assets | (194,682) | (494,322) | (252,978) | (487,387) | |||||||||||||
Other Liabilities | (1,675) | 4,014 | 64,403 | 58,106 | |||||||||||||
Changes in Components of Working Capital Associated with Investing and | (414,236) | (72,347) | (282,154) | 22,034 | |||||||||||||
Discretionary Cash Flow (Non-GAAP) | 671,524 | 2,074,718 | 2,337,706 | 3,989,495 | |||||||||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -68 | % | -41 | % | |||||||||||||
Discretionary Cash Flow (Non-GAAP) | 671,524 | 2,074,718 | 2,337,706 | 3,989,495 | |||||||||||||
Less: | |||||||||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (477,616) | (1,595,726) | (2,162,336) | (3,328,202) | |||||||||||||
Free Cash Flow (Non-GAAP) (b) | 193,908 | 478,992 | 175,370 | 661,293 | |||||||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month and six-month periods ended June 30, 2020 and 2019: | |||||||||||||||||
Total Expenditures (GAAP) | 534,411 | 1,663,127 | 2,360,189 | 3,765,046 | |||||||||||||
Less: | |||||||||||||||||
Asset Retirement Costs | (5,955) | (55,425) | (25,563) | (60,581) | |||||||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (60) | (586) | (60) | (586) | |||||||||||||
Non-Cash Acquisition Costs of Unproved Properties | (23,243) | (10,240) | (47,731) | (53,721) | |||||||||||||
Non-Cash Finance Leases | (24,319) | — | (73,277) | — | |||||||||||||
Acquisition Costs of Proved Properties | (3,218) | (1,150) | (51,222) | (321,956) | |||||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 477,616 | 1,595,726 | 2,162,336 | 3,328,202 | |||||||||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the three-month and six-month periods ending June 30, 2020. The comparative prior periods shown have been revised to conform to this presentation. | |||||||||||||||||
Maintenance Capital Expenditures | |||||||||||||||||
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to anticipated 4Q 2020 U.S. oil production. |
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | |||||||||||||||||
FY 2019 | FY 2018 | FY 2017 | |||||||||||||||
Net Cash Provided by Operating Activities (GAAP) | 8,163,180 | 7,768,608 | 4,265,336 | ||||||||||||||
Adjustments: | |||||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 113,733 | 123,986 | 122,688 | ||||||||||||||
Other Non-Current Income Taxes - Net (Payable) Receivable | 238,711 | 148,993 | (513,404) | ||||||||||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||||||||
Accounts Receivable | 91,792 | 368,180 | 392,131 | ||||||||||||||
Inventories | (90,284) | 395,408 | 174,548 | ||||||||||||||
Accounts Payable | (168,539) | (439,347) | (324,192) | ||||||||||||||
Accrued Taxes Payable | (40,122) | 92,461 | 63,937 | ||||||||||||||
Other Assets | (358,001) | 125,435 | 658,609 | ||||||||||||||
Other Liabilities | 56,619 | (10,949) | 89,871 | ||||||||||||||
Changes in Components of Working Capital Associated with Investing and | 115,061 | (301,083) | (89,992) | ||||||||||||||
Discretionary Cash Flow (Non-GAAP) | 8,122,150 | 8,271,692 | 4,839,532 | ||||||||||||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase (Decrease) | -2 | % | 71 | % | |||||||||||||
Discretionary Cash Flow (Non-GAAP) | 8,122,150 | 8,271,692 | 4,839,532 | ||||||||||||||
Less: | |||||||||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (6,234,454) | (6,172,950) | (4,228,859) | ||||||||||||||
Free Cash Flow (Non-GAAP) (b) | 1,887,696 | 2,098,742 | 610,673 | ||||||||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017: | |||||||||||||||||
Total Expenditures (GAAP) | 6,900,450 | 6,706,359 | 4,612,746 | ||||||||||||||
Less: | |||||||||||||||||
Asset Retirement Costs | (186,088) | (69,699) | (55,592) | ||||||||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (2,266) | (49,484) | — | ||||||||||||||
Non-Cash Acquisition Costs of Unproved Properties | (97,704) | (290,542) | (255,711) | ||||||||||||||
Acquisition Costs of Proved Properties | (379,938) | (123,684) | (72,584) | ||||||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 6,234,454 | 6,172,950 | 4,228,859 | ||||||||||||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow excludes dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. The comparative prior periods shown have been revised to conform to this presentation. | |||||||||||||||||
Discretionary Cash Flow and Free Cash Flow
In thousands of USD (Unaudited) | ||||||||
FY 2014 | FY 2013 | FY 2012 | ||||||
Net Cash Provided by Operating Activities (GAAP) | 8,649,155 | 7,329,414 | 5,236,777 | |||||
Adjustments: | ||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 157,453 | 134,531 | 159,182 | |||||
Excess Tax Benefits from Stock-Based Compensation | 99,459 | 55,831 | 67,035 | |||||
Changes in Components of Working Capital and Other Assets and Liabilities | ||||||||
Accounts Receivable | (84,982) | 23,613 | 178,683 | |||||
Inventories | 161,958 | (53,402) | 156,762 | |||||
Accounts Payable | (543,630) | (178,701) | 17,150 | |||||
Accrued Taxes Payable | (16,486) | (75,142) | (78,094) | |||||
Other Assets | 14,448 | 109,567 | 118,520 | |||||
Other Liabilities | (75,420) | 20,382 | (36,114) | |||||
Changes in Components of Working Capital Associated with Investing and | 103,414 | 51,361 | (74,158) | |||||
Discretionary Cash Flow (Non-GAAP) | 8,465,369 | 7,417,454 | 5,745,743 | |||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 14 | % | 29 | % | ||||
Discretionary Cash Flow (Non-GAAP) | 8,465,369 | 7,417,454 | 5,745,743 | |||||
Less: | ||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) (a) | (8,292,090) | (7,101,791) | (7,539,994) | |||||
Free Cash Flow (Non-GAAP) (b) | 173,279 | 315,663 | (1,794,251) | |||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2014, 2013 and 2012: | ||||||||
Total Expenditures (GAAP) | 8,631,906 | 7,361,457 | 7,753,828 | |||||
Less: | ||||||||
Asset Retirement Costs | (195,630) | (134,445) | (126,987) | |||||
Non-Cash Expenditures of Other Property, Plant and Equipment | — | — | (65,791) | |||||
Non-Cash Acquisition Costs of Unproved Properties | (5,085) | (5,007) | (20,317) | |||||
Acquisition Costs of Proved Properties | (139,101) | (120,214) | (739) | |||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | 8,292,090 | 7,101,791 | 7,539,994 | |||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, the presentation of free cash flow for the comparative prior periods shown has been revised to exclude dividends paid (GAAP) as a reconciling item. |
Total Expenditures
In millions of USD (Unaudited) | ||||||||||||||
2Q 2020 | 2Q 2019 | FY 2019 | FY 2018 | FY 2017 | ||||||||||
Exploration and Development Drilling | 381 | 1,290 | 4,951 | 4,935 | 3,132 | |||||||||
Facilities | 31 | 174 | 629 | 625 | 575 | |||||||||
Leasehold Acquisitions | 30 | 38 | 276 | 488 | 427 | |||||||||
Property Acquisitions | 3 | 1 | 380 | 124 | 73 | |||||||||
Capitalized Interest | 8 | 11 | 38 | 24 | 27 | |||||||||
Subtotal | 453 | 1,514 | 6,274 | 6,196 | 4,234 | |||||||||
Exploration Costs | 27 | 33 | 140 | 149 | 145 | |||||||||
Dry Hole Costs | — | 4 | 28 | 5 | 5 | |||||||||
Exploration and Development Expenditures | 480 | 1,551 | 6,442 | 6,350 | 4,384 | |||||||||
Asset Retirement Costs | 5 | 56 | 186 | 70 | 56 | |||||||||
Total Exploration and Development Expenditures | 485 | 1,607 | 6,628 | 6,420 | 4,440 | |||||||||
Other Property, Plant and Equipment | 49 | 56 | 272 | 286 | 173 | |||||||||
Total Expenditures | 534 | 1,663 | 6,900 | 6,706 | 4,613 |
EBITDAX and Adjusted EBITDAX
In thousands of USD (Unaudited) | |||||||||||
2Q 2020 | 2Q 2019 | YTD 2020 | YTD 2019 | ||||||||
Net Income (Loss) (GAAP) | (909,384) | 847,841 | (899,571) | 1,483,267 | |||||||
Adjustments: | |||||||||||
Interest Expense, Net | 54,213 | 49,908 | 98,903 | 104,814 | |||||||
Income Tax Provision (Benefit) | (235,878) | 241,525 | (214,688) | 433,335 | |||||||
Depreciation, Depletion and Amortization | 706,679 | 957,304 | 1,706,739 | 1,836,899 | |||||||
Exploration Costs | 27,283 | 32,522 | 66,960 | 68,846 | |||||||
Dry Hole Costs | 87 | 3,769 | 459 | 3,863 | |||||||
Impairments | 305,415 | 112,130 | 1,878,350 | 184,486 | |||||||
EBITDAX (Non-GAAP) | (51,585) | 2,244,999 | 2,637,152 | 4,115,510 | |||||||
(Gains) Losses on MTM Commodity Derivative Contracts | 126,362 | (177,300) | (1,079,411) | (156,720) | |||||||
Net Cash Received from Settlements of Commodity Derivative Contracts | 639,388 | 10,444 | 723,761 | 31,290 | |||||||
Less: Gains on Asset Dispositions, Net | (13,233) | (8,009) | (29,693) | (4,173) | |||||||
Adjusted EBITDAX (Non-GAAP) | 700,932 | 2,070,134 | 2,251,809 | 3,985,907 | |||||||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -66 | % | -44 | % | |||||||
Definitions | |||||||||||
EBITDAX - Earnings Before Interest Expense; Income Taxes; Depreciation, Depletion and Amortization; Exploration Costs; Dry Hole Costs; and Impairments |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||||||||
June 30, | March 31, | December 31, | September 30, | June 30, | March 31, | ||||||||||||
Total Stockholders' Equity - (a) | 20,388 | 21,471 | 21,641 | 21,124 | 20,630 | 19,904 | |||||||||||
Current and Long-Term Debt (GAAP) - (b) | 5,724 | 5,222 | 5,175 | 5,177 | 5,179 | 6,081 | |||||||||||
Less: Cash | (2,417) | (2,907) | (2,028) | (1,583) | (1,160) | (1,136) | |||||||||||
Net Debt (Non-GAAP) - (c) | 3,307 | 2,315 | 3,147 | 3,594 | 4,019 | 4,945 | |||||||||||
Total Capitalization (GAAP) - (a) + (b) | 26,112 | 26,693 | 26,816 | 26,301 | 25,809 | 25,985 | |||||||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 23,695 | 23,786 | 24,788 | 24,718 | 24,649 | 24,849 | |||||||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 22 | % | 20 | % | 19 | % | 20 | % | 20 | % | 23 | % | |||||
Net Debt-to-Total Capitalization (Non- | 14 | % | 10 | % | 13 | % | 15 | % | 16 | % | 20 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||
December 31, 2018 | September 30, 2018 | June 30, 2018 | March 31, 2018 | ||||||||
Total Stockholders' Equity - (a) | 19,364 | 18,538 | 17,452 | 16,841 | |||||||
Current and Long-Term Debt (GAAP) - (b) | 6,083 | 6,435 | 6,435 | 6,435 | |||||||
Less: Cash | (1,556) | (1,274) | (1,008) | (816) | |||||||
Net Debt (Non-GAAP) - (c) | 4,527 | 5,161 | 5,427 | 5,619 | |||||||
Total Capitalization (GAAP) - (a) + (b) | 25,447 | 24,973 | 23,887 | 23,276 | |||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 23,891 | 23,699 | 22,879 | 22,460 | |||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 24 | % | 26 | % | 27 | % | 28 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 19 | % | 22 | % | 24 | % | 25 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | |||||||||||
December 31, 2017 | September 30, 2017 | June 30, 2017 | March 31, 2017 | ||||||||
Total Stockholders' Equity - (a) | 16,283 | 13,922 | 13,902 | 13,928 | |||||||
Current and Long-Term Debt (GAAP) - (b) | 6,387 | 6,387 | 6,987 | 6,987 | |||||||
Less: Cash | (834) | (846) | (1,649) | (1,547) | |||||||
Net Debt (Non-GAAP) - (c) | 5,553 | 5,541 | 5,338 | 5,440 | |||||||
Total Capitalization (GAAP) - (a) + (b) | 22,670 | 20,309 | 20,889 | 20,915 | |||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 21,836 | 19,463 | 19,240 | 19,368 | |||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 28 | % | 31 | % | 33 | % | 33 | % | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 25 | % | 28 | % | 28 | % | 28 | % |
Net Debt-to-Total Capitalization Ratio
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
December 31, | September 30, 2016 | June 30, 2016 | March 31, 2016 | December 31, 2015 | ||||||||||
Total Stockholders' Equity - (a) | 13,982 | 11,798 | 12,057 | 12,405 | 12,943 | |||||||||
Current and Long-Term Debt (GAAP) - (b) | 6,986 | 6,986 | 6,986 | 6,986 | 6,660 | |||||||||
Less: Cash | (1,600) | (1,049) | (780) | (668) | (719) | |||||||||
Net Debt (Non-GAAP) - (c) | 5,386 | 5,937 | 6,206 | 6,318 | 5,941 | |||||||||
Total Capitalization (GAAP) - (a) + (b) | 20,968 | 18,784 | 19,043 | 19,391 | 19,603 | |||||||||
Total Capitalization (Non-GAAP) - (a) + (c) | 19,368 | 17,735 | 18,263 | 18,723 | 18,884 | |||||||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + | 33 | % | 37 | % | 37 | % | 36 | % | 34 | % | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 28 | % | 33 | % | 34 | % | 34 | % | 31 | % |
Reserve Replacement Cost Data
In millions of USD, except reserves and ratio data (Unaudited) | |||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | 6,628.2 | 6,419.7 | 4,439.4 | 6,445.2 | 4,928.3 | 7,904.8 | |||||||||||||||||||||||
Less: Asset Retirement Costs | (186.1) | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | |||||||||||||||||||||||
Non-Cash Acquisition Costs of Unproved | (97.7) | (290.5) | (255.7) | (3,101.8) | — | — | |||||||||||||||||||||||
Acquisition Costs of Proved Properties | (379.9) | (123.7) | (72.6) | (749.0) | (480.6) | (139.1) | |||||||||||||||||||||||
Total Exploration and Development Expenditures for | 5,964.5 | 5,935.8 | 4,055.5 | 2,614.3 | 4,394.2 | 7,570.1 | |||||||||||||||||||||||
Total Costs Incurred in Exploration and Development | 6,628.2 | 6,419.7 | 4,439.4 | 6,445.2 | 4,928.3 | 7,904.8 | |||||||||||||||||||||||
Less: Asset Retirement Costs | (186.1) | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | |||||||||||||||||||||||
Non-Cash Acquisition Costs of Unproved | (97.7) | (290.5) | (255.7) | (3,101.8) | — | — | |||||||||||||||||||||||
Non-Cash Acquisition Costs of Proved Properties | (52.3) | (70.9) | (26.2) | (732.3) | — | — | |||||||||||||||||||||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) | 6,292.1 | 5,988.6 | 4,101.9 | 2,631.0 | 4,874.8 | 7,709.2 | |||||||||||||||||||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||||||||||||||||||||||||
Revisions Due to Price - (c) | (59.7) | 34.8 | 154.0 | (100.7) | (573.8) | 52.2 | |||||||||||||||||||||||
Revisions Other Than Price | (0.3) | (39.5) | 48.0 | 252.9 | 107.2 | 48.4 | |||||||||||||||||||||||
Purchases in Place | 16.8 | 11.6 | 2.3 | 42.3 | 56.2 | 14.4 | |||||||||||||||||||||||
Extensions, Discoveries and Other Additions - (d) | 750.0 | 669.7 | 420.8 | 209.0 | 245.9 | 519.2 | |||||||||||||||||||||||
Total Proved Reserve Additions - (e) | 706.8 | 676.6 | 625.1 | 403.5 | (164.5) | 634.2 | |||||||||||||||||||||||
Sales in Place | (4.6) | (10.8) | (20.7) | (167.6) | (3.5) | (36.3) | |||||||||||||||||||||||
Net Proved Reserve Additions From All Sources | 702.2 | 665.8 | 604.4 | 235.9 | (168.0) | 597.9 | |||||||||||||||||||||||
Production | 300.9 | 265.0 | 224.4 | 207.1 | 211.2 | 219.1 | |||||||||||||||||||||||
Reserve Replacement Costs ($ / Boe) | |||||||||||||||||||||||||||||
Total Drilling, Before Revisions - (a / d) | 7.95 | 8.86 | 9.64 | 12.51 | 17.87 | 14.58 | |||||||||||||||||||||||
All-in Total, Net of Revisions - (b / e) | 8.90 | 8.85 | 6.56 | 6.52 | (29.63) | 12.16 | |||||||||||||||||||||||
All-in Total, Excluding Revisions Due to Price - | 8.21 | 9.33 | 8.71 | 5.22 | 11.91 | 13.25 |
Definitions
$/Boe | U.S. Dollars per barrel of oil equivalent | ||||||||||||||||||||||||||||
MMBoe | Million barrels of oil equivalent |
Financial Commodity Derivative Contracts
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | ||||||
ICE Brent Differential Basis Swap Contracts | ||||||
Prices received by EOG for its crude oil production generally vary from NYMEX WTI prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between ICE Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through July 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||||
2020 | Volume (Bbld) | Weighted Average Price Differential | ||||
($/Bbl) | ||||||
May 2020 (CLOSED) | 10,000 | 4.92 | ||||
Houston Differential Basis Swap Contracts | ||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through July 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||||
2020 | Volume (Bbld) | Weighted Average Price | ||||
Differential | ||||||
($/Bbl) | ||||||
May 2020 (CLOSED) | 10,000 | 1.55 | ||||
Roll Differential Swap Contracts | ||||||
EOG has also entered into crude oil swaps in order to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through July 30, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. | ||||||
2020 | Volume (Bbld) | Weighted Average Price | ||||
Differential | ||||||
($/Bbl) | ||||||
February 1, 2020 through June 30, 2020 (CLOSED) | 10,000 | 0.7 | ||||
July 1, 2020 through August 31, 2020 (CLOSED) | 88,000 | (1.16) | ||||
Sep-20 | 88,000 | (1.16) | ||||
October 1, 2020 through December 31, 2020 | 66,000 | (1.16) | ||||
In May 2020, EOG entered into crude oil Roll Differential swap contracts for the period from July 1, 2020 through September 30, 2020, with notional volumes of 22,000 Bbld at a weighted average price differential of $(0.43) per Bbl, and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 44,000 Bbld at a weighted average price differential of $(0.73) per Bbl. These contracts partially offset certain outstanding Roll Differential swap contracts for the same time periods and volumes at a weighted average price differential of $(1.16) per Bbl. EOG expects to pay net cash of $3.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | ||||||
Crude Oil NYMEX WTI Price Swap Contracts | ||||||
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through July 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||||
2020 | Volume (Bbld) | Weighted | ||||
Average Price | ||||||
($/Bbl) | ||||||
January 1, 2020 through March 31, 2020 (CLOSED) | 200,000 | 59.33 | ||||
April 1, 2020 through May 31, 2020 (CLOSED) | 265,000 | 51.36 | ||||
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from June 1, 2020 through June 30, 2020, with notional volumes of 265,000 Bbld at a weighted average price of $33.80 per Bbl, for the period from July 1, 2020 through July 31, 2020, with notional volumes of 254,000 Bbld at a weighted average price of $33.75 per Bbl, for the period from August 1, 2020 through September 30, 2020, with notional volumes of 154,000 Bbld at a weighted average price of $34.18 per Bbl and for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining NYMEX WTI price swap contracts for the same time periods and volumes at a weighted average price of $51.36 per Bbl for the period from June 1, 2020 through June 30, 2020, $42.36 per Bbl for the period from July 1, 2020 through July 31, 2020, $50.42 per Bbl for the period from August 1, 2020 through September 30, 2020 and $31.00 per Bbl for the period from October 1, 2020 through December 31, 2020. EOG expects to receive net cash of $364.0 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | ||||||
Crude Oil ICE Brent Price Swap Contracts | ||||||
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through July 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||||
2020 | Volume (Bbld) | Weighted | ||||
Average Price | ||||||
($/Bbl) | ||||||
April 2020 (CLOSED) | 75,000 | 25.66 | ||||
May 2020 (CLOSED) | 35,000 | 26.53 | ||||
Mont Belvieu Propane Price Swap Contracts | ||||||
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through July 30, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||||
2020 | Volume (Bbld) | Weighted | ||||
Average Price | ||||||
($/Bbl) | ||||||
January 1, 2020 through February 29, 2020 (CLOSED) | 4,000 | 21.34 | ||||
March 1, 2020 through April 30, 2020 (CLOSED) | 25,000 | 17.92 | ||||
In April and May 2020, EOG entered into Mont Belvieu propane price swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 25,000 Bbld at a weighted average price of $16.41 per Bbl. These contracts offset the remaining Mont Belvieu propane price swap contracts for the same time period with notional volumes of 25,000 Bbld at a weighted average price of $17.92 per Bbl. EOG expects to receive net cash of $9.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | ||||||
Natural Gas Price Swap Contracts | ||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through July 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||||
2021 | Volume (MMBtud) | Weighted | ||||
Average Price | ||||||
($/MMBtu) | ||||||
January 1, 2021 through December 31, 2021 | 50,000 | 2.75 |
Natural Gas Collar Contracts | |||||||||
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period from April 1, 2020 through July 31, 2020. The net cash EOG received for settling these contracts was $7.8 million. Presented below is a comprehensive summary of EOG's natural gas collar contracts through July 30, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||
2020 | Volume (MMBtud) | Weighted Average Ceiling Price ($/MMBtu) | Weighted Average | ||||||
Floor Price | |||||||||
($/MMBtu) | |||||||||
April 1, 2020 through July 31, 2020 (CLOSED) | 250,000 | 2.5 | 2 | ||||||
In April 2020, EOG entered into natural gas collar contracts for the period from August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG expects to receive net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
Rockies Differential Basis Swap Contracts | ||||||
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through July 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | ||||||
2020 | Volume | Weighted Average Price Differential | ||||
(MMBtud) | ($/MMBtu) | |||||
January 1, 2020 through July 31, 2020 (CLOSED) | 30,000 | 0.55 | ||||
August 1, 2020 through December 31, 2020 | 30,000 | 0.55 | ||||
HSC Differential Basis Swap Contracts | ||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). In March 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period from April 1, 2020 through December 31, 2020. The net cash EOG paid for settling these contracts was $0.4 million. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through July 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | ||||||
2020 | Volume (MMBtud) | Weighted Average Price Differential | ||||
($/MMBtu) | ||||||
January 1, 2020 through December 31, 2020 (CLOSED) | 60,000 | 0.05 | ||||
Waha Differential Basis Swap Contracts | ||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through July 30, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | ||||||
2020 | Volume | Weighted Average Price Differential | ||||
(MMBtud) | ($/MMBtu) | |||||
January 1, 2020 through April 30, 2020 (CLOSED) | 50,000 | 1.4 | ||||
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 per MMBtu. EOG expects to pay net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. |
Definitions
Bbld | Barrels per day | ||
$/Bbl | Dollars per barrel | ||
ICE | Intercontinental Exchange | ||
MMBtud | Million British thermal units per day | ||
$/MMBtu | Dollars per million British thermal units | ||
NYMEX | U.S. New York Mercantile Exchange | ||
WTI | West Texas Intermediate |
Direct After-Tax Rate of Return
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. | |
Direct ATROR | |
Based on Cash Flow and Time Value of Money | |
- Estimated future commodity prices and operating costs | |
- Costs incurred to drill, complete and equip a well, including facilities | |
Excludes Indirect Capital | |
- Gathering and Processing and other Midstream | |
- Land, Seismic, Geological and Geophysical | |
Payback ~12 Months on 100% Direct ATROR Wells | |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured | |
Return on Equity / Return on Capital Employed | |
Based on GAAP Accrual Accounting | |
Includes All Indirect Capital and Growth Capital for Infrastructure | |
- Eagle Ford, Bakken, Permian Facilities | |
- Gathering and Processing | |
Includes Legacy Gas Capital and Capital from Mature Wells |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Net Interest Expense (GAAP) | 185 | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (39) | (51) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 146 | 194 | ||||||
Net Income (GAAP) - (b) | 2,735 | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Below Detail) (1) | 158 | (201) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | 2,893 | 3,218 | ||||||
Total Stockholders' Equity - (d) | 21,641 | 19,364 | 16,283 | |||||
Average Total Stockholders' Equity * - (e) | 20,503 | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | 5,175 | 6,083 | 6,387 | |||||
Less: Cash | (2,028) | (1,556) | (834) | |||||
Net Debt (Non-GAAP) - (g) | 3,147 | 4,527 | 5,553 | |||||
Total Capitalization (GAAP) - (d) + (f) | 26,816 | 25,447 | 22,670 | |||||
Total Capitalization (Non-GAAP) - (d) + (g) | 24,788 | 23,891 | 21,836 | |||||
Average Total Capitalization (Non-GAAP) * - (h) | 24,340 | 22,864 | ||||||
Return on Capital Employed (ROCE) | ||||||||
GAAP Net Income - [(a) + (b)] / (h) | 11.8 | % | 15.8 | % | ||||
Non-GAAP Adjusted Net Income - [(a) + (c)] / (h) | 12.5 | % | 14.9 | % | ||||
Return on Equity (ROE) | ||||||||
GAAP Net Income - (b) / (e) | 13.3 | % | 19.2 | % | ||||
Non-GAAP Adjusted Net Income - (c) / (e) | 14.1 | % | 18.1 | % | ||||
* Average for the current and immediately preceding year | ||||||||
(1) Detail of adjustments to Net Income (GAAP): | ||||||||
Before | Income Tax | After | ||||||
Year Ended December 31, 2019 | ||||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | 51 | (11) | 40 | |||||
Add: Impairments of Certain Assets | 275 | (60) | 215 | |||||
Less: Net Gains on Asset Dispositions | (124) | 27 | (97) | |||||
Total | 202 | (44) | 158 | |||||
Year Ended December 31, 2018 | ||||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | (93) | 20 | (73) | |||||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | — | (110) | (110) | |||||
Total | (115) | (86) | (201) |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||
Net Interest Expense (GAAP) | 274 | 282 | 237 | 201 | 235 | |||||||||
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 178 | 183 | 154 | 131 | 153 | |||||||||
Net Income (Loss) (GAAP) - (b) | 2,583 | (1,097) | (4,525) | 2,915 | 2,197 | |||||||||
Total Stockholders' Equity - (d) | 16,283 | 13,982 | 12,943 | 17,713 | 15,418 | |||||||||
Average Total Stockholders' Equity* - (e) | 15,133 | 13,463 | 15,328 | 16,566 | 14,352 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 6,387 | 6,986 | 6,655 | 5,906 | 5,909 | |||||||||
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||||||
Net Debt (Non-GAAP) - (g) | 5,553 | 5,386 | 5,936 | 3,819 | 4,591 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 22,670 | 20,968 | 19,598 | 23,619 | 21,327 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 21,836 | 19,368 | 18,879 | 21,532 | 20,009 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 20,602 | 19,124 | 20,206 | 20,771 | 19,365 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income (Loss) - [(a) + (b)] / (h) | 13.4 | % | -4.8 | % | -21.6 | % | 14.7 | % | 12.1 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income (Loss) - (b) / (e) | 17.1 | % | -8.1 | % | -29.5 | % | 17.6 | % | 15.3 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||
Net Interest Expense (GAAP) | 214 | 210 | 130 | 101 | 52 | |||||||||
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 139 | 136 | 84 | 66 | 34 | |||||||||
Net Income (GAAP) - (b) | 570 | 1,091 | 161 | 547 | 2,437 | |||||||||
Total Stockholders' Equity - (d) | 13,285 | 12,641 | 10,232 | 9,998 | 9,015 | |||||||||
Average Total Stockholders' Equity* - (e) | 12,963 | 11,437 | 10,115 | 9,507 | 8,003 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 6,312 | 5,009 | 5,223 | 2,797 | 1,897 | |||||||||
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||||||
Net Debt (Non-GAAP) - (g) | 5,436 | 4,393 | 4,434 | 2,111 | 1,566 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 19,597 | 17,650 | 15,455 | 12,795 | 10,912 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 18,721 | 17,034 | 14,666 | 12,109 | 10,581 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 17,878 | 15,850 | 13,388 | 11,345 | 9,351 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 4.0 | % | 7.7 | % | 1.8 | % | 5.4 | % | 26.4 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 4.4 | % | 9.5 | % | 1.6 | % | 5.8 | % | 30.5 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||
Net Interest Expense (GAAP) | 47 | 43 | 63 | 63 | 59 | |||||||||
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 31 | 28 | 41 | 41 | 38 | |||||||||
Net Income (GAAP) - (b) | 1,090 | 1,300 | 1,260 | 625 | 430 | |||||||||
Total Stockholders' Equity - (d) | 6,990 | 5,600 | 4,316 | 2,945 | 2,223 | |||||||||
Average Total Stockholders' Equity* - (e) | 6,295 | 4,958 | 3,631 | 2,584 | 1,948 | |||||||||
Current and Long-Term Debt (GAAP) - (f) | 1,185 | 733 | 985 | 1,078 | 1,109 | |||||||||
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||||||
Net Debt (Non-GAAP) - (g) | 1,131 | 515 | 341 | 1,057 | 1,105 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 8,175 | 6,333 | 5,301 | 4,023 | 3,332 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 8,121 | 6,115 | 4,657 | 4,002 | 3,328 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 7,118 | 5,386 | 4,330 | 3,665 | 3,068 | |||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 15.7 | % | 24.7 | % | 30.0 | % | 18.2 | % | 15.3 | % | ||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 17.3 | % | 26.2 | % | 34.7 | % | 24.2 | % | 22.1 | % | ||||
* Average for the current and immediately preceding year |
ROCE & ROE
In millions of USD, except ratio data (Unaudited) | ||||||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||
Net Interest Expense (GAAP) | 60 | 45 | 61 | 62 | ||||||||||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | 39 | 29 | 40 | 40 | ||||||||||
Net Income (GAAP) - (b) | 87 | 399 | 397 | 569 | ||||||||||
Total Stockholders' Equity - (d) | 1,672 | 1,643 | 1,381 | 1,130 | 1,280 | |||||||||
Average Total Stockholders' Equity* - (e) | 1,658 | 1,512 | 1,256 | 1,205 | ||||||||||
Current and Long-Term Debt (GAAP) - (f) | 1,145 | 856 | 859 | 990 | 1,143 | |||||||||
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||||||
Net Debt (Non-GAAP) - (g) | 1,135 | 853 | 839 | 965 | 1,137 | |||||||||
Total Capitalization (GAAP) - (d) + (f) | 2,817 | 2,499 | 2,240 | 2,120 | 2,423 | |||||||||
Total Capitalization (Non-GAAP) - (d) + (g) | 2,807 | 2,496 | 2,220 | 2,095 | 2,417 | |||||||||
Average Total Capitalization (Non-GAAP)* - (h) | 2,652 | 2,358 | 2,158 | 2,256 | ||||||||||
Return on Capital Employed (ROCE) | ||||||||||||||
GAAP Net Income - [(a) + (b)] / (h) | 4.8 | % | 18.2 | % | 20.2 | % | 27.0 | % | ||||||
Return on Equity (ROE) | ||||||||||||||
GAAP Net Income - (b) / (e) | 5.2 | % | 26.4 | % | 31.6 | % | 47.2 | % | ||||||
* Average for the current and immediately preceding year |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
1Q 2020 | 2Q 2020 | YTD 2020 | ||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | ||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 79,548 | 56,733 | 136,281 | |||||
Crude Oil and Condensate | 2,065,498 | 614,627 | 2,680,125 | |||||
Natural Gas Liquids | 160,535 | 93,909 | 254,444 | |||||
Natural Gas | 209,764 | 141,696 | 351,460 | |||||
Total Wellhead Revenues - (b) | 2,435,797 | 850,232 | 3,286,029 | |||||
Operating Costs | ||||||||
Lease and Well | 329,659 | 245,346 | 575,005 | |||||
Transportation Costs | 208,296 | 151,728 | 360,024 | |||||
Gathering and Processing Costs | 128,482 | 96,767 | 225,249 | |||||
General and Administrative | 114,273 | 131,855 | 246,128 | |||||
Taxes Other Than Income | 157,360 | 80,319 | 237,679 | |||||
Interest Expense, Net | 44,690 | 54,213 | 98,903 | |||||
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) | 982,760 | 760,228 | 1,742,988 | |||||
Depreciation, Depletion and Amortization (DD&A) | 1,000,060 | 706,679 | 1,706,739 | |||||
Total Operating Cost (excluding Total Exploration Costs) - (d) | 1,982,820 | 1,466,907 | 3,449,727 | |||||
Exploration Costs | 39,677 | 27,283 | 66,960 | |||||
Dry Hole Costs | 372 | 87 | 459 | |||||
Impairments | 1,572,935 | 305,415 | 1,878,350 | |||||
Total Exploration Costs | 1,612,984 | 332,785 | 1,945,769 | |||||
Less: Certain Impairments (Non-GAAP) | (1,516,316) | (239,167) | (1,755,483) | |||||
Total Exploration Costs (Non-GAAP) | 96,668 | 93,618 | 190,286 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 2,079,488 | 1,560,525 | 3,640,013 | |||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 30.62 | 14.99 | 24.11 | |||||
Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a) | 12.36 | 13.40 | 12.79 | |||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 18.26 | 1.59 | 11.32 | |||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) | 24.93 | 25.86 | 25.31 | |||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | 5.69 | (10.87) | (1.20) | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 26.15 | 27.51 | 26.71 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | 4.47 | (12.52) | (2.60) |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | ||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 298,565 | 262,516 | 222,251 | |||||
Crude Oil and Condensate | 9,612,532 | 9,517,440 | 6,256,396 | |||||
Natural Gas Liquids | 784,818 | 1,127,510 | 729,561 | |||||
Natural Gas | 1,184,095 | 1,301,537 | 921,934 | |||||
Total Wellhead Revenues - (b) | 11,581,445 | 11,946,487 | 7,907,891 | |||||
Operating Costs | ||||||||
Lease and Well | 1,366,993 | 1,282,678 | 1,044,847 | |||||
Transportation Costs | 758,300 | 746,876 | 740,352 | |||||
Gathering and Processing Costs | 479,102 | 436,973 | 148,775 | |||||
General and Administrative | 489,397 | 426,969 | 434,467 | |||||
Less: Legal Settlement - Early Leasehold Termination | — | — | (10,202) | |||||
Less: Joint Venture Transaction Costs | — | — | (3,056) | |||||
Less: Joint Interest Billings Deemed Uncollectible | — | — | (4,528) | |||||
General and Administrative (Non-GAAP) | 489,397 | 426,969 | 416,681 | |||||
Taxes Other Than Income | 800,164 | 772,481 | 544,662 | |||||
Interest Expense, Net | 185,129 | 245,052 | 274,372 | |||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | 4,079,085 | 3,911,029 | 3,169,689 | |||||
Depreciation, Depletion and Amortization (DD&A) | 3,749,704 | 3,435,408 | 3,409,387 | |||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | 7,828,789 | 7,346,437 | 6,579,076 | |||||
Exploration Costs | 139,881 | 148,999 | 145,342 | |||||
Dry Hole Costs | 28,001 | 5,405 | 4,609 | |||||
Impairments | 517,896 | 347,021 | 479,240 | |||||
Total Exploration Costs | 685,778 | 501,425 | 629,191 | |||||
Less: Certain Impairments (Non-GAAP) | (274,974) | (152,671) | (261,452) | |||||
Total Exploration Costs (Non-GAAP) | 410,804 | 348,754 | 367,739 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 8,239,593 | 7,695,191 | 6,946,815 | |||||
Cost per Barrel of Oil Equivalent | ||||||||
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2019 | 2018 | 2017 | ||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 38.79 | 45.51 | 35.58 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | 13.66 | 14.90 | 14.25 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 25.13 | 30.61 | 21.33 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - (d) / (a) | 26.22 | 27.99 | 29.59 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | 12.57 | 17.52 | 5.99 | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 27.60 | 29.32 | 31.24 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | 11.19 | 16.19 | 4.34 |
Costs per Barrel of Oil Equivalent
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2016 | 2015 | 2014 | ||||||
Cost per Barrel of Oil Equivalent (Boe) Calculation | ||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 204,929 | 208,862 | 217,073 | |||||
Crude Oil and Condensate | 4,317,341 | 4,934,562 | 9,742,480 | |||||
Natural Gas Liquids | 437,250 | 407,658 | 934,051 | |||||
Natural Gas | 742,152 | 1,061,038 | 1,916,386 | |||||
Total Wellhead Revenues - (b) | 5,496,743 | 6,403,258 | 12,592,917 | |||||
Operating Costs | ||||||||
Lease and Well | 927,452 | 1,182,282 | 1,416,413 | |||||
Transportation Costs | 764,106 | 849,319 | 972,176 | |||||
Gathering and Processing Costs | 122,901 | 146,156 | 145,800 | |||||
General and Administrative | 394,815 | 366,594 | 402,010 | |||||
Less: Voluntary Retirement Expense | (42,054) | — | — | |||||
Less: Acquisition Costs | (5,100) | — | — | |||||
Less: Legal Settlement - Early Leasehold Termination | — | (19,355) | — | |||||
General and Administrative (Non-GAAP) | 347,661 | 347,239 | 402,010 | |||||
Taxes Other Than Income | 349,710 | 421,744 | 757,564 | |||||
Interest Expense, Net | 281,681 | 237,393 | 201,458 | |||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | 2,793,511 | 3,184,133 | 3,895,421 | |||||
Depreciation, Depletion and Amortization (DD&A) | 3,553,417 | 3,313,644 | 3,997,041 | |||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | 6,346,928 | 6,497,777 | 7,892,462 | |||||
Exploration Costs | 124,953 | 149,494 | 184,388 | |||||
Dry Hole Costs | 10,657 | 14,746 | 48,490 | |||||
Impairments | 620,267 | 6,613,546 | 743,575 | |||||
Total Exploration Costs | 755,877 | 6,777,786 | 976,453 | |||||
Less: Certain Impairments (Non-GAAP) | (320,617) | (6,307,593) | (824,312) | |||||
Total Exploration Costs (Non-GAAP) | 435,260 | 470,193 | 152,141 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | 6,782,188 | 6,967,970 | 8,044,603 | |||||
Cost per Barrel of Oil Equivalent | ||||||||
In thousands of USD, except Boe and per Boe amounts (Unaudited) | ||||||||
2016 | 2015 | 2014 | ||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | 26.82 | 30.66 | 58.01 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | 13.64 | 15.25 | 17.95 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | 13.18 | 15.41 | 40.06 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - (d) / (a) | 30.98 | 31.11 | 36.38 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | (4.16) | (0.45) | 21.63 | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | 33.10 | 33.36 | 37.08 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | (6.28) | (2.70) | 20.93 |
Quarter and Full Year Guidance
(Unaudited) | |||||||||||||||||||
(a) Third Quarter and Full Year 2020 Forecast | |||||||||||||||||||
The forecast items for the third quarter and full year 2020 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||||||||||
(b) Capital Expenditures | |||||||||||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions. | |||||||||||||||||||
(c) Benchmark Commodity Pricing | |||||||||||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||||||||||
Estimated Ranges for Third Quarter and Full Year 2020 | 3Q 2020 | FY 2020 | |||||||||||||||||
Daily Sales Volumes | |||||||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||||||||||
United States | 363.0 | - | 373.0 | 402.0 | - | 408.0 | |||||||||||||
Trinidad | 0.6 | - | 1.0 | 0.6 | - | 1.0 | |||||||||||||
Other International | — | - | 0.2 | — | - | 0.2 | |||||||||||||
Total | 363.6 | - | 374.2 | 402.6 | - | 409.2 | |||||||||||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||||||||||
Total | 125.0 | - | 135.0 | 130.0 | - | 140.0 | |||||||||||||
Natural Gas Volumes (MMcfd) | |||||||||||||||||||
United States | 940 | - | 1,000 | 985 | - | 1,075 | |||||||||||||
Trinidad | 165 | - | 185 | 180 | - | 195 | |||||||||||||
Other International | 20 | - | 30 | 20 | - | 30 | |||||||||||||
Total | 1,125 | - | 1,215 | 1,185 | - | 1,300 | |||||||||||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||||||||||
United States | 644.7 | - | 674.7 | 696.2 | - | 727.2 | |||||||||||||
Trinidad | 28.1 | - | 31.8 | 30.6 | - | 33.5 | |||||||||||||
Other International | 3.3 | - | 5.2 | 3.3 | - | 5.2 | |||||||||||||
Total | 676.1 | - | 711.7 | 730.1 | - | 765.9 | |||||||||||||
Quarter and Full Year Guidance
(Unaudited) | |||||||||||||||||||
Estimated Ranges for Third Quarter and Full Year 2020 | 3Q 2020 | FY 2020 | |||||||||||||||||
Capital Expenditures ($MM) | 600 | - | 700 | 3,400 | - | 3,600 | |||||||||||||
Operating Costs | |||||||||||||||||||
Unit Costs ($/Boe) | |||||||||||||||||||
Lease and Well | 4.20 | - | 4.70 | 4.10 | - | 4.50 | |||||||||||||
Transportation Costs | 2.70 | - | 3.10 | 2.50 | - | 2.90 | |||||||||||||
Gathering and Processing | 1.70 | 1.90 | 1.65 | 1.85 | |||||||||||||||
Depreciation, Depletion and Amortization | 12.10 | 12.60 | 11.85 | 12.85 | |||||||||||||||
General and Administrative | 2.25 | - | 2.35 | 1.85 | - | 1.95 | |||||||||||||
Expenses ($MM) | |||||||||||||||||||
Exploration and Dry Hole | 35 | - | 45 | 130 | - | 170 | |||||||||||||
Impairment | 80 | 90 | 290 | 330 | |||||||||||||||
Capitalized Interest | 5 | - | 9 | 27 | - | 33 | |||||||||||||
Net Interest | 50 | - | 54 | 200 | - | 205 | |||||||||||||
Taxes Other Than Income (% of Wellhead Revenue) | 7.0 | % | - | 9.0 | % | 7.0 | % | - | 8.0 | % | |||||||||
Income Taxes | |||||||||||||||||||
Effective Rate | 15 | % | - | 20 | % | 16 | % | - | 21 | % | |||||||||
Current Tax (Benefit) / Expense ($MM) | (15) | - | 25 | (120) | - | (80) | |||||||||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) WTI | (2.30) | - | (0.30) | (2.05) | - | (0.05) | |||||||||||||
Trinidad - above (below) WTI | (11.00) | - | (9.00) | (9.50) | - | (7.50) | |||||||||||||
Other International - above (below) WTI | (18.75) | - | (12.75) | 2.00 | - | 7.00 | |||||||||||||
Natural Gas Liquids | |||||||||||||||||||
Realizations as % of WTI | 29 | % | - | 41 | % | 30 | % | - | 36 | % | |||||||||
Natural Gas ($/Mcf) | |||||||||||||||||||
Differentials | |||||||||||||||||||
United States - above (below) NYMEX Henry Hub | (0.70) | - | (0.30) | (0.80) | - | (0.20) | |||||||||||||
Realizations | |||||||||||||||||||
Trinidad | 2.10 | - | 2.70 | 2.30 | - | 3.00 | |||||||||||||
Other International | 4.00 | - | 4.50 | 3.85 | - | 4.85 |
Definitions
$/Bbl | U.S. Dollars per barrel | ||||||||||||
$/Boe | U.S. Dollars per barrel of oil equivalent | ||||||||||||
$/Mcf | U.S. Dollars per thousand cubic feet | ||||||||||||
$MM | U.S. Dollars in millions | ||||||||||||
MBbld | Thousand barrels per day | ||||||||||||
MBoed | Thousand barrels of oil equivalent per day | ||||||||||||
MMcfd | Million cubic feet per day | ||||||||||||
NYMEX | U.S. New York Mercantile Exchange | ||||||||||||
WTI | West Texas Intermediate |
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SOURCE EOG Resources, Inc.
HOUSTON, June 23, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss second quarter 2020 results on Friday, August 7, 2020, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-second-quarter-2020-results-for-august-7-2020-301082351.html
SOURCE EOG Resources, Inc.
HOUSTON, May 21, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the Bernstein Strategic Decisions Conference at 9:00 a.m. Central time (10:00 a.m. Eastern time) on Wednesday, May 27. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG.
EOG is also scheduled to present at the RBC Global Energy and Power Conference at 7:40 a.m. Central time (8:40 a.m. Eastern time) on Tuesday, June 2. Kenneth W. Boedeker, Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the J.P. Morgan Energy Conference taking place June 16-17. Please visit the Investors/Events & Presentations page on the EOG website for the date and time of the presentation. Lloyd W. "Billy" Helms, Jr., Chief Operating Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcasts. If you are unable to listen live, a replay will be available for six months.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
Source: EOG Resources, Inc.
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conferences-301063951.html
SOURCE EOG Resources, Inc.
HOUSTON, May 7, 2020 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported first quarter 2020 net income of $10 million, or $0.02 per share, compared with first quarter 2019 net income of $635 million, or $1.10 per share.
Adjusted non-GAAP net income for the first quarter 2020 was $318 million, or $0.55 per share, compared with adjusted non-GAAP net income of $689 million, or $1.19 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
First Quarter 2020 Review
EOG continued to deliver strong operational and financial performance in the first quarter 2020 while responding to rapidly changing market conditions. The company moved quickly to reduce activity and capital expenditures. EOG also elected to defer production by delaying the startup of new wells and shutting in production from existing wells.
Crude oil production volumes in the first quarter 2020 were in line with the target range while capital expenditures were 14 percent below the target midpoint. Total company crude oil volumes of 483,300 barrels of oil per day (Bopd) grew 11 percent compared with the first quarter 2019, despite electing to delay the startup of some new wells in the quarter and the shut-in of approximately 8,000 Bopd in March. Natural gas liquids production increased 35 percent, supported by the increased recovery of ethane in natural gas processing operations. Natural gas volumes grew five percent, contributing to total company daily production growth of 13 percent.
Cash operating expenses declined by eight percent on a per-unit basis during the first quarter 2020 compared with the same prior year period. Lower per-unit lease and well and general and administrative costs contributed to the overall cost reduction.
Net cash provided by operating activities for the first quarter 2020 was $2.6 billion. EOG generated $1.7 billion of discretionary cash flow in the first quarter 2020. The company incurred total expenditures of $1.8 billion, including $1.7 billion of capital expenditures before acquisitions, non‐cash transactions and asset retirement costs. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG is a resilient company. During the first quarter the company adjusted operations quickly to manage extreme commodity price volatility and the challenges from the COVID-19 pandemic," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "These unprecedented market conditions have super-charged our unique culture to vigorously lower costs and generate innovative productivity gains that will make EOG a much better company as we emerge from this downturn. Our years of continuous improvement, disciplined high-return investments, free cash flow generation and focus on strengthening our balance sheet have positioned the company for sustainable success through commodity price cycles."
Updated 2020 Capital Plan
EOG has further revised its full-year 2020 plan as a result of the significant decline and increased volatility of commodity prices. The goals of the plan are to generate high rates of return on capital investments, maintain EOG's strong financial position and support the dividend. The revised plan retains funding for projects that support the long-term value of the company, including targeted infrastructure, exploration and environmental projects.
Exploration and development expenditures for 2020 are now expected to range from $3.3 billion to $3.7 billion, including facilities and gathering, processing and other expenditures, and excluding acquisitions, non‐cash transactions and asset retirement costs. This represents a reduction of $1.0 billion from the previous updated plan that was announced on March 16 and a reduction of $3.0 billion, or 46 percent, from the original plan at the start of the year.
EOG has moved quickly to reduce its operating activity. The company lowered its operated rig count from 36 rigs to eight rigs during the last six weeks, with an average of approximately six rigs expected for the remainder of 2020. EOG has identified over 4,500 net drilling locations - more than nine years of inventory at the 2020 activity pace - that are capable of generating strong rates of return at less than $30 WTI oil. The company plans to focus its 2020 activity on these high-return wells.
Driven by its innovative culture and decentralized organization, EOG is accelerating cost reductions and sustainable efficiency improvements across its operations. Targeted well costs are forecast to decline an average of eight percent compared with 2019 levels, including reductions of nine percent and seven percent, respectively, in EOG's premier Delaware Basin and South Texas Eagle Ford operations.
EOG's revised capital plan targets full-year 2020 crude oil production of approximately 390,000 Bopd, representing a decline of 15 percent compared with full-year 2019 levels. EOG currently plans to bring approximately 485 net wells onto production for the full-year 2020 compared with the original forecast of 800 net wells, with a focus on the Delaware Basin and South Texas Eagle Ford.
In order to generate higher rates of return, the company has elected to defer some of its production until oil prices recover. This includes delaying the startup of approximately 150 net new wells until the second half of 2020 and the shut-in of existing production. The net production volume associated with the shut-in of existing wells was approximately 8,000 Bopd in March, 24,000 Bopd in April and is estimated to be 125,000 Bopd in May and 100,000 Bopd in June, with an average of 40,000 Bopd for the full-year 2020.
"Our guiding principles in this environment remain consistent with EOG's long-term strategy: to make returns-based decisions and spend within our means to protect our strong balance sheet. This is intended to preserve EOG's business value and position the company to thrive in an upturn," Thomas said.
"Over the last several years as we implemented our premium strategy, EOG significantly lowered its cost structure and strengthened its financial position, giving us a distinct advantage in the current environment. Our operational flexibility, favorable hedges and strong liquidity leave us well-positioned to respond to volatile market conditions. Since the end of the first quarter, we have further bolstered our liquidity by adjusting our hedge position and issuing new long-term debt to refinance bond maturities. Because we have acted decisively, we will be able to utilize these advantages as we navigate the downturn."
"During these challenging times, our first priority is the health and safety of our employees and their families, our contractors and our communities. We are also committed to sustaining our unique culture, EOG's most important asset. I am incredibly proud of our exceptional people, who have quickly adjusted to the new environment. Our employees are the foundation of the EOG culture. Thanks to their hard work and dedication, EOG is well-positioned to emerge even stronger in the recovery."
Dividend
The board of directors declared a dividend of $0.375 per share on EOG's Common Stock. The dividend will be payable July 31, 2020, to stockholders of record as of July 17, 2020. The indicated annual rate is $1.50 per share.
Financial Review
At March 31, 2020, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 20 percent. Considering $2.9 billion of cash on the balance sheet at the end of the first quarter, EOG's net debt was $2.3 billion for a net debt-to-total capitalization ratio of 10 percent. EOG's liquidity is further enhanced by $2.0 billion of availability under its senior unsecured revolving credit agreement as of March 31, 2020. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Subsequent to the end of the first quarter, on April 1, 2020, EOG repaid, with cash on hand, the $500 million aggregate principal amount of its 2.45% Senior Notes due 2020 that matured on that date. In addition, on April 14, 2020, EOG closed its sale of $750 million aggregate principal amount of its 4.375% Senior Notes due 2030 and $750 million aggregate principal amount of its 4.950% Senior Notes due 2050. EOG received aggregate net proceeds from the sale, after deducting underwriting discounts and estimated offering expenses, of approximately $1.48 billion.
First Quarter 2020 Results Webcast
Friday, May 8, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
Source: EOG Resources, Inc.
Category: Earnings
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||
Financial Report | |||||||
(Unaudited; in millions, except per share data) | |||||||
Three Months Ended |
|||||||
March 31, |
|||||||
2020 |
2019 |
||||||
Operating Revenues and Other |
$ |
4,717.7 |
$ |
4,058.6 |
|||
Net Income |
$ |
9.8 |
$ |
635.4 |
|||
Net Income Per Share |
|||||||
Basic |
$ |
0.02 |
$ |
1.10 |
|||
Diluted |
$ |
0.02 |
$ |
1.10 |
|||
Average Number of Common Shares |
|||||||
Basic |
578.5 |
577.2 |
|||||
Diluted |
580.3 |
580.2 |
|||||
Summary Income Statements | |||||||
(Unaudited; in thousands, except per share data) | |||||||
Three Months Ended |
|||||||
March 31, |
|||||||
2020 |
2019 |
||||||
Operating Revenues and Other |
|||||||
Crude Oil and Condensate |
$ |
2,065,498 |
$ |
2,200,403 |
|||
Natural Gas Liquids |
160,535 |
218,638 |
|||||
Natural Gas |
209,764 |
334,972 |
|||||
Gains (Losses) on Mark-to-Market Commodity |
1,205,773 |
(20,580) |
|||||
Gathering, Processing and Marketing |
1,038,646 |
1,285,654 |
|||||
Gains (Losses) on Asset Dispositions, Net |
16,460 |
(3,836) |
|||||
Other, Net |
21,016 |
43,391 |
|||||
Total |
4,717,692 |
4,058,642 |
|||||
Operating Expenses |
|||||||
Lease and Well |
329,659 |
336,291 |
|||||
Transportation Costs |
208,296 |
176,522 |
|||||
Gathering and Processing Costs |
128,482 |
111,295 |
|||||
Exploration Costs |
39,677 |
36,324 |
|||||
Dry Hole Costs |
372 |
94 |
|||||
Impairments |
1,572,935 |
72,356 |
|||||
Marketing Costs |
1,108,993 |
1,270,057 |
|||||
Depreciation, Depletion and Amortization |
1,000,060 |
879,595 |
|||||
General and Administrative |
114,273 |
106,672 |
|||||
Taxes Other Than Income |
157,360 |
192,906 |
|||||
Total |
4,660,107 |
3,182,112 |
|||||
Operating Income |
57,585 |
876,530 |
|||||
Other Income, Net |
18,108 |
5,612 |
|||||
Income Before Interest Expense and Income Taxes |
75,693 |
882,142 |
|||||
Interest Expense, Net |
44,690 |
54,906 |
|||||
Income Before Income Taxes |
31,003 |
827,236 |
|||||
Income Tax Provision |
21,190 |
191,810 |
|||||
Net Income |
$ |
9,813 |
$ |
635,426 |
|||
Dividends Declared per Common Share |
$ |
0.3750 |
$ |
0.2200 |
EOG RESOURCES, INC. | |||||||
Operating Highlights | |||||||
(Unaudited) | |||||||
Three Months Ended |
|||||||
March 31, |
|||||||
2020 |
2019 |
% Change | |||||
Wellhead Volumes and Prices |
|||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||
United States |
482.7 |
435.1 |
11% | ||||
Trinidad |
0.5 |
0.7 |
-29% | ||||
Other International (B) |
0.1 |
0.1 |
0% | ||||
Total |
483.3 |
435.9 |
11% | ||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||
United States |
$ |
46.97 |
$ |
56.11 |
-16% | ||
Trinidad |
34.93 |
43.68 |
-20% | ||||
Other International (B) |
57.51 |
60.13 |
-4% | ||||
Composite |
46.96 |
56.09 |
-16% | ||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||
United States |
161.3 |
119.8 |
35% | ||||
Other International (B) |
- |
- |
|||||
Total |
161.3 |
119.8 |
35% | ||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||
United States |
$ |
10.94 |
$ |
20.28 |
-46% | ||
Other International (B) |
- |
- |
|||||
Composite |
10.94 |
20.28 |
-46% | ||||
Natural Gas Volumes (MMcfd) (A) |
|||||||
United States |
1,139 |
1,003 |
14% | ||||
Trinidad |
201 |
267 |
-25% | ||||
Other International (B) |
38 |
38 |
0% | ||||
Total |
1,378 |
1,308 |
5% | ||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||
United States |
$ |
1.50 |
$ |
2.77 |
-46% | ||
Trinidad |
2.17 |
2.91 |
-26% | ||||
Other International (B) |
4.32 |
4.37 |
-1% | ||||
Composite |
1.67 |
2.85 |
-41% | ||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||
United States |
833.8 |
722.0 |
15% | ||||
Trinidad |
34.0 |
45.1 |
-25% | ||||
Other International (B) |
6.3 |
6.5 |
-3% | ||||
Total |
874.1 |
773.6 |
13% | ||||
Total MMBoe (D) |
79.5 |
69.6 |
14% | ||||
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||
(B) Other International includes EOG's China and Canada operations. | |||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2019). | |||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
March 31, |
December 31, | ||||
2020 |
2019 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
2,906,852 |
$ |
2,027,972 | |
Accounts Receivable, Net |
1,449,637 |
2,001,658 | |||
Inventories |
662,398 |
767,297 | |||
Assets from Price Risk Management Activities |
932,928 |
1,299 | |||
Income Taxes Receivable |
309,328 |
151,665 | |||
Other |
229,906 |
323,448 | |||
Total |
6,491,049 |
5,273,339 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
64,046,355 |
62,830,415 | |||
Other Property, Plant and Equipment |
4,648,834 |
4,472,246 | |||
Total Property, Plant and Equipment |
68,695,189 |
67,302,661 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(39,001,135) |
(36,938,066) | |||
Total Property, Plant and Equipment, Net |
29,694,054 |
30,364,595 | |||
Deferred Income Taxes |
2,558 |
2,363 | |||
Other Assets |
1,446,423 |
1,484,311 | |||
Total Assets |
$ |
37,634,084 |
$ |
37,124,608 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
2,892,320 |
$ |
2,429,127 | |
Accrued Taxes Payable |
200,240 |
254,850 | |||
Dividends Payable |
216,933 |
166,273 | |||
Liabilities from Price Risk Management Activities |
- |
20,194 | |||
Current Portion of Long-Term Debt |
519,017 |
1,014,524 | |||
Current Portion of Operating Lease Liabilities |
322,367 |
369,365 | |||
Other |
154,134 |
232,655 | |||
Total |
4,305,011 |
4,486,988 | |||
Long-Term Debt |
4,703,152 |
4,160,919 | |||
Other Liabilities |
2,064,175 |
1,789,884 | |||
Deferred Income Taxes |
5,091,071 |
5,046,101 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and |
205,824 |
205,822 | |||
Additional Paid in Capital |
5,852,821 |
5,817,475 | |||
Accumulated Other Comprehensive Loss |
(3,305) |
(4,652) | |||
Retained Earnings |
15,440,142 |
15,648,604 | |||
Common Stock Held in Treasury, 319,162 Shares at March 31, 2020 |
(24,807) |
(26,533) | |||
Total Stockholders' Equity |
21,470,675 |
21,640,716 | |||
Total Liabilities and Stockholders' Equity |
$ |
37,634,084 |
$ |
37,124,608 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Three Months Ended | |||||
March 31, | |||||
2020 |
2019 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
|||||
Net Income |
$ |
9,813 |
$ |
635,426 | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
1,000,060 |
879,595 | |||
Impairments |
1,572,935 |
72,356 | |||
Stock-Based Compensation Expenses |
40,072 |
39,087 | |||
Deferred Income Taxes |
44,774 |
106,324 | |||
(Gains) Losses on Asset Dispositions, Net |
(16,460) |
3,836 | |||
Other, Net |
(8,815) |
2,952 | |||
Dry Hole Costs |
372 |
94 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(1,205,773) |
20,580 | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
84,373 |
20,846 | |||
Other, Net |
(355) |
976 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
722,163 |
(308,996) | |||
Inventories |
102,670 |
(18,979) | |||
Accounts Payable |
433,558 |
194,082 | |||
Accrued Taxes Payable |
(54,605) |
114,998 | |||
Other Assets |
58,296 |
(6,935) | |||
Other Liabilities |
(66,078) |
(54,092) | |||
Changes in Components of Working Capital Associated with Investing |
(132,082) |
(94,381) | |||
Net Cash Provided by Operating Activities |
2,584,918 |
1,607,769 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(1,566,051) |
(1,939,473) | |||
Additions to Other Property, Plant and Equipment |
(122,775) |
(60,963) | |||
Proceeds from Sales of Assets |
25,801 |
15,049 | |||
Changes in Components of Working Capital Associated with Investing Activities |
132,082 |
94,381 | |||
Net Cash Used in Investing Activities |
(1,530,943) |
(1,891,006) | |||
Financing Cash Flows |
|||||
Dividends Paid |
(167,058) |
(127,546) | |||
Treasury Stock Purchased |
(4,655) |
(6,248) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
66 |
403 | |||
Repayment of Finance Lease Liabilities |
(3,621) |
(3,190) | |||
Net Cash Used in Financing Activities |
(175,268) |
(136,581) | |||
Effect of Exchange Rate Changes on Cash |
173 |
(6) | |||
Increase (Decrease) in Cash and Cash Equivalents |
878,880 |
(419,824) | |||
Cash and Cash Equivalents at Beginning of Period |
2,027,972 |
1,555,634 | |||
Cash and Cash Equivalents at End of Period |
$ |
2,906,852 |
$ |
1,135,810 |
EOG RESOURCES, INC. | |||||||||||||||
Reconciliation of Adjusted Net Income | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month periods ended March 31, 2020 and 2019 reported Net Income (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2020 and 2019 and to add back impairment charges related to certain of EOG's assets in 2020 and 2019. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
March 31, 2020 |
March 31, 2019 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (GAAP) |
$ 31,003 |
$(21,190) |
$ 9,813 |
$ 0.02 |
$827,236 |
$(191,810) |
$635,426 |
$ 1.10 | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
(1,205,773) |
264,643 |
(941,130) |
(1.62) |
20,580 |
(4,533) |
16,047 |
0.02 | |||||||
Net Cash Received from Settlements of |
84,373 |
(18,518) |
65,855 |
0.11 |
20,846 |
(4,592) |
16,254 |
0.03 | |||||||
Add: (Gains) Losses on Asset Dispositions, Net |
(16,460) |
3,613 |
(12,847) |
(0.02) |
3,836 |
(736) |
3,100 |
0.01 | |||||||
Add: Impairments |
1,516,316 |
(319,973) |
1,196,343 |
2.06 |
23,745 |
(5,230) |
18,515 |
0.03 | |||||||
Adjustments to Net Income |
378,456 |
(70,235) |
308,221 |
0.53 |
69,007 |
(15,091) |
53,916 |
0.09 | |||||||
Adjusted Net Income (Non-GAAP) |
$ 409,459 |
$(91,425) |
$ 318,034 |
$ 0.55 |
$896,243 |
$(206,901) |
$689,342 |
$ 1.19 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
578,462 |
577,207 | |||||||||||||
Diluted |
580,283 |
580,222 |
EOG RESOURCES, INC. | ||||
Reconciliation of Discretionary Cash Flow | ||||
(Unaudited; in thousands) | ||||
Calculation of Free Cash Flow | ||||
(Unaudited; in thousands) | ||||
The following chart reconciles the three-month periods ended March 31, 2020 and 2019 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the three months ended March 31, 2020 and 2019. EOG management uses this information for comparative purposes within the industry. | ||||
Three Months Ended | ||||
March 31, | ||||
2020 |
2019 | |||
Net Cash Provided by Operating Activities (GAAP) |
$2,584,918 |
$1,607,769 | ||
Adjustments: |
||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
32,482 |
29,787 | ||
Other Non-Current Income Taxes - Net Receivable |
112,704 |
102,918 | ||
Changes in Components of Working Capital and Other Assets |
||||
and Liabilities |
||||
Accounts Receivable |
(722,163) |
308,996 | ||
Inventories |
(102,670) |
18,979 | ||
Accounts Payable |
(433,558) |
(194,082) | ||
Accrued Taxes Payable |
54,605 |
(114,998) | ||
Other Assets |
(58,296) |
6,935 | ||
Other Liabilities |
66,078 |
54,092 | ||
Changes in Components of Working Capital Associated with |
||||
Investing Activities |
132,082 |
94,381 | ||
Discretionary Cash Flow (Non-GAAP) |
$1,666,182 |
$1,914,777 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-13% |
|||
Discretionary Cash Flow (Non-GAAP) |
$1,666,182 |
$1,914,777 | ||
Less: |
||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) |
(1,684,720) |
(1,732,476) | ||
Free Cash Flow (Non-GAAP)(b) |
$ (18,538) |
$ 182,301 | ||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month periods ended March 31, 2020 and 2019: | ||||
Total Expenditures (GAAP) |
$1,825,778 |
$2,101,919 | ||
Less: |
||||
Asset Retirement Costs |
(19,608) |
(5,156) | ||
Non-Cash Expenditures of Other Property, Plant and Equipment |
- |
- | ||
Non-Cash Acquisition Costs of Unproved Properties |
(24,488) |
(43,481) | ||
Non-Cash Finance Leases |
(48,958) |
- | ||
Acquisition Costs of Proved Properties |
(48,004) |
(320,806) | ||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
$1,684,720 |
$1,732,476 | ||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item for the three-month period ending March 31, 2020. The comparative prior period has been revised for this change in presentation. | ||||
Maintenance Capital Expenditures | ||||
The capital expenditures required to fund drilling and infrastructure requirements to keep U.S. oil production in 2021 flat relative to anticipated 4Q 2020 U.S. oil production. |
EOG RESOURCES, INC. | |||||
Reconciliation of Discretionary Cash Flow | |||||
(Unaudited; in thousands) | |||||
Calculation of Free Cash Flow | |||||
(Unaudited; in thousands) | |||||
The following chart reconciles the twelve-month periods ended December 31, 2019, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net (Payable) Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2019, 2018 and 2017. EOG management uses this information for comparative purposes within the industry. | |||||
Twelve Months Ended | |||||
December 31, | |||||
2019 |
2018 |
2017 | |||
Net Cash Provided by Operating Activities (GAAP) |
$ 8,163,180 |
$ 7,768,608 |
$ 4,265,336 | ||
Adjustments: |
|||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
113,733 |
123,986 |
122,688 | ||
Other Non-Current Income Taxes - Net (Payable) Receivable |
238,711 |
148,993 |
(513,404) | ||
Changes in Components of Working Capital and Other Assets |
|||||
and Liabilities |
|||||
Accounts Receivable |
91,792 |
368,180 |
392,131 | ||
Inventories |
(90,284) |
395,408 |
174,548 | ||
Accounts Payable |
(168,539) |
(439,347) |
(324,192) | ||
Accrued Taxes Payable |
(40,122) |
92,461 |
63,937 | ||
Other Assets |
(358,001) |
125,435 |
658,609 | ||
Other Liabilities |
56,619 |
(10,949) |
89,871 | ||
Changes in Components of Working Capital Associated with |
|||||
Investing and Financing Activities |
115,061 |
(301,083) |
(89,992) | ||
Discretionary Cash Flow (Non-GAAP) |
$ 8,122,150 |
$ 8,271,692 |
$ 4,839,532 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease |
-2% |
71% |
|||
Discretionary Cash Flow (Non-GAAP) |
$ 8,122,150 |
$ 8,271,692 |
$ 4,839,532 | ||
Less: |
|||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) |
(6,234,454) |
(6,172,950) |
(4,228,859) | ||
Free Cash Flow (Non-GAAP)(b) |
$ 1,887,696 |
$ 2,098,742 |
$ 610,673 | ||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2019, 2018 and 2017: | |||||
Total Expenditures (GAAP) |
$ 6,900,450 |
$ 6,706,359 |
$ 4,612,746 | ||
Less: |
|||||
Asset Retirement Costs |
(186,088) |
(69,699) |
(55,592) | ||
Non-Cash Expenditures of Other Property, Plant and Equipment |
(2,266) |
(49,484) |
- | ||
Non-Cash Acquisition Costs of Unproved Properties |
(97,704) |
(290,542) |
(255,711) | ||
Acquisition Costs of Proved Properties |
(379,938) |
(123,684) |
(72,584) | ||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
$ 6,234,454 |
$ 6,172,950 |
$ 4,228,859 | ||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item for the twelve-month period ending December 31, 2019. Comparative prior periods have been revised for this change in presentation. | |||||
EOG RESOURCES, INC. | |||||
Reconciliation of Discretionary Cash Flow | |||||
(Unaudited; in thousands) | |||||
Calculation of Free Cash Flow | |||||
(Unaudited; in thousands) | |||||
The following chart reconciles the twelve-month periods ended December 31, 2014, 2013 and 2012 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2014, 2013 and 2012. EOG management uses this information for comparative purposes within the industry. | |||||
Twelve Months Ended | |||||
December 31, | |||||
2014 |
2013 |
2012 | |||
Net Cash Provided by Operating Activities (GAAP) |
$ 8,649,155 |
$ 7,329,414 |
$ 5,236,777 | ||
Adjustments: |
|||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
157,453 |
134,531 |
159,182 | ||
Excess Tax Benefits from Stock-Based Compensation |
99,459 |
55,831 |
67,035 | ||
Changes in Components of Working Capital and Other Assets |
|||||
and Liabilities |
|||||
Accounts Receivable |
(84,982) |
23,613 |
178,683 | ||
Inventories |
161,958 |
(53,402) |
156,762 | ||
Accounts Payable |
(543,630) |
(178,701) |
17,150 | ||
Accrued Taxes Payable |
(16,486) |
(75,142) |
(78,094) | ||
Other Assets |
14,448 |
109,567 |
118,520 | ||
Other Liabilities |
(75,420) |
20,382 |
(36,114) | ||
Changes in Components of Working Capital Associated with |
|||||
Investing and Financing Activities |
103,414 |
51,361 |
(74,158) | ||
Discretionary Cash Flow (Non-GAAP) |
$ 8,465,369 |
$ 7,417,454 |
$ 5,745,743 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
14% |
29% |
|||
Discretionary Cash Flow (Non-GAAP) |
$ 8,465,369 |
$ 7,417,454 |
$ 5,745,743 | ||
Less: |
|||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) |
(8,292,090) |
(7,101,791) |
(7,539,994) | ||
Free Cash Flow (Non-GAAP)(b) |
$ 173,279 |
$ 315,663 |
$ (1,794,251) | ||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2014, 2013 and 2012: | |||||
Total Expenditures (GAAP) |
$ 8,631,906 |
$ 7,361,457 |
$ 7,753,828 | ||
Less: |
|||||
Asset Retirement Costs |
(195,630) |
(134,445) |
(126,987) | ||
Non-Cash Expenditures of Other Property, Plant and Equipment |
- |
- |
(65,791) | ||
Non-Cash Acquisition Costs of Unproved Properties |
(5,085) |
(5,007) |
(20,317) | ||
Acquisition Costs of Proved Properties |
(139,101) |
(120,214) |
(739) | ||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
$ 8,292,090 |
$ 7,101,791 |
$ 7,539,994 | ||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item. Comparative prior periods presented herein have been revised for this change in presentation. |
EOG RESOURCES, INC. | ||||||||||
Total Expenditures | ||||||||||
(Unaudited; in millions) | ||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||
March 31, |
December 31, | |||||||||
2020 |
2019 |
2019 |
2018 |
2017 | ||||||
Exploration and Development Drilling |
$1,313 |
$1,402 |
$4,951 |
$4,935 |
$3,132 | |||||
Facilities |
179 |
164 |
629 |
625 |
575 | |||||
Leasehold Acquisitions |
45 |
107 |
276 |
488 |
427 | |||||
Property Acquisitions |
48 |
321 |
380 |
124 |
73 | |||||
Capitalized Interest |
9 |
7 |
38 |
24 |
27 | |||||
Subtotal |
1,594 |
2,001 |
6,274 |
6,196 |
4,234 | |||||
Exploration Costs |
40 |
36 |
140 |
149 |
145 | |||||
Dry Hole Costs |
- |
- |
28 |
5 |
5 | |||||
Exploration and Development Expenditures |
1,634 |
2,037 |
6,442 |
6,350 |
4,384 | |||||
Asset Retirement Costs |
20 |
4 |
186 |
70 |
56 | |||||
Total Exploration and Development Expenditures |
1,654 |
2,041 |
6,628 |
6,420 |
4,440 | |||||
Other Property, Plant and Equipment |
172 |
61 |
272 |
286 |
173 | |||||
Total Expenditures |
$1,826 |
$2,102 |
$6,900 |
$6,706 |
$4,613 |
EOG RESOURCES, INC. | ||||||
Reconciliation of Adjusted EBITDAX | ||||||
(Unaudited; in thousands) | ||||||
The following chart adjusts the three-month periods ended March 31, 2020 and 2019 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||
Three Months Ended |
||||||
March 31, |
||||||
2020 |
2019 |
|||||
Net Income (GAAP) |
$ |
9,813 |
$ |
635,426 |
||
Adjustments: |
||||||
Interest Expense, Net |
44,690 |
54,906 |
||||
Income Tax Provision |
21,190 |
191,810 |
||||
Depreciation, Depletion and Amortization |
1,000,060 |
879,595 |
||||
Exploration Costs |
39,677 |
36,324 |
||||
Dry Hole Costs |
372 |
94 |
||||
Impairments |
1,572,935 |
72,356 |
||||
EBITDAX (Non-GAAP) |
2,688,737 |
1,870,511 |
||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
(1,205,773) |
20,580 |
||||
Net Cash Received from Settlements of Commodity |
84,373 |
20,846 |
||||
(Gains) Losses on Asset Dispositions, Net |
(16,460) |
3,836 |
||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,550,877 |
$ |
1,915,773 |
||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-19% |
EOG RESOURCES, INC. | |||||||||
Reconciliation of Net Debt and Total Capitalization | |||||||||
Calculation of Net Debt-to-Total Capitalization Ratio | |||||||||
(Unaudited; in millions, except ratio data) | |||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||||||
At |
At |
At |
At |
At | |||||
March 31, |
December 31, |
September 30, |
June 30, |
March 31, | |||||
2020 |
2019 |
2019 |
2019 |
2019 | |||||
Total Stockholders' Equity - (a) |
$ 21,471 |
$ 21,641 |
$ 21,124 |
$ 20,630 |
$ 19,904 | ||||
Current and Long-Term Debt (GAAP) - (b) |
5,222 |
5,175 |
5,177 |
5,179 |
6,081 | ||||
Less: Cash |
(2,907) |
(2,028) |
(1,583) |
(1,160) |
(1,136) | ||||
Net Debt (Non-GAAP) - (c) |
2,315 |
3,147 |
3,594 |
4,019 |
4,945 | ||||
Total Capitalization (GAAP) - (a) + (b) |
$ 26,693 |
$ 26,816 |
$ 26,301 |
$ 25,809 |
$ 25,985 | ||||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ 23,786 |
$ 24,788 |
$ 24,718 |
$ 24,649 |
$ 24,849 | ||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
20% |
19% |
20% |
20% |
23% | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
10% |
13% |
15% |
16% |
20% | ||||
EOG RESOURCES, INC. |
|||||||||
Reconciliation of Net Debt and Total Capitalization |
|||||||||
Calculation of Net Debt-to-Total Capitalization Ratio |
|||||||||
(Unaudited; in millions, except ratio data) |
|||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
|||||||||
At |
At |
At |
At |
||||||
December 31, |
September 30, |
June 30, |
March 31, |
||||||
2018 |
2018 |
2018 |
2018 |
||||||
Total Stockholders' Equity - (a) |
$ 19,364 |
$ 18,538 |
$ 17,452 |
$ 16,841 |
|||||
Current and Long-Term Debt (GAAP) - (b) |
6,083 |
6,435 |
6,435 |
6,435 |
|||||
Less: Cash |
(1,556) |
(1,274) |
(1,008) |
(816) |
|||||
Net Debt (Non-GAAP) - (c) |
4,527 |
5,161 |
5,427 |
5,619 |
|||||
Total Capitalization (GAAP) - (a) + (b) |
$ 25,447 |
$ 24,973 |
$ 23,887 |
$ 23,276 |
|||||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ 23,891 |
$ 23,699 |
$ 22,879 |
$ 22,460 |
|||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
24% |
26% |
27% |
28% |
|||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
19% |
22% |
24% |
25% |
|||||
EOG RESOURCES, INC. |
|||||||||
Reconciliation of Net Debt and Total Capitalization |
|||||||||
Calculation of Net Debt-to-Total Capitalization Ratio |
|||||||||
(Unaudited; in millions, except ratio data) |
|||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
|||||||||
At |
At |
At |
At |
||||||
December 31, |
September 30, |
June 30, |
March 31, |
||||||
2017 |
2017 |
2017 |
2017 |
||||||
Total Stockholders' Equity - (a) |
$ 16,283 |
$ 13,922 |
$ 13,902 |
$ 13,928 |
|||||
Current and Long-Term Debt (GAAP) - (b) |
6,387 |
6,387 |
6,987 |
6,987 |
|||||
Less: Cash |
(834) |
(846) |
(1,649) |
(1,547) |
|||||
Net Debt (Non-GAAP) - (c) |
5,553 |
5,541 |
5,338 |
5,440 |
|||||
Total Capitalization (GAAP) - (a) + (b) |
$ 22,670 |
$ 20,309 |
$ 20,889 |
$ 20,915 |
|||||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ 21,836 |
$ 19,463 |
$ 19,240 |
$ 19,368 |
|||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
28% |
31% |
33% |
33% |
|||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25% |
28% |
28% |
28% |
|||||
EOG RESOURCES, INC. | |||||||||
Reconciliation of Net Debt and Total Capitalization | |||||||||
Calculation of Net Debt-to-Total Capitalization Ratio | |||||||||
(Unaudited; in millions, except ratio data) | |||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||||||
At |
At |
At |
At |
At | |||||
December 31, |
September 30, |
June 30, |
March 31, |
December 31, | |||||
2016 |
2016 |
2016 |
2016 |
2015 | |||||
Total Stockholders' Equity - (a) |
$ 13,982 |
$ 11,798 |
$ 12,057 |
$ 12,405 |
12,943 | ||||
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,986 |
6,986 |
6,986 |
6,660 | ||||
Less: Cash |
(1,600) |
(1,049) |
(780) |
(668) |
(719) | ||||
Net Debt (Non-GAAP) - (c) |
5,386 |
5,937 |
6,206 |
6,318 |
5,941 | ||||
Total Capitalization (GAAP) - (a) + (b) |
$ 20,968 |
$ 18,784 |
$ 19,043 |
$ 19,391 |
19,603 | ||||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ 19,368 |
$ 17,735 |
$ 18,263 |
$ 18,723 |
18,884 | ||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33% |
37% |
37% |
36% |
34% | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
33% |
34% |
34% |
31% |
EOG RESOURCES, INC. | ||||||||||||
Reconciliation of Total Exploration and Development Expenditures | ||||||||||||
For Drilling Only and Total Exploration and Development Expenditures | ||||||||||||
Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||||||
2019 |
2018 |
2017 |
2016 |
2015 |
2014 | |||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,628.2 |
$ 6,419.7 |
$ 4,439.4 |
$ 6,445.2 |
$ 4,928.3 |
$ 7,904.8 | ||||||
Less: Asset Retirement Costs |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) | ||||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
- |
- | ||||||
Acquisition Costs of Proved Properties |
(379.9) |
(123.7) |
(72.6) |
(749.0) |
(480.6) |
(139.1) | ||||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) |
$ 5,964.5 |
$ 5,935.8 |
$ 4,055.5 |
$ 2,614.3 |
$ 4,394.2 |
$ 7,570.1 | ||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,628.2 |
$ 6,419.7 |
$ 4,439.4 |
$ 6,445.2 |
$ 4,928.3 |
$ 7,904.8 | ||||||
Less: Asset Retirement Costs |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) | ||||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
- |
- | ||||||
Non-Cash Acquisition Costs of Proved Properties |
(52.3) |
(70.9) |
(26.2) |
(732.3) |
- |
- | ||||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) |
$ 6,292.1 |
$ 5,988.6 |
$ 4,101.9 |
$ 2,631.0 |
$ 4,874.8 |
$ 7,709.2 | ||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||||||
Revisions Due to Price - (c) |
(59.7) |
34.8 |
154.0 |
(100.7) |
(573.8) |
52.2 | ||||||
Revisions Other Than Price |
(0.3) |
(39.5) |
48.0 |
252.9 |
107.2 |
48.4 | ||||||
Purchases in Place |
16.8 |
11.6 |
2.3 |
42.3 |
56.2 |
14.4 | ||||||
Extensions, Discoveries and Other Additions - (d) |
750.0 |
669.7 |
420.8 |
209.0 |
245.9 |
519.2 | ||||||
Total Proved Reserve Additions - (e) |
706.8 |
676.6 |
625.1 |
403.5 |
(164.5) |
634.2 | ||||||
Sales in Place |
(4.6) |
(10.8) |
(20.7) |
(167.6) |
(3.5) |
(36.3) | ||||||
Net Proved Reserve Additions From All Sources |
702.2 |
665.8 |
604.4 |
235.9 |
(168.0) |
597.9 | ||||||
Production |
300.9 |
265.0 |
224.4 |
207.1 |
211.2 |
219.1 | ||||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||||||
Total Drilling, Before Revisions - (a / d) |
$ 7.95 |
$ 8.86 |
$ 9.64 |
$ 12.51 |
$ 17.87 |
$ 14.58 | ||||||
All-in Total, Net of Revisions - (b / e) |
$ 8.90 |
$ 8.85 |
$ 6.56 |
$ 6.52 |
$ (29.63) |
$ 12.16 | ||||||
All-in Total, Excluding Revisions Due to Price - (b / (e - c)) |
$ 8.21 |
$ 9.33 |
$ 8.71 |
$ 5.22 |
$ 11.91 |
$ 13.25 |
EOG RESOURCES, INC. | |||||||||||
Crude Oil, NGLs and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||||||||
Prices received by EOG for its crude oil production generally vary from NYMEX WTI prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between Intercontinental Exchange (ICE) Brent pricing and pricing in Cushing, Oklahoma (ICE Brent Differential). Presented below is a comprehensive summary of EOG's ICE Brent Differential basis swap contracts through May 5, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
ICE Brent Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
May 2020 |
10,000 |
$ 4.92 | |||||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in Houston, Texas, and Cushing, Oklahoma (Houston Differential). Presented below is a comprehensive summary of EOG's Houston Differential basis swap contracts through May 5, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Houston Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
May 2020 (closed) |
10,000 |
$ 1.55 | |||||||||
EOG has also entered into crude oil swaps to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through May 5, 2020. The weighted average price differential expressed in $/Bbl represents the amount of net addition (reduction) to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. | |||||||||||
Roll Differential Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
February 1, 2020 through May 31, 2020 (closed) |
10,000 |
$ 0.70 | |||||||||
June 2020 |
10,000 |
0.70 | |||||||||
July 1, 2020 through September 30, 2020 |
110,000 |
(1.16) | |||||||||
October 1, 2020 through December 31, 2020 |
93,000 |
(1.16) | |||||||||
In May 2020, EOG entered into crude oil Roll Differential contracts for the period from October 1, 2020 through December 31, 2020, with notional volumes of 17,000 Bbld at a weighted average price differential of $(1.01) per Bbl. These contracts partially offset certain outstanding Roll Differential contracts for the same time period with notional volumes of 17,000 Bbld at a weighted average price differential of $(1.16) per Bbl. EOG expects to pay net cash of $0.2 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's crude oil NYMEX WTI price swap contracts through May 5, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil NYMEX WTI Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through March 31, 2020 (closed) |
200,000 |
$ 59.33 | |||||||||
April 2020 (closed) |
265,000 |
51.36 | |||||||||
May 1, 2020 through June 30, 2020 |
265,000 |
51.36 | |||||||||
July 2020 |
254,000 |
42.36 | |||||||||
August 1, 2020 through September 30, 2020 |
154,000 |
50.42 | |||||||||
In April and May 2020, EOG entered into crude oil NYMEX WTI price swap contracts for the period from October 1, 2020 through December 31, 2020, with notional volumes of 47,000 Bbld at a weighted average price of $30.04 per Bbl. These contracts offset the remaining NYMEX WTI price swap contracts for the same time period with notional volumes of 47,000 Bbld at a weighted average price of $31.00 per Bbl. EOG expects to receive net cash of $4.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's crude oil ICE Brent price swap contracts through May 5, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil ICE Brent Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
April 2020 (closed) |
75,000 |
$ 25.66 | |||||||||
May 2020 |
35,000 |
26.53 | |||||||||
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) financial price swap contracts (Mont Belvieu Propane Price Swap Contracts) through May 5, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Mont Belvieu Propane Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through February 29, 2020 (closed) |
4,000 |
$ 21.34 | |||||||||
March 1, 2020 through April 30, 2020 (closed) |
25,000 |
17.92 | |||||||||
May 1, 2020 through December 31, 2020 |
7,000 |
17.92 | |||||||||
In April and May 2020, EOG entered into Mont Belvieu Propane Price Swap Contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 18,000 Bbld at a weighted average price of $15.68 per Bbl. These contracts partially offset certain outstanding Mont Belvieu Propane Price Swap Contracts for the same time period with notional volumes of 18,000 Bbld at a weighted average price of $17.92 per Bbl. EOG expects to receive net cash of $9.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through May 5, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2021 |
|||||||||||
January 1, 2021 through December 31, 2021 |
50,000 |
$ 2.75 | |||||||||
EOG has entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. On March 24, 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 natural gas collar contracts with notional volumes of 250,000 MMBtud at a weighted average ceiling price of $2.50 per MMBtu and a weighted average floor price of $2.00 per MMBtu for the period April 1, 2020 through July 31, 2020. The net cash EOG received for settling these contracts was $7.8 million. Presented below is a comprehensive summary of EOG's natural gas collar contracts through May 5, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume (MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2020 |
|||||||||||
April 1, 2020 through July 31, 2020 (closed) |
250,000 |
$ 2.50 |
$ 2.00 | ||||||||
On April 14, 2020, EOG entered into natural gas collar contracts for the period August 1, 2020 through October 31, 2020, with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. These contracts offset the remaining natural gas collar contracts for the same time period with notional volumes of 250,000 MMBtud at a ceiling price of $2.50 per MMBtu and a floor price of $2.00 per MMBtu. EOG expects to receive net cash of $1.1 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | |||||||||||
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through May 5, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
Rockies Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through May 31, 2020 (closed) |
30,000 |
$ 0.55 | |||||||||
June 1, 2020 through December 31, 2020 |
30,000 |
0.55 | |||||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). On March 27, 2020, EOG executed the early termination provision granting EOG the right to terminate certain 2020 HSC Differential basis swaps with notional volumes of 60,000 MMBtud at a weighted average price differential of $0.05 per MMBtu for the period April 1, 2020 through December 31, 2020. The net cash EOG paid for settling these contracts was $0.4 million. Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through May 5, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
HSC Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through December 31, 2020 (closed) |
60,000 |
$ 0.05 | |||||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through May 5, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
Waha Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through April 30, 2020 (closed) |
50,000 |
$ 1.40 | |||||||||
In April 2020, EOG entered into Waha Differential basis swap contracts for the period from May 1, 2020 through December 31, 2020, with notional volumes of 50,000 MMBtud at a weighted average price differential of $0.43 per MMBtu. These contracts offset the remaining Waha Differential basis swap contracts for the same time period with notional volumes of 50,000 MMBtud at a weighted average price differential of $1.40 MMBtu. EOG expects to pay net cash of $11.9 million for the settlement of these contracts. The offsetting contracts were excluded from the above table. | |||||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
||||||||||
WTI |
West Texas Intermediate |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, | ||||||||
Net Debt and Total Capitalization | ||||||||
Calculations of Return on Capital Employed and Return on Equity | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2019 |
2018 |
2017 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||
Net Interest Expense (GAAP) |
$ |
185 |
$ |
245 |
||||
Tax Benefit Imputed (based on 21%) |
(39) |
(51) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
146 |
$ |
194 |
||||
Net Income (GAAP) - (b) |
$ |
2,735 |
$ |
3,419 |
||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) |
158 |
(1) |
(201) |
(2) |
||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
2,893 |
$ |
3,218 |
||||
Total Stockholders' Equity - (d) |
$ |
21,641 |
$ |
19,364 |
$ |
16,283 | ||
Average Total Stockholders' Equity * - (e) |
$ |
20,503 |
$ |
17,824 |
||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
5,175 |
$ |
6,083 |
$ |
6,387 | ||
Less: Cash |
(2,028) |
(1,556) |
(834) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
3,147 |
$ |
4,527 |
$ |
5,553 | ||
Total Capitalization (GAAP) - (d) + (f) |
$ |
26,816 |
$ |
25,447 |
$ |
22,670 | ||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
24,788 |
$ |
23,891 |
$ |
21,836 | ||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
24,340 |
$ |
22,864 |
||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
11.8% |
15.8% |
||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
12.5% |
14.9% |
||||||
Return on Equity (ROE) |
||||||||
ROE (GAAP Net Income) - (b) / (e) |
13.3% |
19.2% |
||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
14.1% |
18.1% |
||||||
* Average for the current and immediately preceding year |
||||||||
Adjustments to Net Income (GAAP) |
||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2019: |
||||||||
Year Ended December 31, 2019 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
51 |
$ |
(11) |
$ |
40 | ||
Add: Impairments of Certain Assets |
275 |
(60) |
215 | |||||
Less: Net Gains on Asset Dispositions |
(124) |
27 |
(97) | |||||
Total |
$ |
202 |
$ |
(44) |
$ |
158 | ||
(2) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: |
||||||||
Year Ended December 31, 2018 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(93) |
$ |
20 |
$ |
(73) | ||
Add: Impairments of Certain Assets |
153 |
(34) |
119 | |||||
Less: Net Gains on Asset Dispositions |
(175) |
38 |
(137) | |||||
Less: Tax Reform Impact |
- |
(110) |
(110) | |||||
Total |
$ |
(115) |
$ |
(86) |
$ |
(201) |
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 |
2016 |
2015 |
2014 |
2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
$ |
235 |
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
(82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
$ |
153 |
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
Total Stockholders' Equity - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
Average Total Stockholders' Equity * - (e) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 |
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
21,836 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,602 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
$ |
19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
13.4% |
-4.8% |
-21.6% |
14.7% |
12.1% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.1% |
-8.1% |
-29.5% |
17.6% |
15.3% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 |
2011 |
2010 |
2009 |
2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
214 |
$ |
210 |
$ |
130 |
$ |
101 |
$ |
52 |
Tax Benefit Imputed (based on 35%) |
(75) |
(74) |
(46) |
(35) |
(18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
139 |
$ |
136 |
$ |
84 |
$ |
66 |
$ |
34 |
Net Income (Loss) (GAAP) - (b) |
$ |
570 |
$ |
1,091 |
$ |
161 |
$ |
547 |
$ |
2,437 |
Total Stockholders' Equity - (d) |
$ |
13,285 |
$ |
12,641 |
$ |
10,232 |
$ |
9,998 |
$ |
9,015 |
Average Total Stockholders' Equity * - (e) |
$ |
12,963 |
$ |
11,437 |
$ |
10,115 |
$ |
9,507 |
$ |
8,003 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,312 |
$ |
5,009 |
$ |
5,223 |
$ |
2,797 |
$ |
1,897 |
Less: Cash |
(876) |
(616) |
(789) |
(686) |
(331) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
5,436 |
$ |
4,393 |
$ |
4,434 |
$ |
2,111 |
$ |
1,566 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,597 |
$ |
17,650 |
$ |
15,455 |
$ |
12,795 |
$ |
10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,721 |
$ |
17,034 |
$ |
14,666 |
$ |
12,109 |
$ |
10,581 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
17,878 |
$ |
15,850 |
$ |
13,388 |
$ |
11,345 |
$ |
9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.0% |
7.7% |
1.8% |
5.4% |
26.4% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
4.4% |
9.5% |
1.6% |
5.8% |
30.5% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 |
2006 |
2005 |
2004 |
2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
47 |
$ |
43 |
$ |
63 |
$ |
63 |
$ |
59 |
Tax Benefit Imputed (based on 35%) |
(16) |
(15) |
(22) |
(22) |
(21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
31 |
$ |
28 |
$ |
41 |
$ |
41 |
$ |
38 |
Net Income (Loss) (GAAP) - (b) |
$ |
1,090 |
$ |
1,300 |
$ |
1,260 |
$ |
625 |
$ |
430 |
Total Stockholders' Equity - (d) |
$ |
6,990 |
$ |
5,600 |
$ |
4,316 |
$ |
2,945 |
$ |
2,223 |
Average Total Stockholders' Equity * - (e) |
$ |
6,295 |
$ |
4,958 |
$ |
3,631 |
$ |
2,584 |
$ |
1,948 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,185 |
$ |
733 |
$ |
985 |
$ |
1,078 |
$ |
1,109 |
Less: Cash |
(54) |
(218) |
(644) |
(21) |
(4) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
1,131 |
$ |
515 |
$ |
341 |
$ |
1,057 |
$ |
1,105 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
8,175 |
$ |
6,333 |
$ |
5,301 |
$ |
4,023 |
$ |
3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
8,121 |
$ |
6,115 |
$ |
4,657 |
$ |
4,002 |
$ |
3,328 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
7,118 |
$ |
5,386 |
$ |
4,330 |
$ |
3,665 |
$ |
3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
15.7% |
24.7% |
30.0% |
18.2% |
15.3% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.3% |
26.2% |
34.7% |
24.2% |
22.1% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 |
2001 |
2000 |
1999 |
1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
60 |
$ |
45 |
$ |
61 |
$ |
62 |
||
Tax Benefit Imputed (based on 35%) |
(21) |
(16) |
(21) |
(22) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
39 |
$ |
29 |
$ |
40 |
$ |
40 |
||
Net Income (Loss) (GAAP) - (b) |
$ |
87 |
$ |
399 |
$ |
397 |
$ |
569 |
||
Total Stockholders' Equity - (d) |
$ |
1,672 |
$ |
1,643 |
$ |
1,381 |
$ |
1,130 |
$ |
1,280 |
Average Total Stockholders' Equity * - (e) |
$ |
1,658 |
$ |
1,512 |
$ |
1,256 |
$ |
1,205 |
||
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,145 |
$ |
856 |
$ |
859 |
$ |
990 |
$ |
1,143 |
Less: Cash |
(10) |
(3) |
(20) |
(25) |
(6) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
1,135 |
$ |
853 |
$ |
839 |
$ |
965 |
$ |
1,137 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
2,817 |
$ |
2,499 |
$ |
2,240 |
$ |
2,120 |
$ |
2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
2,807 |
$ |
2,496 |
$ |
2,220 |
$ |
2,095 |
$ |
2,417 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
2,652 |
$ |
2,358 |
$ |
2,158 |
$ |
2,256 |
||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.8% |
18.2% |
20.2% |
27.0% |
||||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
5.2% |
26.4% |
31.6% |
47.2% |
||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||||
1st Quarter |
|||||||||||||
2020 |
2019 |
||||||||||||
Cash Operating Expenses (GAAP)* |
|||||||||||||
Lease and Well |
$ 329,659 |
$ 336,291 |
|||||||||||
Transportation Costs |
208,296 |
176,522 |
|||||||||||
General and Administrative |
114,273 |
106,672 |
|||||||||||
Cash Operating Expenses |
652,228 |
619,485 |
|||||||||||
Less: Non-GAAP Adjustments |
- |
- |
|||||||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) |
$ 652,228 |
$ 619,485 |
|||||||||||
Volume - Thousand Barrels of Oil Equivalent - (b) |
79,548 |
69,623 |
|||||||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) |
$ 8.20 |
(c) |
$ 8.90 |
(d) |
|||||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - |
|||||||||||||
1Q20 compared to 1Q19 - [(c) - (d)] / (d) |
-8% |
||||||||||||
* Includes stock compensation expense and other non-cash items. |
|||||||||||||
EOG RESOURCES, INC. | |||||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||||
Year Ended |
|||||||||||||
December 31, |
|||||||||||||
2019 |
2018 |
2017 |
2016 |
2015 |
2014 |
||||||||
Cash Operating Expenses (GAAP)* |
|||||||||||||
Lease and Well |
$1,366,993 |
$1,282,678 |
$1,044,847 |
$ 927,452 |
$1,182,282 |
$1,416,413 |
|||||||
Transportation Costs |
758,300 |
746,876 |
740,352 |
764,106 |
849,319 |
972,176 |
|||||||
General and Administrative |
489,397 |
426,969 |
434,467 |
394,815 |
366,594 |
402,010 |
|||||||
Cash Operating Expenses |
2,614,690 |
2,456,523 |
2,219,666 |
2,086,373 |
2,398,195 |
2,790,599 |
|||||||
Less: Legal Settlement - Early Leasehold Termination |
- |
- |
(10,202) |
- |
(19,355) |
- |
|||||||
Less: Voluntary Retirement Expense |
- |
- |
- |
(42,054) |
- |
- |
|||||||
Less: Acquisition Costs - Yates Transaction |
- |
- |
- |
(5,100) |
- |
- |
|||||||
Less: Joint Venture Transaction Costs |
- |
- |
(3,056) |
- |
- |
- |
|||||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
- |
(4,528) |
- |
- |
- |
|||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) |
$2,614,690 |
$2,456,523 |
$2,201,880 |
$2,039,219 |
$2,378,840 |
$2,790,599 |
|||||||
Volume - Thousand Barrels of Oil Equivalent - (b) |
298,565 |
262,516 |
222,251 |
204,929 |
208,862 |
217,073 |
|||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) |
$ 8.76 |
(c) |
$ 9.36 |
(d) |
$ 9.91 |
(e) |
$ 9.95 |
(f) |
$ 11.39 |
(g) |
$ 12.86 |
(h) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - |
|||||||||||||
2019 compared to 2018 - [(c) - (d)] / (d) |
-6% |
||||||||||||
2019 compared to 2017 - [(c) - (e)] / (e) |
-12% |
||||||||||||
2019 compared to 2016 - [(c) - (f)] / (f) |
-12% |
||||||||||||
2019 compared to 2015 - [(c) - (g)] / (g) |
-23% |
||||||||||||
2019 compared to 2014 - [(c) - (h)] / (h) |
-32% |
||||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | ||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||
Three Months Ended |
||||||||
March 31, |
||||||||
2020 |
||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
79,548 |
|||||||
Crude Oil and Condensate |
$ 2,065,498 |
|||||||
Natural Gas Liquids |
160,535 |
|||||||
Natural Gas |
209,764 |
|||||||
Total Wellhead Revenues - (b) |
$ 2,435,797 |
|||||||
Operating Costs |
||||||||
Lease and Well |
$ 329,659 |
|||||||
Transportation Costs |
208,296 |
|||||||
Gathering and Processing Costs |
128,482 |
|||||||
General and Administrative |
114,273 |
|||||||
Taxes Other Than Income |
157,360 |
|||||||
Interest Expense, Net |
44,690 |
|||||||
Total Cash Operating Cost (excluding DD&A and Total |
$ 982,760 |
|||||||
Depreciation, Depletion and Amortization (DD&A) |
1,000,060 |
|||||||
Total Operating Cost (excluding Total Exploration Costs) - (d) |
$ 1,982,820 |
|||||||
Exploration Costs |
$ 39,677 |
|||||||
Dry Hole Costs |
372 |
|||||||
Impairments |
1,572,935 |
|||||||
Total Exploration Costs |
1,612,984 |
|||||||
Less: Impairments (Non-GAAP) |
(1,516,316) |
|||||||
Total Exploration Costs (Non-GAAP) |
$ 96,668 |
|||||||
Total Operating Cost (Non-GAAP) (including Total |
$ 2,079,488 |
|||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 30.62 |
|||||||
Total Cash Operating Cost per Boe (excluding DD&A |
$ 12.36 |
|||||||
Composite Average Margin per Boe (excluding DD&A |
$ 18.26 |
|||||||
Total Operating Cost per Boe (excluding Total |
$ 24.93 |
|||||||
Composite Average Margin per Boe (excluding Total |
$ 5.69 |
|||||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 26.15 |
|||||||
Composite Average Margin per Boe (Non-GAAP) |
$ 4.47 |
|||||||
EOG RESOURCES, INC. |
||||||||
Cost per Barrel of Oil Equivalent (Boe) |
||||||||
(Unaudited; in thousands, except per Boe amounts) |
||||||||
Year Ended |
||||||||
December 31, |
||||||||
2019 |
2018 |
2017 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
298,565 |
262,516 |
222,251 |
|||||
Crude Oil and Condensate |
$ 9,612,532 |
$ 9,517,440 |
$ 6,256,396 |
|||||
Natural Gas Liquids |
784,818 |
1,127,510 |
729,561 |
|||||
Natural Gas |
1,184,095 |
1,301,537 |
921,934 |
|||||
Total Wellhead Revenues - (b) |
$ 11,581,445 |
$ 11,946,487 |
$ 7,907,891 |
|||||
Operating Costs |
||||||||
Lease and Well |
$ 1,366,993 |
$ 1,282,678 |
$ 1,044,847 |
|||||
Transportation Costs |
758,300 |
746,876 |
740,352 |
|||||
Gathering and Processing Costs |
479,102 |
436,973 |
148,775 |
|||||
General and Administrative |
489,397 |
426,969 |
434,467 |
|||||
Less: Legal Settlement - Early Leasehold Termination |
- |
- |
(10,202) |
|||||
Less: Joint Venture Transaction Costs |
- |
- |
(3,056) |
|||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
- |
(4,528) |
|||||
General and Administrative (Non-GAAP) |
489,397 |
426,969 |
416,681 |
|||||
Taxes Other Than Income |
800,164 |
772,481 |
544,662 |
|||||
Interest Expense, Net |
185,129 |
245,052 |
274,372 |
|||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A |
$ 4,079,085 |
$ 3,911,029 |
$ 3,169,689 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
3,749,704 |
3,435,408 |
3,409,387 |
|||||
Total Operating Cost (Non-GAAP) (excluding Total |
$ 7,828,789 |
$ 7,346,437 |
$ 6,579,076 |
|||||
Exploration Costs |
$ 139,881 |
$ 148,999 |
$ 145,342 |
|||||
Dry Hole Costs |
28,001 |
5,405 |
4,609 |
|||||
Impairments |
517,896 |
347,021 |
479,240 |
|||||
Total Exploration Costs |
685,778 |
501,425 |
629,191 |
|||||
Less: Impairments (Non-GAAP) |
(274,974) |
(152,671) |
(261,452) |
|||||
Total Exploration Costs (Non-GAAP) |
$ 410,804 |
$ 348,754 |
$ 367,739 |
|||||
Total Operating Cost (Non-GAAP) (including Total |
$ 8,239,593 |
$ 7,695,191 |
$ 6,946,815 |
|||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 38.79 |
$ 45.51 |
$ 35.58 |
|||||
Total Cash Operating Cost per Boe (Non-GAAP) |
$ 13.66 |
$ 14.90 |
$ 14.25 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding |
$ 25.13 |
$ 30.61 |
$ 21.33 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding |
$ 26.22 |
$ 27.99 |
$ 29.59 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ 12.57 |
$ 17.52 |
$ 5.99 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 27.60 |
$ 29.32 |
$ 31.24 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ 11.19 |
$ 16.19 |
$ 4.34 |
|||||
EOG RESOURCES, INC. |
||||||||
Cost per Barrel of Oil Equivalent (Boe) |
||||||||
(Unaudited; in thousands, except per Boe amounts) |
||||||||
Year Ended |
||||||||
December 31, |
||||||||
2016 |
2015 |
2014 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
204,929 |
208,862 |
217,073 |
|||||
Crude Oil and Condensate |
$ 4,317,341 |
$ 4,934,562 |
$ 9,742,480 |
|||||
Natural Gas Liquids |
437,250 |
407,658 |
934,051 |
|||||
Natural Gas |
742,152 |
1,061,038 |
1,916,386 |
|||||
Total Wellhead Revenues - (b) |
$ 5,496,743 |
$ 6,403,258 |
$ 12,592,917 |
|||||
Operating Costs |
||||||||
Lease and Well |
$ 927,452 |
$ 1,182,282 |
$ 1,416,413 |
|||||
Transportation Costs |
764,106 |
849,319 |
972,176 |
|||||
Gathering and Processing Costs |
122,901 |
146,156 |
145,800 |
|||||
General and Administrative |
394,815 |
366,594 |
402,010 |
|||||
Less: Voluntary Retirement Expense |
(42,054) |
- |
- |
|||||
Less: Acquisition Costs |
(5,100) |
- |
- |
|||||
Less: Legal Settlement - Early Leasehold Termination |
- |
(19,355) |
- |
|||||
General and Administrative (Non-GAAP) |
347,661 |
347,239 |
402,010 |
|||||
Taxes Other Than Income |
349,710 |
421,744 |
757,564 |
|||||
Interest Expense, Net |
281,681 |
237,393 |
201,458 |
|||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A |
$ 2,793,511 |
$ 3,184,133 |
$ 3,895,421 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
3,553,417 |
3,313,644 |
3,997,041 |
|||||
Total Operating Cost (Non-GAAP) (excluding Total |
$ 6,346,928 |
$ 6,497,777 |
$ 7,892,462 |
|||||
Exploration Costs |
$ 124,953 |
$ 149,494 |
$ 184,388 |
|||||
Dry Hole Costs |
10,657 |
14,746 |
48,490 |
|||||
Impairments |
620,267 |
6,613,546 |
743,575 |
|||||
Total Exploration Costs |
755,877 |
6,777,786 |
976,453 |
|||||
Less: Impairments (Non-GAAP) |
(320,617) |
(6,307,593) |
(824,312) |
|||||
Total Exploration Costs (Non-GAAP) |
$ 435,260 |
$ 470,193 |
$ 152,141 |
|||||
Total Operating Cost (Non-GAAP) (including Total |
$ 6,782,188 |
$ 6,967,970 |
$ 8,044,603 |
|||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 26.82 |
$ 30.66 |
$ 58.01 |
|||||
Total Cash Operating Cost per Boe (Non-GAAP) |
$ 13.64 |
$ 15.25 |
$ 17.95 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding |
$ 13.18 |
$ 15.41 |
$ 40.06 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding |
$ 30.98 |
$ 31.11 |
$ 36.38 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ (4.16) |
$ (0.45) |
$ 21.63 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 33.10 |
$ 33.36 |
$ 37.08 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ (6.28) |
$ (2.70) |
$ 20.93 |
EOG RESOURCES, INC. | |||||||||||
Second Quarter and Full Year 2020 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Second Quarter and Full Year 2020 Forecast |
|||||||||||
The forecast items for the second quarter and full year 2020 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Capital Expenditures |
|||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Transactions. | |||||||||||
(c) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2020 |
Full Year 2020 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
300.0 |
- |
320.0 |
376.0 |
- |
402.0 | |||||
Trinidad |
0.2 |
- |
0.6 |
0.5 |
- |
0.7 | |||||
Other International |
0.0 |
- |
0.2 |
0.0 |
- |
0.2 | |||||
Total |
300.2 |
- |
320.8 |
376.5 |
- |
402.9 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
85.0 |
- |
95.0 |
105.0 |
- |
125.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
870 |
- |
930 |
950 |
- |
1,050 | |||||
Trinidad |
160 |
- |
180 |
170 |
- |
190 | |||||
Other International |
20 |
- |
30 |
20 |
- |
30 | |||||
Total |
1,050 |
- |
1,140 |
1,140 |
- |
1,270 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
530.0 |
- |
570.0 |
639.3 |
- |
702.0 | |||||
Trinidad |
26.9 |
- |
30.6 |
28.8 |
- |
32.4 | |||||
Other International |
3.3 |
- |
5.2 |
3.3 |
- |
5.2 | |||||
Total |
560.2 |
- |
605.8 |
671.4 |
- |
739.6 | |||||
Capital Expenditures ($MM) |
$ |
600 |
- |
$ |
700 |
$ |
3,300 |
- |
$ |
3,700 | |
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2020 |
Full Year 2020 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.65 |
- |
$ |
5.15 |
$ |
4.20 |
- |
$ |
4.80 | |
Transportation Costs |
$ |
3.00 |
- |
$ |
3.40 |
$ |
2.60 |
- |
$ |
3.20 | |
Gathering and Processing |
$ |
2.15 |
- |
$ |
2.35 |
$ |
1.80 |
- |
$ |
2.10 | |
Depreciation, Depletion and Amortization |
$ |
12.10 |
- |
$ |
12.60 |
$ |
11.85 |
- |
$ |
12.85 | |
General and Administrative |
$ |
2.40 |
- |
$ |
2.50 |
$ |
1.90 |
- |
$ |
2.10 | |
Expenses ($MM) |
|||||||||||
Exploration and Dry Hole |
$ |
32 |
- |
$ |
42 |
$ |
130 |
- |
$ |
170 | |
Impairment |
$ |
75 |
- |
$ |
85 |
$ |
300 |
- |
$ |
340 | |
Capitalized Interest |
$ |
5 |
- |
$ |
9 |
$ |
27 |
- |
$ |
33 | |
Net Interest |
$ |
51 |
- |
$ |
55 |
$ |
200 |
- |
$ |
205 | |
Taxes Other Than Income (% of Wellhead Revenue) |
9.0% |
- |
11.0% |
7.0% |
- |
8.0% | |||||
Income Taxes |
|||||||||||
Effective Rate |
19% |
- |
24% |
17% |
- |
22% | |||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(5) |
- |
$ |
35 |
$ |
(110) |
- |
$ |
(70) | |
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(7.75) |
- |
$ |
(2.75) |
$ |
(0.40) |
- |
$ |
1.60 | |
Trinidad - above (below) WTI |
$ |
(12.00) |
- |
$ |
(10.00) |
$ |
(12.00) |
- |
$ |
(10.00) | |
Other International - above (below) WTI |
$ |
26.50 |
- |
$ |
32.50 |
$ |
7.00 |
- |
$ |
12.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
38% |
- |
48% |
30% |
- |
36% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.85) |
- |
$ |
(0.45) |
$ |
(0.85) |
- |
$ |
(0.25) | |
Realizations |
|||||||||||
Trinidad |
$ |
2.90 |
- |
$ |
3.50 |
$ |
2.60 |
- |
$ |
3.30 | |
Other International |
$ |
5.00 |
- |
$ |
5.50 |
$ |
4.45 |
- |
$ |
5.45 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX U.S. New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, April 15, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) today announced that EOG's Board of Directors has changed the company's 2020 annual meeting of stockholders (Annual Meeting) from in-person to virtual-only.
The Annual Meeting will be held on Thursday, April 30, 2020, at 2:00 p.m. Central time (3:00 p.m. Eastern time) via live webcast. Stockholders may access the live webcast of the Annual Meeting at www.virtualshareholdermeeting.com/EOG2020. Stockholders will not be able to attend the Annual Meeting in person.
Stockholders as of the close of business on March 6, 2020, the record date for the Annual Meeting, will be entitled to participate and vote at the Annual Meeting by entering the 16-digit control number found on their proxy card, voting instruction form or notice. Stockholders will also be able to submit questions during the Annual Meeting via the meeting website.
Stockholders are encouraged to vote and submit their proxies in advance of the Annual Meeting by one of the methods described in the proxy materials. If a stockholder has already voted, no additional action is required.
Virtual-Only 2020 Annual Stockholders Meeting
Thursday, April 30, 2020, 2:00 p.m. Central time (3:00 p.m. Eastern time)
The Annual Meeting can be accessed at www.virtualshareholdermeeting.com/EOG2020.
Technical assistance will be available for those attending the meeting.
Proxy Statement and Annual Report
The proxy statement for the Annual Meeting and EOG's 2019 annual report are available at www.proxyvote.com. These materials are also available on EOG's website at http://investors.eogresources.com/Investors. For additional information regarding accessing and participating in the virtual meeting, please refer to EOG's supplemental proxy materials filed with the United States Securities and Exchange Commission on April 15, 2020.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-hold-virtual-only-2020-annual-stockholders-meeting-301041416.html
SOURCE EOG Resources, Inc.
HOUSTON, April 8, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss first quarter 2020 results on Friday, May 8, 2020, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-first-quarter-2020-results-for-may-8-2020-301037805.html
SOURCE EOG Resources, Inc.
HOUSTON, March 16, 2020 /PRNewswire/ --
EOG Resources, Inc. (EOG) today updated its full-year 2020 capital plan as a result of the significant decline and increased volatility of commodity prices.
Exploration and development expenditures for 2020 are now expected to range from $4.3 billion to $4.7 billion, including facilities and gathering, processing and other expenditures, and excluding acquisitions and non‐cash exchanges. Net cash from operating activities is expected to fund both capital expenditures and dividend payments assuming mid-$30 oil prices for the remainder of 2020. The revised capital plan supports full-year 2020 crude oil production of 446,000 to 466,000 barrels of oil per day, approximately flat compared to full-year 2019 levels.
Given the current commodity price environment, EOG has elected to reduce activity across its operating areas. The company plans to focus its drilling operations in the Delaware Basin and South Texas Eagle Ford and continue funding projects that support the long-term value of the company, including targeted infrastructure, exploration and environmental projects.
"Our first priority is to generate high returns with every dollar we spend even at low oil prices," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG's premium drilling strategy is the most strict reinvestment hurdle rate in the industry. With oil around $30 our 2020 premium drilling program is expected to generate more than 30% direct after-tax rate of return. Our commitment to reinvesting at high returns never wavers."
EOG's strategy of maintaining exceptional financial strength leaves it well positioned to sustain its business model through volatile commodity price environments. At December 31, 2019, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 19 percent. Considering $2.0 billion of cash on the balance sheet at the end of the fourth quarter, EOG's net debt-to-total capitalization ratio was 13 percent. For definitions and the reconciliation of non‐GAAP measures to GAAP measures referenced herein, please refer to the attached tables.
"Our business is more resilient today than it has ever been in the company's history," said Thomas. "By significantly improving the economics of our premium inventory, maintaining operational flexibility and strengthening our balance sheet, we are well positioned to weather the storms of low commodity prices."
EOG Resources plans to provide a more comprehensive operational and financial update for the 2020 plan with the release of its first quarter 2020 results.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
EOG RESOURCES, INC. | ||
Reconciliation of Net Debt and Total Capitalization | ||
Calculation of Net Debt-to-Total Capitalization Ratio | ||
(Unaudited; in millions, except ratio data) | ||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||
At | ||
December 31, | ||
2019 | ||
Total Stockholders' Equity - (a) | $ 21,641 | |
Current and Long-Term Debt (GAAP) - (b) | 5,175 | |
Less: Cash | (2,028) | |
Net Debt (Non-GAAP) - (c) | 3,147 | |
Total Capitalization (GAAP) - (a) + (b) | $ 26,816 | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ 24,788 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 19% | |
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 13% |
View original content:http://www.prnewswire.com/news-releases/eog-resources-updates-2020-capital-plan-premium-strategy-proves-resilient-at-low-oil-prices-301024687.html
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 27, 2020 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported fourth quarter 2019 net income of $637 million, or $1.10 per share, compared with fourth quarter 2018 net income of $893 million, or $1.54 per share. Net cash from operating activities for the fourth quarter 2019 was $1.8 billion. For the full year 2019, EOG reported net income of $2.7 billion, or $4.71 per share, compared with net income of $3.4 billion, or $5.89 per share, for the full year 2018. Net cash from operating activities for the full year 2019 was $8.2 billion.
Adjusted non-GAAP net income for the fourth quarter 2019 was $787 million, or $1.35 per share, compared with adjusted non-GAAP net income of $718 million, or $1.24 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2019 was $2.9 billion, or $4.98 per share, compared with adjusted non-GAAP net income of $3.2 billion, or $5.54 per share, for the full year 2018.
Increased crude oil production from high-return operating areas and reductions in per-unit operating costs contributed to EOG's strong fourth quarter 2019 financial results. Adjusted earnings per share, discretionary cash flow and adjusted EBITDAX increased in the fourth quarter 2019 compared with the same prior year period, demonstrating EOG's resiliency and ability to overcome declines in commodity prices. Please refer to the attached tables for definitions and the reconciliation of non-GAAP measures to GAAP measures.
Fourth Quarter and Full Year 2019 Operating Review
Capital efficiency improvements from increased well productivity and cost reductions across EOG's premium plays supported strong operating and financial performance in 2019. United States crude oil volumes grew 15 percent to 455,500 barrels of oil per day (Bopd). Total company natural gas liquids production increased 16 percent, while total company natural gas volumes grew 12 percent.
Total crude oil volumes in the fourth quarter 2019 were 468,900 Bopd, which was above the midpoint of the target range and represents an eight percent increase compared with the same prior year period. Natural gas liquids and natural gas volumes increased by 17 percent and 15 percent, respectively, during this same period. EOG incurred total expenditures of $1.5 billion in the fourth quarter. Total cash capital expenditures before acquisitions of $1.4 billion were below the low end of the target range. Please refer to the attached tables for definitions and the reconciliation of non-GAAP measures to GAAP measures.
EOG continued to lower operating costs during the fourth quarter 2019. Lease and well costs declined 13 percent, transportation costs fell five percent and depreciation, depletion and amortization (DD&A) expenses fell six percent, all on a per-unit basis compared with the same prior-year period. The company also continued to implement sustainable efficiency improvements to reduce well costs. The fourth quarter improvements brought full-year 2019 well cost reductions to seven percent, two percentage points ahead of the target.
EOG generated $2.1 billion of discretionary cash flow in the fourth quarter 2019. After considering total cash capital expenditures before acquisitions of $1.4 billion, EOG generated free cash flow during the fourth quarter 2019 of $723 million. For the full year 2019, EOG generated $8.1 billion of discretionary cash flow and incurred total cash capital expenditures before acquisitions of $6.2 billion, resulting in free cash flow of $1.9 billion. Please refer to the attached tables for definitions and the reconciliation of non-GAAP measures to GAAP measures. As is further explained in the attached reconciliation tables, EOG now defines its free cash flow for a period as its discretionary cash flow for such period less its total cash capital expenditures (before acquisitions) for such period (without regards to the dividends paid in such period). EOG believes this definition of free cash flow is more consistent with that utilized by other companies in the industry.
"Year after year, EOG keeps getting better, delivering record operating performance in 2019. Significant capital efficiency improvements from strong well productivity and sustainable cost reductions allowed us to deliver higher production with less capital investment than we planned at the beginning of the year," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We did this while generating substantial free cash flow, strengthening our financial position and increasing the dividend. This was the third consecutive year since our transition to premium drilling that EOG delivered double-digit returns and production growth along with strong free cash flow."
2020 Capital Plan
The purpose of EOG's annual capital program is to generate high returns on investment and increase the company's business value. Exploration and development expenditures for 2020 are expected to range from $6.3 billion to $6.7 billion, including facilities and gathering, processing and other expenditures, and excluding acquisitions and non-cash exchanges. The disciplined capital program supports growth in crude oil production of 10 to 14 percent in 2020 and funds dividend payments with net cash from operating activities at less than $50 oil.
Due to the decline in crude oil prices, the 2020 capital plan allocates slightly less capital to growing oil production than in 2019. To continue to improve the company, the 2020 plan allocates more capital than in 2019 to fund new high-quality drilling potential and high-return infrastructure to further lower EOG's cost structure and environmental footprint. With the benefit of sustainable cost reductions and operational efficiencies, EOG expects to complete approximately 800 net wells in 2020 compared with 750 net wells in 2019. Activity will remain focused in EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford and Rocky Mountain Area.
"EOG's 2020 capital plan reflects continued improvement in capital efficiency, highlights the resiliency of our business model, and ensures the capital program and dividend payments can be funded at a conservative oil price. Looking to the future, our 2020 plan also invests in new high-return drilling potential and infrastructure development to lower costs and further improve the company," Thomas said. "EOG's sustainable competitive advantages already position us as one of the lowest cost oil producers in the global market and we are poised to extend our cost advantage well into the future."
Dividend Increase
The board of directors declared a dividend of $0.375 per share on EOG's Common Stock, an increase of 30 percent. The dividend will be payable April 30, 2020, to stockholders of record as of April 16, 2020. The indicated annual rate is $1.50 per share.
"EOG's high-return premium drilling program and our low cost structure allow us to continue upholding the commitment we have made to return more cash to shareholders. This latest dividend increase demonstrates the confidence we have in our ability to grow cash flow, generate high returns through our premium well strategy and improve our future inventory with high quality new drilling potential," Thomas said.
Reserves
At year-end 2019, total company net proved reserves were 3,329 million barrels of oil equivalent (MMBoe), a 14 percent increase compared with year-end 2018. Net proved reserve additions from all sources, excluding revisions due to price, replaced 253 percent of EOG's 2019 production at a finding and development cost of $8.21 per barrel of oil equivalent. Revisions due to price decreased net proved reserves by 60 MMBoe and asset divestitures decreased net proved reserves by five MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures please refer to the attached tables.
For the 32nd consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.
Financial Review
EOG further strengthened its financial position during the fourth quarter 2019. At December 31, 2019, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 19 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG's net debt was $3.1 billion for a net debt-to-total capitalization ratio of 13 percent. For definitions and the reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Fourth Quarter 2019 Results Webcast
Friday, February 28, 2020, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG's website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2019, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2019 |
2018 |
2019 |
2018 | ||||||||
Operating Revenues and Other |
$ |
4,320.2 |
$ |
4,574.5 |
$ |
17,380.0 |
$ |
17,275.4 | |||
Net Income |
$ |
636.5 |
$ |
892.8 |
$ |
2,734.9 |
$ |
3,419.0 | |||
Net Income Per Share |
|||||||||||
Basic |
$ |
1.10 |
$ |
1.55 |
$ |
4.73 |
$ |
5.93 | |||
Diluted |
$ |
1.10 |
$ |
1.54 |
$ |
4.71 |
$ |
5.89 | |||
Average Number of Common Shares |
|||||||||||
Basic |
578.2 |
577.0 |
577.7 |
576.6 | |||||||
Diluted |
580.8 |
580.3 |
580.8 |
580.4 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2019 |
2018 |
2019 |
2018 | ||||||||
Operating Revenues and Other |
|||||||||||
Crude Oil and Condensate |
$ |
2,464,274 |
$ |
2,383,326 |
$ |
9,612,532 |
$ |
9,517,440 | |||
Natural Gas Liquids |
215,070 |
266,037 |
784,818 |
1,127,510 | |||||||
Natural Gas |
309,606 |
389,213 |
1,184,095 |
1,301,537 | |||||||
Gains (Losses) on Mark-to-Market Commodity |
(62,347) |
132,095 |
180,275 |
(165,640) | |||||||
Gathering, Processing and Marketing |
1,238,792 |
1,331,105 |
5,360,282 |
5,230,355 | |||||||
Gains on Asset Dispositions, Net |
119,963 |
79,904 |
123,613 |
174,562 | |||||||
Other, Net |
34,888 |
(7,144) |
134,358 |
89,635 | |||||||
Total |
4,320,246 |
4,574,536 |
17,379,973 |
17,275,399 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
334,538 |
346,442 |
1,366,993 |
1,282,678 | |||||||
Transportation Costs |
208,312 |
196,095 |
758,300 |
746,876 | |||||||
Gathering and Processing Costs |
127,615 |
112,396 |
479,102 |
436,973 | |||||||
Exploration Costs |
36,495 |
33,862 |
139,881 |
148,999 | |||||||
Dry Hole Costs |
- |
145 |
28,001 |
5,405 | |||||||
Impairments |
228,135 |
186,087 |
517,896 |
347,021 | |||||||
Marketing Costs |
1,237,259 |
1,349,416 |
5,351,524 |
5,203,243 | |||||||
Depreciation, Depletion and Amortization |
959,208 |
919,963 |
3,749,704 |
3,435,408 | |||||||
General and Administrative |
125,187 |
116,904 |
489,397 |
426,969 | |||||||
Taxes Other Than Income |
199,746 |
190,086 |
800,164 |
772,481 | |||||||
Total |
3,456,495 |
3,451,396 |
13,680,962 |
12,806,053 | |||||||
Operating Income |
863,751 |
1,123,140 |
3,699,011 |
4,469,346 | |||||||
Other Income, Net |
8,152 |
21,220 |
31,385 |
16,704 | |||||||
Income Before Interest Expense and Income Taxes |
871,903 |
1,144,360 |
3,730,396 |
4,486,050 | |||||||
Interest Expense, Net |
40,695 |
56,020 |
185,129 |
245,052 | |||||||
Income Before Income Taxes |
831,208 |
1,088,340 |
3,545,267 |
4,240,998 | |||||||
Income Tax Provision |
194,687 |
195,572 |
810,357 |
821,958 | |||||||
Net Income |
$ |
636,521 |
$ |
892,768 |
$ |
2,734,910 |
$ |
3,419,040 | |||
Dividends Declared per Common Share |
$ |
0.2875 |
$ |
0.2200 |
$ |
1.0825 |
$ |
0.8100 |
EOG RESOURCES, INC. | |||||||||||||||
Operating Highlights | |||||||||||||||
(Unaudited) | |||||||||||||||
Three Months Ended |
Twelve Months Ended |
||||||||||||||
December 31, |
December 31, |
||||||||||||||
2019 |
2018 |
% Change |
2019 |
2018 |
% Change | ||||||||||
Wellhead Volumes and Prices |
|||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||||||
United States |
468.3 |
430.3 |
9% |
455.5 |
394.8 |
15% | |||||||||
Trinidad |
0.5 |
0.8 |
-38% |
0.6 |
0.8 |
-25% | |||||||||
Other International (B) |
0.1 |
4.5 |
-98% |
0.1 |
4.3 |
-98% | |||||||||
Total |
468.9 |
435.6 |
8% |
456.2 |
399.9 |
14% | |||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||||||
United States |
$ |
57.14 |
$ |
59.37 |
-4% |
$ |
57.74 |
$ |
65.16 |
-11% | |||||
Trinidad |
46.73 |
51.80 |
-10% |
47.16 |
57.26 |
-18% | |||||||||
Other International (B) |
53.76 |
70.44 |
-24% |
57.40 |
71.45 |
-20% | |||||||||
Composite |
57.13 |
59.47 |
-4% |
57.72 |
65.21 |
-11% | |||||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||||||
United States |
144.0 |
122.8 |
17% |
134.1 |
116.1 |
16% | |||||||||
Other International (B) |
- |
- |
- |
- |
|||||||||||
Total |
144.0 |
122.8 |
17% |
134.1 |
116.1 |
16% | |||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||||||
United States |
$ |
16.23 |
$ |
23.54 |
-31% |
$ |
16.03 |
$ |
26.60 |
-40% | |||||
Other International (B) |
- |
- |
- |
- |
|||||||||||
Composite |
16.23 |
23.54 |
-31% |
16.03 |
26.60 |
-40% | |||||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||||||
United States |
1,148 |
974 |
18% |
1,069 |
923 |
16% | |||||||||
Trinidad |
242 |
230 |
5% |
260 |
266 |
-2% | |||||||||
Other International (B) |
35 |
32 |
9% |
37 |
30 |
23% | |||||||||
Total |
1,425 |
1,236 |
15% |
1,366 |
1,219 |
12% | |||||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||||||
United States |
$ |
2.20 |
$ |
3.50 |
-37% |
$ |
2.22 |
$ |
2.88 |
-23% | |||||
Trinidad |
2.78 |
3.03 |
-8% |
2.72 |
2.94 |
-7% | |||||||||
Other International (B) |
4.88 |
4.02 |
22% |
4.44 |
4.08 |
9% | |||||||||
Composite |
2.36 |
3.42 |
-31% |
2.38 |
2.92 |
-19% | |||||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||||||
United States |
803.6 |
715.5 |
12% |
767.8 |
664.7 |
16% | |||||||||
Trinidad |
40.9 |
39.0 |
5% |
44.0 |
45.1 |
-2% | |||||||||
Other International (B) |
5.8 |
10.0 |
-42% |
6.2 |
9.4 |
-34% | |||||||||
Total |
850.3 |
764.5 |
11% |
818.0 |
719.2 |
14% | |||||||||
Total MMBoe (D) |
78.2 |
70.3 |
11% |
298.6 |
262.5 |
14% | |||||||||
(A) Thousand barrels per day or million cubic feet per day, as applicable. |
|||||||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. |
|||||||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2019). |
|||||||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
December 31, |
December 31, | ||||
2019 |
2018 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
2,027,972 |
$ |
1,555,634 | |
Accounts Receivable, Net |
2,001,658 |
1,915,215 | |||
Inventories |
767,297 |
859,359 | |||
Assets from Price Risk Management Activities |
1,299 |
23,806 | |||
Income Taxes Receivable |
151,665 |
427,909 | |||
Other |
323,448 |
275,467 | |||
Total |
5,273,339 |
5,057,390 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
62,830,415 |
57,330,016 | |||
Other Property, Plant and Equipment |
4,472,246 |
4,220,665 | |||
Total Property, Plant and Equipment |
67,302,661 |
61,550,681 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(36,938,066) |
(33,475,162) | |||
Total Property, Plant and Equipment, Net |
30,364,595 |
28,075,519 | |||
Deferred Income Taxes |
2,363 |
777 | |||
Other Assets |
1,484,311 |
800,788 | |||
Total Assets |
$ |
37,124,608 |
$ |
33,934,474 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
2,429,127 |
$ |
2,239,850 | |
Accrued Taxes Payable |
254,850 |
214,726 | |||
Dividends Payable |
166,273 |
126,971 | |||
Liabilities from Price Risk Management Activities |
20,194 |
- | |||
Current Portion of Long-Term Debt |
1,014,524 |
913,093 | |||
Current Portion of Operating Lease Liabilities |
369,365 |
- | |||
Other |
232,655 |
233,724 | |||
Total |
4,486,988 |
3,728,364 | |||
Long-Term Debt |
4,160,919 |
5,170,169 | |||
Other Liabilities |
1,789,884 |
1,258,355 | |||
Deferred Income Taxes |
5,046,101 |
4,413,398 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and |
205,822 |
205,804 | |||
Additional Paid in Capital |
5,817,475 |
5,658,794 | |||
Accumulated Other Comprehensive Loss |
(4,652) |
(1,358) | |||
Retained Earnings |
15,648,604 |
13,543,130 | |||
Common Stock Held in Treasury, 298,820 Shares and |
(26,533) |
(42,182) | |||
Total Stockholders' Equity |
21,640,716 |
19,364,188 | |||
Total Liabilities and Stockholders' Equity |
$ |
37,124,608 |
$ |
33,934,474 |
EOG RESOURCES, INC. | |||||||||||
Summary Statements of Cash Flows | |||||||||||
(Unaudited; in thousands) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2019 |
2018 |
2019 |
2018 | ||||||||
Cash Flows from Operating Activities |
|||||||||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
|||||||||||
Net Income |
$ |
636,521 |
$ |
892,768 |
$ |
2,734,910 |
$ |
3,419,040 | |||
Items Not Requiring (Providing) Cash |
|||||||||||
Depreciation, Depletion and Amortization |
959,208 |
919,963 |
3,749,704 |
3,435,408 | |||||||
Impairments |
228,135 |
186,087 |
517,896 |
347,021 | |||||||
Stock-Based Compensation Expenses |
42,415 |
39,047 |
174,738 |
155,337 | |||||||
Deferred Income Taxes |
123,082 |
212,454 |
631,658 |
894,156 | |||||||
Gains on Asset Dispositions, Net |
(119,963) |
(79,904) |
(123,613) |
(174,562) | |||||||
Other, Net |
341 |
(8,248) |
4,496 |
7,066 | |||||||
Dry Hole Costs |
- |
145 |
28,001 |
5,405 | |||||||
Mark-to-Market Commodity Derivative Contracts |
|||||||||||
Total (Gains) Losses |
62,347 |
(132,095) |
(180,275) |
165,640 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
91,521 |
(78,678) |
231,229 |
(258,906) | |||||||
Other, Net |
(253) |
1,456 |
962 |
3,108 | |||||||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||||||||
Accounts Receivable |
(85,937) |
185,349 |
(91,792) |
(368,180) | |||||||
Inventories |
34,686 |
(108,591) |
90,284 |
(395,408) | |||||||
Accounts Payable |
34,286 |
(98,178) |
168,539 |
439,347 | |||||||
Accrued Taxes Payable |
(47,925) |
(55,570) |
40,122 |
(92,461) | |||||||
Other Assets |
(36,572) |
(22,101) |
358,001 |
(125,435) | |||||||
Other Liabilities |
(38,304) |
25,725 |
(56,619) |
10,949 | |||||||
Changes in Components of Working Capital Associated with Investing and Financing |
(76,384) |
205,599 |
(115,061) |
301,083 | |||||||
Net Cash Provided by Operating Activities |
1,807,204 |
2,085,228 |
8,163,180 |
7,768,608 | |||||||
Investing Cash Flows |
|||||||||||
Additions to Oil and Gas Properties |
(1,285,003) |
(1,267,362) |
(6,151,885) |
(5,839,294) | |||||||
Additions to Other Property, Plant and Equipment |
(83,291) |
(34,797) |
(270,641) |
(237,181) | |||||||
Proceeds from Sales of Assets |
104,883 |
215,864 |
140,292 |
227,446 | |||||||
Other Investing Activities |
(10,000) |
- |
(10,000) |
(19,993) | |||||||
Changes in Components of Working Capital Associated with Investing Activities |
76,384 |
(205,599) |
115,061 |
(301,140) | |||||||
Net Cash Used in Investing Activities |
(1,197,027) |
(1,291,894) |
(6,177,173) |
(6,170,162) | |||||||
Financing Cash Flows |
|||||||||||
Long-Term Debt Repayments |
- |
(350,000) |
(900,000) |
(350,000) | |||||||
Dividends Paid |
(167,349) |
(126,970) |
(588,200) |
(438,045) | |||||||
Treasury Stock Purchased |
(2,914) |
(4,898) |
(25,152) |
(63,456) | |||||||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
8,388 |
8,462 |
17,946 |
20,560 | |||||||
Debt Issuance Costs |
- |
- |
(5,016) |
- | |||||||
Repayment of Finance Lease Obligation |
(3,261) |
(3,167) |
(12,899) |
(8,219) | |||||||
Changes in Components of Working Capital Associated with Financing Activities |
- |
- |
- |
57 | |||||||
Net Cash Used in Financing Activities |
(165,136) |
(476,573) |
(1,513,321) |
(839,103) | |||||||
Effect of Exchange Rate Changes on Cash |
(174) |
(35,259) |
(348) |
(37,937) | |||||||
Increase in Cash and Cash Equivalents |
444,867 |
281,502 |
472,338 |
721,406 | |||||||
Cash and Cash Equivalents at Beginning of Period |
1,583,105 |
1,274,132 |
1,555,634 |
834,228 | |||||||
Cash and Cash Equivalents at End of Period |
$ |
2,027,972 |
$ |
1,555,634 |
$ |
2,027,972 |
$ |
1,555,634 |
EOG RESOURCES, INC. | ||||||||||||||
Fourth Quarter 2019 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells On Line |
Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross |
Net |
Lateral Length (ft) |
Crude Oil and Condensate (Bbld) (A) |
Natural Gas Liquids (Bbld) (A) |
Natural Gas (MMcfd) (A) |
Crude Oil Equivalent (Boed) (B) | ||||||||
Delaware Basin |
||||||||||||||
Wolfcamp |
23 |
20 |
9,400 |
2,500 |
750 |
3.7 |
3,850 | |||||||
Bone Spring |
17 |
15 |
8,000 |
1,850 |
450 |
2.3 |
2,700 | |||||||
Leonard |
11 |
11 |
8,000 |
2,350 |
900 |
4.6 |
4,000 | |||||||
South Texas Eagle Ford |
67 |
64 |
7,400 |
1,100 |
150 |
0.6 |
1,350 | |||||||
South Texas Austin Chalk |
9 |
9 |
6,100 |
1,650 |
300 |
1.4 |
2,200 | |||||||
Powder River Basin |
||||||||||||||
Turner / Parkman |
7 |
6 |
8,900 |
900 |
150 |
3.5 |
1,650 | |||||||
Niobrara |
1 |
1 |
8,800 |
950 |
50 |
0.7 |
1,100 | |||||||
DJ Basin Codell / Niobrara |
12 |
11 |
11,400 |
850 |
50 |
0.4 |
950 | |||||||
Williston Basin Bakken/Three Forks |
6 |
5 |
10,100 |
2,250 |
250 |
1.9 |
2,800 | |||||||
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Reconciliation of Adjusted Net Income | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net gains on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG's assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
December 31, 2019 |
December 31, 2018 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (GAAP) |
$ 831,208 |
$(194,687) |
$ 636,521 |
$ 1.10 |
$1,088,340 |
$(195,572) |
$ 892,768 |
$ 1.54 | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
62,347 |
(13,684) |
48,663 |
0.08 |
(132,095) |
29,096 |
(102,999) |
(0.18) | |||||||
Net Cash Received from (Payments for) |
91,521 |
(20,087) |
71,434 |
0.12 |
(78,678) |
17,330 |
(61,348) |
(0.11) | |||||||
Less: Gains on Asset Dispositions, Net |
(119,963) |
26,342 |
(93,621) |
(0.16) |
(79,904) |
13,625 |
(66,279) |
(0.11) | |||||||
Add: Impairments |
158,725 |
(34,837) |
123,888 |
0.21 |
131,795 |
(29,031) |
102,764 |
0.18 | |||||||
Less: Tax Reform Impact |
- |
- |
- |
- |
- |
(46,684) |
(46,684) |
(0.08) | |||||||
Adjustments to Net Income |
192,630 |
(42,266) |
150,364 |
0.25 |
(158,882) |
(15,664) |
(174,546) |
(0.30) | |||||||
Adjusted Net Income (Non-GAAP) |
$1,023,838 |
$(236,953) |
$ 786,885 |
$ 1.35 |
$ 929,458 |
$(211,236) |
$ 718,222 |
$ 1.24 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
578,219 |
577,035 | |||||||||||||
Diluted |
580,849 |
580,288 | |||||||||||||
Twelve Months Ended |
Twelve Months Ended | ||||||||||||||
December 31, 2019 |
December 31, 2018 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (GAAP) |
$3,545,267 |
$(810,357) |
$2,734,910 |
$ 4.71 |
$4,240,998 |
$(821,958) |
$3,419,040 |
$ 5.89 | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
(180,275) |
39,567 |
(140,708) |
(0.24) |
165,640 |
(36,486) |
129,154 |
0.22 | |||||||
Net Cash Received from (Payments for) |
231,229 |
(50,750) |
180,479 |
0.31 |
(258,906) |
57,029 |
(201,877) |
(0.35) | |||||||
Less: Gains on Asset Dispositions, Net |
(123,613) |
27,252 |
(96,361) |
(0.17) |
(174,562) |
37,860 |
(136,702) |
(0.24) | |||||||
Add: Impairments |
274,974 |
(60,351) |
214,623 |
0.37 |
152,671 |
(33,629) |
119,042 |
0.21 | |||||||
Less: Tax Reform Impact |
- |
- |
- |
- |
- |
(110,335) |
(110,335) |
(0.19) | |||||||
Adjustments to Net Income |
202,315 |
(44,282) |
158,033 |
0.27 |
(115,157) |
(85,561) |
(200,718) |
(0.35) | |||||||
Adjusted Net Income (Non-GAAP) |
$3,747,582 |
$(854,639) |
$2,892,943 |
$ 4.98 |
$4,125,841 |
$(907,519) |
$3,218,322 |
$ 5.54 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
577,670 |
576,578 | |||||||||||||
Diluted |
580,777 |
580,441 |
EOG RESOURCES, INC. | ||||||||||||||
Reconciliation of Discretionary Cash Flow | ||||||||||||||
(Unaudited; in thousands) | ||||||||||||||
Calculation of Free Cash Flow | ||||||||||||||
(Unaudited; in thousands) | ||||||||||||||
The following chart reconciles the three-month periods ended December 31, 2019 and 2018 and twelve-month periods ended December 31, 2019, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net (Payable) Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the three months ended December 31, 2019 and 2018 and twelve months ended December 31, 2019, 2018 and 2017. EOG management uses this information for comparative purposes within the industry. | ||||||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||||||
December 31, |
December 31, | |||||||||||||
2019 |
2018 |
2019 |
2018 |
2017 | ||||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,807,204 |
$ |
2,085,228 |
$ |
8,163,180 |
$ |
7,768,608 |
$ |
4,265,336 | ||||
Adjustments: |
||||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
28,483 |
27,270 |
113,733 |
123,986 |
122,688 | |||||||||
Other Non-Current Income Taxes - Net (Payable) Receivable |
59,174 |
86,572 |
238,711 |
148,993 |
(513,404) | |||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||||
and Liabilities |
||||||||||||||
Accounts Receivable |
85,937 |
(185,349) |
91,792 |
368,180 |
392,131 | |||||||||
Inventories |
(34,686) |
108,591 |
(90,284) |
395,408 |
174,548 | |||||||||
Accounts Payable |
(34,286) |
98,178 |
(168,539) |
(439,347) |
(324,192) | |||||||||
Accrued Taxes Payable |
47,925 |
55,570 |
(40,122) |
92,461 |
63,937 | |||||||||
Other Assets |
36,572 |
22,101 |
(358,001) |
125,435 |
658,609 | |||||||||
Other Liabilities |
38,304 |
(25,725) |
56,619 |
(10,949) |
89,871 | |||||||||
Changes in Components of Working Capital Associated with |
||||||||||||||
Investing and Financing Activities |
76,384 |
(205,599) |
115,061 |
(301,083) |
(89,992) | |||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
2,111,011 |
$ |
2,066,837 |
$ |
8,122,150 |
$ |
8,271,692 |
$ |
4,839,532 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease |
2% |
-2% |
71% |
|||||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
2,111,011 |
$ |
2,066,837 |
$ |
8,122,150 |
$ |
8,271,692 |
4,839,532 | |||||
Less: |
||||||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) |
(1,388,233) |
(1,302,999) |
(6,234,454) |
(6,172,950) |
(4,228,859) | |||||||||
Free Cash Flow (Non-GAAP)(b) |
$ |
722,778 |
$ |
763,838 |
$ |
1,887,696 |
$ |
2,098,742 |
$ |
610,673 | ||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the three-month periods ended December 31, 2019 and 2018 and twelve-month periods ended December 31, 2019, 2018 and 2017: | ||||||||||||||
Total Expenditures (GAAP) |
$ |
1,506,061 |
$ |
1,504,438 |
$ |
6,900,450 |
$ |
6,706,359 |
$ |
4,612,746 | ||||
Less: |
||||||||||||||
Asset Retirement Costs |
(34,537) |
(27,910) |
(186,088) |
(69,699) |
(55,592) | |||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment |
(1,680) |
(547) |
(2,266) |
(49,484) |
- | |||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(33,317) |
(128,719) |
(97,704) |
(290,542) |
(255,711) | |||||||||
Acquisition Costs of Proved Properties |
(48,294) |
(44,263) |
(379,938) |
(123,684) |
(72,584) | |||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
$ |
1,388,233 |
$ |
1,302,999 |
$ |
6,234,454 |
$ |
6,172,950 |
4,228,859 | |||||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item for the three-month and twelve-month periods ending December 31, 2019. The comparative prior periods have been revised for this change in presentation. | ||||||||||||||
Maintenance Capital Expenditures | ||||||||||||||
The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays. |
EOG RESOURCES, INC. | ||||||||
Reconciliation of Discretionary Cash Flow | ||||||||
(Unaudited; in thousands) | ||||||||
Calculation of Free Cash Flow | ||||||||
(Unaudited; in thousands) | ||||||||
The following chart reconciles the twelve-month periods ended December 31, 2014, 2013 and 2012 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (before acquisitions) incurred (Non-GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2014, 2013 and 2012. EOG management uses this information for comparative purposes within the industry. | ||||||||
Twelve Months Ended | ||||||||
December 31, | ||||||||
2014 |
2013 |
2012 | ||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
8,649,155 |
$ |
7,329,414 |
$ |
5,236,777 | ||
Adjustments: |
||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
157,453 |
134,531 |
159,182 | |||||
Excess Tax Benefits from Stock-Based Compensation |
99,459 |
55,831 |
67,035 | |||||
Changes in Components of Working Capital and Other Assets |
||||||||
and Liabilities |
||||||||
Accounts Receivable |
(84,982) |
23,613 |
178,683 | |||||
Inventories |
161,958 |
(53,402) |
156,762 | |||||
Accounts Payable |
(543,630) |
(178,701) |
17,150 | |||||
Accrued Taxes Payable |
(16,486) |
(75,142) |
(78,094) | |||||
Other Assets |
14,448 |
109,567 |
118,520 | |||||
Other Liabilities |
(75,420) |
20,382 |
(36,114) | |||||
Changes in Components of Working Capital Associated with |
||||||||
Investing and Financing Activities |
103,414 |
51,361 |
(74,158) | |||||
Discretionary Cash Flow (Non-GAAP) |
$ |
8,465,369 |
$ |
7,417,454 |
$ |
5,745,743 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
14% |
29% |
||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
8,465,369 |
$ |
7,417,454 |
5,745,743 | |||
Less: |
||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) |
(8,292,090) |
(7,101,791) |
(7,539,994) | |||||
Free Cash Flow (Non-GAAP)(b) |
$ |
173,279 |
$ |
315,663 |
$ |
(1,794,251) | ||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) for the twelve-month periods ended December 31, 2014, 2013 and 2012: | ||||||||
Total Expenditures (GAAP) |
$ |
8,631,906 |
$ |
7,361,457 |
$ |
7,753,828 | ||
Less: |
||||||||
Asset Retirement Costs |
(195,630) |
(134,445) |
(126,987) | |||||
Non-Cash Expenditures of Other Property, Plant and Equipment |
- |
- |
(65,791) | |||||
Non-Cash Acquisition Costs of Unproved Properties |
(5,085) |
(5,007) |
(20,317) | |||||
Acquisition Costs of Proved Properties |
(139,101) |
(120,214) |
(739) | |||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) |
$ |
8,292,090 |
$ |
7,101,791 |
$ |
7,539,994 | ||
(b) To better align the presentation of free cash flow for comparative purposes within the industry, free cash flow has been updated to exclude dividends paid (GAAP) as a reconciling item. The comparative prior periods presented herein have been revised for this change in presentation. | ||||||||
Maintenance Capital Expenditures | ||||||||
The capital expenditures required to fund drilling as well as infrastructure requirements to keep oil production flat relative to 2019 across all premium oil plays. |
EOG RESOURCES, INC. | ||||||||||
Total Expenditures | ||||||||||
(Unaudited; in millions) | ||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||
December 31, |
December 31, | |||||||||
2019 |
2018 |
2019 |
2018 |
2017 | ||||||
Exploration and Development Drilling |
$1,086 |
$1,092 |
$4,951 |
$4,935 |
$3,132 | |||||
Facilities |
130 |
107 |
629 |
625 |
575 | |||||
Leasehold Acquisitions |
75 |
157 |
276 |
488 |
427 | |||||
Property Acquisitions |
48 |
45 |
380 |
124 |
73 | |||||
Capitalized Interest |
10 |
6 |
38 |
24 |
27 | |||||
Subtotal |
1,349 |
1,407 |
6,274 |
6,196 |
4,234 | |||||
Exploration Costs |
37 |
34 |
140 |
149 |
145 | |||||
Dry Hole Costs |
- |
- |
28 |
5 |
5 | |||||
Exploration and Development Expenditures |
1,386 |
1,441 |
6,442 |
6,350 |
4,384 | |||||
Asset Retirement Costs |
35 |
28 |
186 |
70 |
56 | |||||
Total Exploration and Development Expenditures |
1,421 |
1,469 |
6,628 |
6,420 |
4,440 | |||||
Other Property, Plant and Equipment |
85 |
35 |
272 |
286 |
173 | |||||
Total Expenditures |
$1,506 |
$1,504 |
$6,900 |
$6,706 |
$4,613 |
EOG RESOURCES, INC. | |||||||||||
Reconciliation of Adjusted EBITDAX | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the gains on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2019 |
2018 |
2019 |
2018 | ||||||||
Net Income (GAAP) |
$ |
636,521 |
$ |
892,768 |
$ |
2,734,910 |
$ |
3,419,040 | |||
Adjustments: |
|||||||||||
Interest Expense, Net |
40,695 |
56,020 |
185,129 |
245,052 | |||||||
Income Tax Provision |
194,687 |
195,572 |
810,357 |
821,958 | |||||||
Depreciation, Depletion and Amortization |
959,208 |
919,963 |
3,749,704 |
3,435,408 | |||||||
Exploration Costs |
36,495 |
33,862 |
139,881 |
148,999 | |||||||
Dry Hole Costs |
- |
145 |
28,001 |
5,405 | |||||||
Impairments |
228,135 |
186,087 |
517,896 |
347,021 | |||||||
EBITDAX (Non-GAAP) |
2,095,741 |
2,284,417 |
8,165,878 |
8,422,883 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
62,347 |
(132,095) |
(180,275) |
165,640 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity |
91,521 |
(78,678) |
231,229 |
(258,906) | |||||||
Gains on Asset Dispositions, Net |
(119,963) |
(79,904) |
(123,613) |
(174,562) | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
2,129,646 |
$ |
1,993,740 |
$ |
8,093,219 |
$ |
8,155,055 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease |
7% |
-1% |
EOG RESOURCES, INC. | ||||||||
Reconciliation of Net Debt and Total Capitalization | ||||||||
Calculation of Net Debt-to-Total Capitalization Ratio | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||||||
At | ||||||||
December 31, | ||||||||
2019 |
2018 |
2017 |
2016 | |||||
Total Stockholders' Equity - (a) |
$21,641 |
$19,364 |
$16,283 |
$13,982 | ||||
Current and Long-Term Debt (GAAP) - (b) |
5,175 |
6,083 |
6,387 |
6,986 | ||||
Less: Cash |
(2,028) |
(1,556) |
(834) |
(1,600) | ||||
Net Debt (Non-GAAP) - (c) |
3,147 |
4,527 |
5,553 |
5,386 | ||||
Total Capitalization (GAAP) - (a) + (b) |
$26,816 |
$25,447 |
$22,670 |
$20,968 | ||||
Total Capitalization (Non-GAAP) - (a) + (c) |
$24,788 |
$23,891 |
$21,836 |
$19,368 | ||||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
19% |
24% |
28% |
33% | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
13% |
19% |
25% |
28% |
EOG RESOURCES, INC. | ||||||||
Reserves Supplemental Data | ||||||||
(Unaudited) | ||||||||
2019 NET PROVED RESERVES RECONCILIATION SUMMARY |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
CRUDE OIL AND CONDENSATE (MMBbl) |
||||||||
Beginning Reserves |
1,531.7 |
0.4 |
0.2 |
1,532.3 |
||||
Revisions |
(43.0) |
0.1 |
- |
(42.9) |
||||
Purchases in Place |
2.9 |
- |
- |
2.9 |
||||
Extensions, Discoveries and Other Additions |
370.0 |
- |
- |
370.0 |
||||
Sales in Place |
(1.3) |
- |
- |
(1.3) |
||||
Production |
(166.3) |
(0.2) |
(0.1) |
(166.6) |
||||
Ending Reserves |
1,694.0 |
0.3 |
0.1 |
1,694.4 |
||||
NATURAL GAS LIQUIDS (MMBbl) |
||||||||
Beginning Reserves |
614.3 |
- |
- |
614.3 |
||||
Revisions |
5.4 |
- |
- |
5.4 |
||||
Purchases in Place |
2.0 |
- |
- |
2.0 |
||||
Extensions, Discoveries and Other Additions |
167.8 |
- |
- |
167.8 |
||||
Sales in Place |
(0.9) |
- |
- |
(0.9) |
||||
Production |
(48.9) |
- |
- |
(48.9) |
||||
Ending Reserves |
739.7 |
- |
- |
739.7 |
||||
NATURAL GAS (Bcf) |
||||||||
Beginning Reserves |
4,390.6 |
237.0 |
59.6 |
4,687.2 |
||||
Revisions |
(184.4) |
47.0 |
2.6 |
(134.8) |
||||
Purchases in Place |
71.7 |
- |
- |
71.7 |
||||
Extensions, Discoveries and Other Additions |
1,175.9 |
87.5 |
9.7 |
1,273.1 |
||||
Sales in Place |
(14.5) |
- |
- |
(14.5) |
||||
Production |
(404.5) |
(95.4) |
(13.1) |
(513.0) |
||||
Ending Reserves |
5,034.8 |
276.1 |
58.8 |
5,369.7 |
||||
OIL EQUIVALENTS (MMBoe) |
||||||||
Beginning Reserves |
2,877.8 |
39.9 |
10.1 |
2,927.8 |
||||
Revisions |
(68.3) |
7.9 |
0.4 |
(60.0) |
||||
Purchases in Place |
16.8 |
- |
- |
16.8 |
||||
Extensions, Discoveries and Other Additions |
733.7 |
14.6 |
1.7 |
750.0 |
||||
Sales in Place |
(4.6) |
- |
- |
(4.6) |
||||
Production |
(282.6) |
(16.1) |
(2.2) |
(300.9) |
||||
Ending Reserves |
3,272.8 |
46.3 |
10.0 |
3,329.1 |
||||
Net Proved Developed Reserves (MMBoe) |
||||||||
At December 31, 2018 |
1,503.4 |
37.7 |
7.0 |
1,548.1 |
||||
At December 31, 2019 |
1,684.2 |
29.9 |
7.1 |
1,721.2 |
||||
2019 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Acquisition Cost of Unproved Properties |
$ 276.1 |
$ - |
$ - |
$ 276.1 |
||||
Exploration Costs |
213.5 |
46.6 |
13.2 |
273.3 |
||||
Development Costs |
5,480.7 |
24.0 |
8.1 |
5,512.8 |
||||
Total Drilling |
5,970.3 |
70.6 |
21.3 |
6,062.2 |
||||
Acquisition Cost of Proved Properties |
379.9 |
- |
- |
379.9 |
||||
Asset Retirement Costs |
181.1 |
1.0 |
4.0 |
186.1 |
||||
Total Exploration and Development Expenditures |
6,531.3 |
71.6 |
25.3 |
6,628.2 |
||||
Gathering, Processing and Other |
269.7 |
2.4 |
0.1 |
272.2 |
||||
Total Expenditures |
6,801.0 |
74.0 |
25.4 |
6,900.4 |
||||
Proceeds from Sales in Place |
(140.3) |
- |
- |
(140.3) |
||||
Net Expenditures |
$6,660.7 |
$ 74.0 |
$ 25.4 |
$6,760.1 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe ) * |
||||||||
All-in Total, Net of Revisions |
$ 9.09 |
$ 3.14 |
$ 10.14 |
$ 8.90 |
||||
All-in Total, Excluding Revisions Due to Price |
$ 8.36 |
$ 3.14 |
$ 10.14 |
$ 8.21 |
||||
RESERVE REPLACEMENT * |
||||||||
Drilling Only |
260% |
91% |
77% |
249% |
||||
All-in Total, Net of Revisions and Dispositions |
240% |
140% |
95% |
233% |
||||
All-in Total, Excluding Revisions Due to Price |
261% |
140% |
95% |
253% |
||||
All-in Total, Liquids |
234% |
50% |
0% |
233% |
||||
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. | ||||||||
Reconciliation of Total Exploration and Development Expenditures | ||||||||
Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflects total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||
For the Twelve Months Ended December 31, 2019 |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$6,531.3 |
$ 71.6 |
$ 25.3 |
$6,628.2 |
||||
Less: Asset Retirement Costs |
(181.1) |
(1.0) |
(4.0) |
(186.1) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
- |
- |
(97.7) |
||||
Total Acquisition Cost of Proved Properties |
(379.9) |
- |
- |
(379.9) |
||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) |
$5,872.6 |
$ 70.6 |
$ 21.3 |
$5,964.5 |
||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$6,531.3 |
$ 71.6 |
$ 25.3 |
$6,628.2 |
||||
Less: Asset Retirement Costs |
(181.1) |
(1.0) |
(4.0) |
(186.1) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
- |
- |
(97.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(52.3) |
- |
- |
(52.3) |
||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) |
$6,200.2 |
$ 70.6 |
$ 21.3 |
$6,292.1 |
||||
Total Expenditures (GAAP) |
$6,801.0 |
$ 74.0 |
$ 25.4 |
$6,900.4 |
||||
Less: Asset Retirement Costs |
(181.1) |
(1.0) |
(4.0) |
(186.1) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
- |
- |
(97.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(52.3) |
- |
- |
(52.3) |
||||
Non-Cash Capital - Other Miscellaneous |
(1.6) |
- |
- |
(1.6) |
||||
Total Cash Expenditures (Non-GAAP) |
$6,468.3 |
$ 73.0 |
$ 21.4 |
$6,562.7 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||
Revisions Due to Price - (c) |
(59.7) |
- |
- |
(59.7) |
||||
Revisions Other Than Price |
(8.6) |
7.9 |
0.4 |
(0.3) |
||||
Purchases in Place |
16.8 |
- |
- |
16.8 |
||||
Extensions, Discoveries and Other Additions - (d) |
733.7 |
14.6 |
1.7 |
750.0 |
||||
Total Proved Reserve Additions - (e) |
682.2 |
22.5 |
2.1 |
706.8 |
||||
Sales in Place |
(4.6) |
- |
- |
(4.6) |
||||
Net Proved Reserve Additions From All Sources - (f) |
677.6 |
22.5 |
2.1 |
702.2 |
||||
Production - (g) |
282.6 |
16.1 |
2.2 |
300.9 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Drilling, Before Revisions - (a / d) |
$ 8.00 |
$ 4.84 |
$ 12.53 |
$ 7.95 |
||||
All-in Total, Net of Revisions - (b / e) |
$ 9.09 |
$ 3.14 |
$ 10.14 |
$ 8.90 |
||||
All-in Total, Excluding Revisions Due to Price - (b / (e - c)) |
$ 8.36 |
$ 3.14 |
$ 10.14 |
$ 8.21 |
||||
RESERVE REPLACEMENT |
||||||||
Drilling Only - (d / g) |
260% |
91% |
77% |
249% |
||||
All-in Total, Net of Revisions and Dispositions - (f / g) |
240% |
140% |
95% |
233% |
||||
All-in Total, Excluding Revisions Due to Price - ((f - c ) / g) |
261% |
140% |
95% |
253% |
||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
||||||||
Revisions |
(37.6) |
0.1 |
- |
(37.5) |
||||
Purchases in Place |
4.9 |
- |
- |
4.9 |
||||
Extensions, Discoveries and Other Additions - (h) |
537.8 |
- |
- |
537.8 |
||||
Total Proved Reserve Additions |
505.1 |
0.1 |
- |
505.2 |
||||
Sales in Place |
(2.2) |
- |
- |
(2.2) |
||||
Net Proved Reserve Additions From All Sources - (i) |
502.9 |
0.1 |
- |
503.0 |
||||
Production - (j) |
215.2 |
0.2 |
0.1 |
215.5 |
||||
RESERVE REPLACEMENT - LIQUIDS |
||||||||
Drilling Only - (h / j) |
250% |
0% |
0% |
250% |
||||
All-in Total, Net of Revisions & Dispositions - (i / j) |
234% |
50% |
0% |
233% |
||||
EOG RESOURCES, INC. | ||||||||
Reconciliation of Drillbit Exploration and Development Expenditures | ||||||||
Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. | ||||||||
For the Twelve Months Ended December 31, 2019 |
||||||||
Total |
||||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$6,628.2 |
|||||||
Less: Asset Retirement Costs |
(186.1) |
|||||||
Acquisition Costs of Unproved Properties |
(276.1) |
|||||||
Acquisition Cost of Proved Properties |
(379.9) |
|||||||
Drillbit Exploration and Development Expenditures (Non-GAAP) - (k) |
$5,786.1 |
|||||||
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) |
750.0 |
|||||||
Add: Conversion of Proved Undeveloped Reserves to Proved Developed |
302.0 |
|||||||
Less: Proved Undeveloped Extensions and Discoveries |
(578.3) |
|||||||
Proved Developed Reserves - Extensions and Discoveries (MMBoe) |
473.7 |
|||||||
Total Proved Reserves - Revisions (MMBoe) |
(60.0) |
|||||||
Less: Proved Undeveloped Reserves - Revisions |
49.8 |
|||||||
Proved Developed - Revisions Due to Price |
59.7 |
|||||||
Proved Developed Reserves - Revisions Other Than Price (MMBoe) |
49.5 |
|||||||
Proved Developed Reserves - Extensions and discoveries plus Revisions |
||||||||
Other than Price (MMBoe) - (l) |
523.2 |
|||||||
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) - (k / l) |
$ 11.06 |
EOG RESOURCES, INC. | ||||||||||||
Reconciliation of Total Exploration and Development Expenditures | ||||||||||||
For Drilling Only and Total Exploration and Development Expenditures | ||||||||||||
Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||||||
2019 |
2018 |
2017 |
2016 |
2015 |
2014 | |||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,628.2 |
$6,419.7 |
$4,439.4 |
$6,445.2 |
$4,928.3 |
$7,904.8 | ||||||
Less: Asset Retirement Costs |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) | ||||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
- |
- | ||||||
Acquisition Costs of Proved Properties |
(379.9) |
(123.7) |
(72.6) |
(749.0) |
(480.6) |
(139.1) | ||||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) |
$ 5,964.5 |
$5,935.8 |
$4,055.5 |
$2,614.3 |
$4,394.2 |
$7,570.1 | ||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,628.2 |
$6,419.7 |
$4,439.4 |
$6,445.2 |
$4,928.3 |
$7,904.8 | ||||||
Less: Asset Retirement Costs |
(186.1) |
(69.7) |
(55.6) |
19.9 |
(53.5) |
(195.6) | ||||||
Non-Cash Acquisition Costs of Unproved Properties |
(97.7) |
(290.5) |
(255.7) |
(3,101.8) |
- |
- | ||||||
Non-Cash Acquisition Costs of Proved Properties |
(52.3) |
(70.9) |
(26.2) |
(732.3) |
- |
- | ||||||
Total Exploration and Development Expenditures (Non-GAAP) - (b) |
$ 6,292.1 |
$5,988.6 |
$4,101.9 |
$2,631.0 |
$4,874.8 |
$7,709.2 | ||||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||||||
Revisions Due to Price - (c) |
(59.7) |
34.8 |
154.0 |
(100.7) |
(573.8) |
52.2 | ||||||
Revisions Other Than Price |
(0.3) |
(39.5) |
48.0 |
252.9 |
107.2 |
48.4 | ||||||
Purchases in Place |
16.8 |
11.6 |
2.3 |
42.3 |
56.2 |
14.4 | ||||||
Extensions, Discoveries and Other Additions - (d) |
750.0 |
669.7 |
420.8 |
209.0 |
245.9 |
519.2 | ||||||
Total Proved Reserve Additions - (e) |
706.8 |
676.6 |
625.1 |
403.5 |
(164.5) |
634.2 | ||||||
Sales in Place |
(4.6) |
(10.8) |
(20.7) |
(167.6) |
(3.5) |
(36.3) | ||||||
Net Proved Reserve Additions From All Sources - (f) |
702.2 |
665.8 |
604.4 |
235.9 |
(168.0) |
597.9 | ||||||
Production - (g) |
300.9 |
265.0 |
224.4 |
207.1 |
211.2 |
219.1 | ||||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||||||
Total Drilling, Before Revisions - (a / d) |
$ 7.95 |
$ 8.86 |
$ 9.64 |
$ 12.51 |
$ 17.87 |
$ 14.58 | ||||||
All-in Total, Net of Revisions - (b / e) |
$ 8.90 |
$ 8.85 |
$ 6.56 |
$ 6.52 |
$ (29.63) |
$ 12.16 | ||||||
All-in Total, Excluding Revisions Due to Price - (b / (e - c)) |
$ 8.21 |
$ 9.33 |
$ 8.71 |
$ 5.22 |
$ 11.91 |
$ 13.25 |
EOG RESOURCES, INC. | |||||||||||
Crude Oil, NGLs and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||||||||
Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 (closed) |
20,000 |
$ 1.075 | |||||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 (closed) |
13,000 |
$ 5.572 | |||||||||
EOG has also entered into crude oil swaps to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts. | |||||||||||
Roll Differential Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
February 2020 (closed) |
10,000 |
$ 0.70 | |||||||||
March 1, 2020 through December 31, 2020 |
10,000 |
0.70 | |||||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2019 |
|||||||||||
April 2019 (closed) |
25,000 |
$ 60.00 | |||||||||
May 1, 2019 through December 31, 2019 (closed) |
150,000 |
62.50 | |||||||||
2020 |
|||||||||||
January 2020 (closed) |
200,000 |
$ 59.33 | |||||||||
February 1, 2020 through March 31, 2020 |
200,000 |
59.33 | |||||||||
April 1, 2020 through June 30, 2020 |
200,000 |
59.59 | |||||||||
July 1, 2020 through September 30, 2020 |
107,000 |
58.94 | |||||||||
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Mont Belvieu Propane Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2020 |
|||||||||||
January 2020 (closed) |
4,000 |
$ 21.34 | |||||||||
February 2020 |
4,000 |
21.34 | |||||||||
March 1, 2020 through December 31, 2020 |
25,000 |
17.92 | |||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2019 |
|||||||||||
April 1, 2019 through October 31, 2019 (closed) |
250,000 |
$ 2.90 | |||||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume (MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2020 |
|||||||||||
April 1, 2020 through October 31, 2020 |
250,000 |
$ 2.50 |
$ 2.00 | ||||||||
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
Rockies Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through February 29, 2020 (closed) |
30,000 |
$ 0.55 | |||||||||
March 1, 2020 through December 31, 2020 |
30,000 |
0.55 | |||||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
HSC Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through February 29, 2020 (closed) |
60,000 |
$ 0.05 | |||||||||
March 1, 2020 through December 31, 2020 |
60,000 |
0.05 | |||||||||
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||||||||||
Waha Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2020 |
|||||||||||
January 1, 2020 through February 29, 2020 (closed) |
50,000 |
$ 1.40 | |||||||||
March 1, 2020 through December 31, 2020 |
50,000 |
1.40 | |||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, | ||||||||
Net Debt and Total Capitalization | ||||||||
Calculations of Return on Capital Employed and Return on Equity | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2019 |
2018 |
2017 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||
Net Interest Expense (GAAP) |
$ |
185 |
$ |
245 |
||||
Tax Benefit Imputed (based on 21%) |
(39) |
(51) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
146 |
$ |
194 |
||||
Net Income (GAAP) - (b) |
$ |
2,735 |
$ |
3,419 |
||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) |
158 |
(1) |
(201) |
(2) |
||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
2,893 |
$ |
3,218 |
||||
Total Stockholders' Equity - (d) |
$ |
21,641 |
$ |
19,364 |
$ |
16,283 | ||
Average Total Stockholders' Equity * - (e) |
$ |
20,503 |
$ |
17,824 |
||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
5,175 |
$ |
6,083 |
$ |
6,387 | ||
Less: Cash |
(2,028) |
(1,556) |
(834) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
3,147 |
$ |
4,527 |
$ |
5,553 | ||
Total Capitalization (GAAP) - (d) + (f) |
$ |
26,816 |
$ |
25,447 |
$ |
22,670 | ||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
24,788 |
$ |
23,891 |
$ |
21,836 | ||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
24,340 |
$ |
22,864 |
||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
11.8% |
15.8% |
||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
12.5% |
14.9% |
||||||
Return on Equity (ROE) |
||||||||
ROE (GAAP Net Income) - (b) / (e) |
13.3% |
19.2% |
||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
14.1% |
18.1% |
||||||
* Average for the current and immediately preceding year |
||||||||
Adjustments to Net Income (GAAP) |
||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2019: |
||||||||
Year Ended December 31, 2019 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
51 |
$ |
(11) |
$ |
40 | ||
Add: Impairments of Certain Assets |
275 |
(60) |
215 | |||||
Less: Net Gains on Asset Dispositions |
(124) |
27 |
(97) | |||||
Total |
$ |
202 |
$ |
(44) |
$ |
158 | ||
(2) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: |
||||||||
Year Ended December 31, 2018 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(93) |
$ |
20 |
$ |
(73) | ||
Add: Impairments of Certain Assets |
153 |
(34) |
119 | |||||
Less: Net Gains on Asset Dispositions |
(175) |
38 |
(137) | |||||
Less: Tax Reform Impact |
- |
(110) |
(110) | |||||
Total |
$ |
(115) |
$ |
(86) |
$ |
(201) |
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 |
2016 |
2015 |
2014 |
2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
$ |
235 |
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
(82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
$ |
153 |
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
Total Stockholders' Equity - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
Average Total Stockholders' Equity * - (e) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 |
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
21,836 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,602 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
$ |
19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
13.4% |
-4.8% |
-21.6% |
14.7% |
12.1% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.1% |
-8.1% |
-29.5% |
17.6% |
15.3% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 |
2011 |
2010 |
2009 |
2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
214 |
$ |
210 |
$ |
130 |
$ |
101 |
$ |
52 |
Tax Benefit Imputed (based on 35%) |
(75) |
(74) |
(46) |
(35) |
(18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
139 |
$ |
136 |
$ |
84 |
$ |
66 |
$ |
34 |
Net Income (Loss) (GAAP) - (b) |
$ |
570 |
$ |
1,091 |
$ |
161 |
$ |
547 |
$ |
2,437 |
Total Stockholders' Equity - (d) |
$ |
13,285 |
$ |
12,641 |
$ |
10,232 |
$ |
9,998 |
$ |
9,015 |
Average Total Stockholders' Equity * - (e) |
$ |
12,963 |
$ |
11,437 |
$ |
10,115 |
$ |
9,507 |
$ |
8,003 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,312 |
$ |
5,009 |
$ |
5,223 |
$ |
2,797 |
$ |
1,897 |
Less: Cash |
(876) |
(616) |
(789) |
(686) |
(331) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
5,436 |
$ |
4,393 |
$ |
4,434 |
$ |
2,111 |
$ |
1,566 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,597 |
$ |
17,650 |
$ |
15,455 |
$ |
12,795 |
$ |
10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,721 |
$ |
17,034 |
$ |
14,666 |
$ |
12,109 |
$ |
10,581 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
17,878 |
$ |
15,850 |
$ |
13,388 |
$ |
11,345 |
$ |
9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.0% |
7.7% |
1.8% |
5.4% |
26.4% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
4.4% |
9.5% |
1.6% |
5.8% |
30.5% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 |
2006 |
2005 |
2004 |
2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
47 |
$ |
43 |
$ |
63 |
$ |
63 |
$ |
59 |
Tax Benefit Imputed (based on 35%) |
(16) |
(15) |
(22) |
(22) |
(21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
31 |
$ |
28 |
$ |
41 |
$ |
41 |
$ |
38 |
Net Income (Loss) (GAAP) - (b) |
$ |
1,090 |
$ |
1,300 |
$ |
1,260 |
$ |
625 |
$ |
430 |
Total Stockholders' Equity - (d) |
$ |
6,990 |
$ |
5,600 |
$ |
4,316 |
$ |
2,945 |
$ |
2,223 |
Average Total Stockholders' Equity * - (e) |
$ |
6,295 |
$ |
4,958 |
$ |
3,631 |
$ |
2,584 |
$ |
1,948 |
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,185 |
$ |
733 |
$ |
985 |
$ |
1,078 |
$ |
1,109 |
Less: Cash |
(54) |
(218) |
(644) |
(21) |
(4) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
1,131 |
$ |
515 |
$ |
341 |
$ |
1,057 |
$ |
1,105 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
8,175 |
$ |
6,333 |
$ |
5,301 |
$ |
4,023 |
$ |
3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
8,121 |
$ |
6,115 |
$ |
4,657 |
$ |
4,002 |
$ |
3,328 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
7,118 |
$ |
5,386 |
$ |
4,330 |
$ |
3,665 |
$ |
3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
15.7% |
24.7% |
30.0% |
18.2% |
15.3% | |||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
17.3% |
26.2% |
34.7% |
24.2% |
22.1% | |||||
* Average for the current and immediately preceding year |
||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 |
2001 |
2000 |
1999 |
1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||
(Calculated Using GAAP Net Income) |
||||||||||
Net Interest Expense (GAAP) |
$ |
60 |
$ |
45 |
$ |
61 |
$ |
62 |
||
Tax Benefit Imputed (based on 35%) |
(21) |
(16) |
(21) |
(22) |
||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
39 |
$ |
29 |
$ |
40 |
$ |
40 |
||
Net Income (Loss) (GAAP) - (b) |
$ |
87 |
$ |
399 |
$ |
397 |
$ |
569 |
||
Total Stockholders' Equity - (d) |
$ |
1,672 |
$ |
1,643 |
$ |
1,381 |
$ |
1,130 |
$ |
1,280 |
Average Total Stockholders' Equity * - (e) |
$ |
1,658 |
$ |
1,512 |
$ |
1,256 |
$ |
1,205 |
||
Current and Long-Term Debt (GAAP) - (f) |
$ |
1,145 |
$ |
856 |
$ |
859 |
$ |
990 |
$ |
1,143 |
Less: Cash |
(10) |
(3) |
(20) |
(25) |
(6) | |||||
Net Debt (Non-GAAP) - (g) |
$ |
1,135 |
$ |
853 |
$ |
839 |
$ |
965 |
$ |
1,137 |
Total Capitalization (GAAP) - (d) + (f) |
$ |
2,817 |
$ |
2,499 |
$ |
2,240 |
$ |
2,120 |
$ |
2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
2,807 |
$ |
2,496 |
$ |
2,220 |
$ |
2,095 |
$ |
2,417 |
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
2,652 |
$ |
2,358 |
$ |
2,158 |
$ |
2,256 |
||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
4.8% |
18.2% |
20.2% |
27.0% |
||||||
Return on Equity (ROE) (GAAP) |
||||||||||
ROE (GAAP Net Income) - (b) / (e) |
5.2% |
26.4% |
31.6% |
47.2% |
||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||||
Year Ended |
|||||||||||||
December 31, |
|||||||||||||
2019 |
2018 |
2017 |
2016 |
2015 |
2014 |
||||||||
Cash Operating Expenses (GAAP)* |
|||||||||||||
Lease and Well |
$ 1,366,993 |
$ 1,282,678 |
$ 1,044,847 |
$ 927,452 |
$ 1,182,282 |
$ 1,416,413 |
|||||||
Transportation Costs |
758,300 |
746,876 |
740,352 |
764,106 |
849,319 |
972,176 |
|||||||
General and Administrative |
489,397 |
426,969 |
434,467 |
394,815 |
366,594 |
402,010 |
|||||||
Cash Operating Expenses |
2,614,690 |
2,456,523 |
2,219,666 |
2,086,373 |
2,398,195 |
2,790,599 |
|||||||
Less: Legal Settlement - Early Leasehold Termination |
- |
- |
(10,202) |
- |
(19,355) |
- |
|||||||
Less: Voluntary Retirement Expense |
- |
- |
- |
(42,054) |
- |
- |
|||||||
Less: Acquisition Costs - Yates Transaction |
- |
- |
- |
(5,100) |
- |
- |
|||||||
Less: Joint Venture Transaction Costs |
- |
- |
(3,056) |
- |
- |
- |
|||||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
- |
(4,528) |
- |
- |
- |
|||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) |
$ 2,614,690 |
$ 2,456,523 |
$ 2,201,880 |
$ 2,039,219 |
$ 2,378,840 |
$ 2,790,599 |
|||||||
Volume - Thousand Barrels of Oil Equivalent - (b) |
298,565 |
262,516 |
222,251 |
204,929 |
208,862 |
217,073 |
|||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) |
$ 8.76 |
(c) |
$ 9.36 |
(d) |
$ 9.91 |
(e) |
$ 9.95 |
(f) |
$ 11.39 |
(g) |
$ 12.86 |
(h) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - |
|||||||||||||
2019 compared to 2018 - [(c) - (d)] / (d) |
-6% |
||||||||||||
2019 compared to 2017 - [(c) - (e)] / (e) |
-12% |
||||||||||||
2019 compared to 2016 - [(c) - (f)] / (f) |
-12% |
||||||||||||
2019 compared to 2015 - [(c) - (g)] / (g) |
-23% |
||||||||||||
2019 compared to 2014 - [(c) - (h)] / (h) |
-32% |
||||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | ||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||
Three Months Ended | ||||||||
March 31, |
June 30, |
September 30, |
December 31, | |||||
2019 |
2019 |
2019 |
2019 | |||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
69,623 |
73,964 |
76,748 |
78,231 | ||||
Crude Oil and Condensate |
$ 2,200,403 |
$ 2,528,866 |
$ 2,418,989 |
$ 2,464,274 | ||||
Natural Gas Liquids |
218,638 |
186,374 |
164,736 |
215,070 | ||||
Natural Gas |
334,972 |
269,892 |
269,625 |
309,606 | ||||
Total Wellhead Revenues - (b) |
$ 2,754,013 |
$ 2,985,132 |
$ 2,853,350 |
$ 2,988,950 | ||||
Operating Costs |
||||||||
Lease and Well |
$ 336,291 |
$ 347,281 |
$ 348,883 |
$ 334,538 | ||||
Transportation Costs |
176,522 |
174,101 |
199,365 |
208,312 | ||||
Gathering and Processing Costs |
111,295 |
112,643 |
127,549 |
127,615 | ||||
General and Administrative |
106,672 |
121,780 |
135,758 |
125,187 | ||||
Taxes Other Than Income |
192,906 |
204,414 |
203,098 |
199,746 | ||||
Interest Expense, Net |
54,906 |
49,908 |
39,620 |
40,695 | ||||
Total Cash Operating Cost (excluding DD&A and Total |
$ 978,592 |
$ 1,010,127 |
$ 1,054,273 |
$ 1,036,093 | ||||
Depreciation, Depletion and Amortization (DD&A) |
879,595 |
957,304 |
953,597 |
959,208 | ||||
Total Operating Cost (excluding Total Exploration Costs) - (d) |
$ 1,858,187 |
$ 1,967,431 |
$ 2,007,870 |
$ 1,995,301 | ||||
Exploration Costs |
$ 36,324 |
$ 32,522 |
$ 34,540 |
$ 36,495 | ||||
Dry Hole Costs |
94 |
3,769 |
24,138 |
- | ||||
Impairments |
72,356 |
112,130 |
105,275 |
228,135 | ||||
Total Exploration Costs |
108,774 |
148,421 |
163,953 |
264,630 | ||||
Less: Impairments (Non-GAAP) |
(23,745) |
(65,289) |
(27,215) |
(158,725) | ||||
Total Exploration Costs (Non-GAAP) |
$ 85,029 |
$ 83,132 |
$ 136,738 |
$ 105,905 | ||||
Total Operating Cost (Non-GAAP) (including Total |
$ 1,943,216 |
$ 2,050,563 |
$ 2,144,608 |
$ 2,101,206 | ||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 39.56 |
$ 40.36 |
$ 37.18 |
$ 38.21 | ||||
Total Cash Operating Cost per Boe (excluding DD&A |
$ 14.06 |
$ 13.65 |
$ 13.75 |
$ 13.24 | ||||
Composite Average Margin per Boe (excluding DD&A |
$ 25.50 |
$ 26.71 |
$ 23.43 |
$ 24.97 | ||||
Total Operating Cost per Boe (excluding Total |
$ 26.69 |
$ 26.59 |
$ 26.18 |
$ 25.50 | ||||
Composite Average Margin per Boe (excluding Total |
$ 12.87 |
$ 13.77 |
$ 11.00 |
$ 12.71 | ||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 27.91 |
$ 27.72 |
$ 27.97 |
$ 26.85 | ||||
Composite Average Margin per Boe (Non-GAAP) |
$ 11.65 |
$ 12.64 |
$ 9.21 |
$ 11.36 | ||||
EOG RESOURCES, INC. |
||||||||
Cost per Barrel of Oil Equivalent (Boe) |
||||||||
(Unaudited; in thousands, except per Boe amounts) |
||||||||
Year Ended |
||||||||
December 31, |
||||||||
2019 |
2018 |
2017 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
298,565 |
262,516 |
222,251 |
|||||
Crude Oil and Condensate |
$ 9,612,532 |
$ 9,517,440 |
$ 6,256,396 |
|||||
Natural Gas Liquids |
784,818 |
1,127,510 |
729,561 |
|||||
Natural Gas |
1,184,095 |
1,301,537 |
921,934 |
|||||
Total Wellhead Revenues - (b) |
$ 11,581,445 |
$ 11,946,487 |
$ 7,907,891 |
|||||
Operating Costs |
||||||||
Lease and Well |
$ 1,366,993 |
$ 1,282,678 |
$ 1,044,847 |
|||||
Transportation Costs |
758,300 |
746,876 |
740,352 |
|||||
Gathering and Processing Costs |
479,102 |
436,973 |
148,775 |
|||||
General and Administrative |
489,397 |
426,969 |
434,467 |
|||||
Less: Legal Settlement - Early Leasehold Termination |
- |
- |
(10,202) |
|||||
Less: Joint Venture Transaction Costs |
- |
- |
(3,056) |
|||||
Less: Joint Interest Billings Deemed Uncollectible |
- |
- |
(4,528) |
|||||
General and Administrative (Non-GAAP) |
489,397 |
426,969 |
416,681 |
|||||
Taxes Other Than Income |
800,164 |
772,481 |
544,662 |
|||||
Interest Expense, Net |
185,129 |
245,052 |
274,372 |
|||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A |
$ 4,079,085 |
$ 3,911,029 |
$ 3,169,689 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
3,749,704 |
3,435,408 |
3,409,387 |
|||||
Total Operating Cost (Non-GAAP) (excluding Total |
$ 7,828,789 |
$ 7,346,437 |
$ 6,579,076 |
|||||
Exploration Costs |
$ 139,881 |
$ 148,999 |
$ 145,342 |
|||||
Dry Hole Costs |
28,001 |
5,405 |
4,609 |
|||||
Impairments |
517,896 |
347,021 |
479,240 |
|||||
Total Exploration Costs |
685,778 |
501,425 |
629,191 |
|||||
Less: Impairments (Non-GAAP) |
(274,974) |
(152,671) |
(261,452) |
|||||
Total Exploration Costs (Non-GAAP) |
$ 410,804 |
$ 348,754 |
$ 367,739 |
|||||
Total Operating Cost (Non-GAAP) (including Total |
$ 8,239,593 |
$ 7,695,191 |
$ 6,946,815 |
|||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 38.79 |
$ 45.51 |
$ 35.58 |
|||||
Total Cash Operating Cost per Boe (Non-GAAP) |
$ 13.66 |
$ 14.90 |
$ 14.25 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding |
$ 25.13 |
$ 30.61 |
$ 21.33 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding |
$ 26.22 |
$ 27.99 |
$ 29.59 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ 12.57 |
$ 17.52 |
$ 5.99 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 27.60 |
$ 29.32 |
$ 31.24 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ 11.19 |
$ 16.19 |
$ 4.34 |
|||||
EOG RESOURCES, INC. |
||||||||
Cost per Barrel of Oil Equivalent (Boe) |
||||||||
(Unaudited; in thousands, except per Boe amounts) |
||||||||
Year Ended |
||||||||
December 31, |
||||||||
2016 |
2015 |
2014 |
||||||
Volume - Thousand Barrels of Oil Equivalent - (a) |
204,929 |
208,862 |
217,073 |
|||||
Crude Oil and Condensate |
$ 4,317,341 |
$ 4,934,562 |
$ 9,742,480 |
|||||
Natural Gas Liquids |
437,250 |
407,658 |
934,051 |
|||||
Natural Gas |
742,152 |
1,061,038 |
1,916,386 |
|||||
Total Wellhead Revenues - (b) |
$ 5,496,743 |
$ 6,403,258 |
$ 12,592,917 |
|||||
Operating Costs |
||||||||
Lease and Well |
$ 927,452 |
$ 1,182,282 |
$ 1,416,413 |
|||||
Transportation Costs |
764,106 |
849,319 |
972,176 |
|||||
Gathering and Processing Costs |
122,901 |
146,156 |
145,800 |
|||||
General and Administrative |
394,815 |
366,594 |
402,010 |
|||||
Less: Voluntary Retirement Expense |
(42,054) |
- |
- |
|||||
Less: Acquisition Costs |
(5,100) |
- |
- |
|||||
Less: Legal Settlement - Early Leasehold Termination |
- |
(19,355) |
- |
|||||
General and Administrative (Non-GAAP) |
347,661 |
347,239 |
402,010 |
|||||
Taxes Other Than Income |
349,710 |
421,744 |
757,564 |
|||||
Interest Expense, Net |
281,681 |
237,393 |
201,458 |
|||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A |
$ 2,793,511 |
$ 3,184,133 |
$ 3,895,421 |
|||||
Depreciation, Depletion and Amortization (DD&A) |
3,553,417 |
3,313,644 |
3,997,041 |
|||||
Total Operating Cost (Non-GAAP) (excluding Total |
$ 6,346,928 |
$ 6,497,777 |
$ 7,892,462 |
|||||
Exploration Costs |
$ 124,953 |
$ 149,494 |
$ 184,388 |
|||||
Dry Hole Costs |
10,657 |
14,746 |
48,490 |
|||||
Impairments |
620,267 |
6,613,546 |
743,575 |
|||||
Total Exploration Costs |
755,877 |
6,777,786 |
976,453 |
|||||
Less: Impairments (Non-GAAP) |
(320,617) |
(6,307,593) |
(824,312) |
|||||
Total Exploration Costs (Non-GAAP) |
$ 435,260 |
$ 470,193 |
$ 152,141 |
|||||
Total Operating Cost (Non-GAAP) (including Total |
$ 6,782,188 |
$ 6,967,970 |
$ 8,044,603 |
|||||
Composite Average Wellhead Revenue per Boe - (b) / (a) |
$ 26.82 |
$ 30.66 |
$ 58.01 |
|||||
Total Cash Operating Cost per Boe (Non-GAAP) |
$ 13.64 |
$ 15.25 |
$ 17.95 |
|||||
Composite Average Margin per Boe (Non-GAAP) (excluding |
$ 13.18 |
$ 15.41 |
$ 40.06 |
|||||
Total Operating Cost per Boe (Non-GAAP) (excluding |
$ 30.98 |
$ 31.11 |
$ 36.38 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ (4.16) |
$ (0.45) |
$ 21.63 |
|||||
Total Operating Cost per Boe (Non-GAAP) (including |
$ 33.10 |
$ 33.36 |
$ 37.08 |
|||||
Composite Average Margin per Boe (Non-GAAP) |
$ (6.28) |
$ (2.70) |
$ 20.93 |
EOG RESOURCES, INC. | |||||||||||
First Quarter and Full Year 2020 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) First Quarter and Full Year 2020 Forecast |
|||||||||||
The forecast items for the first quarter and full year 2020 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Capital Expenditures |
|||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. | |||||||||||
(c) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
1Q 2020 |
Full Year 2020 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
479.0 |
- |
487.0 |
499.0 |
- |
517.6 | |||||
Trinidad |
0.5 |
- |
0.7 |
1.0 |
- |
1.2 | |||||
Other International |
0.0 |
- |
0.2 |
0.0 |
- |
0.2 | |||||
Total |
479.5 |
- |
487.9 |
500.0 |
- |
519.0 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
150.0 |
- |
160.0 |
157.0 |
- |
177.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
1,090 |
- |
1,150 |
1,135 |
- |
1,235 | |||||
Trinidad |
185 |
- |
215 |
215 |
- |
255 | |||||
Other International |
25 |
- |
35 |
25 |
- |
35 | |||||
Total |
1,300 |
- |
1,400 |
1,375 |
- |
1,525 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
810.7 |
- |
838.7 |
845.2 |
- |
900.4 | |||||
Trinidad |
31.3 |
- |
36.5 |
36.8 |
- |
43.7 | |||||
Other International |
4.2 |
- |
6.0 |
4.2 |
- |
6.0 | |||||
Total |
846.2 |
- |
881.2 |
886.2 |
- |
950.1 | |||||
Capital Expenditures ($MM) |
$ |
1,850 |
- |
$ |
2,050 |
$ |
6,300 |
- |
$ |
6,700 | |
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
1Q 2020 |
Full Year 2020 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.30 |
- |
$ |
4.80 |
$ |
4.20 |
- |
$ |
4.80 | |
Transportation Costs |
$ |
2.40 |
- |
$ |
2.80 |
$ |
2.30 |
- |
$ |
2.70 | |
General and Administrative |
$ |
1.55 |
- |
$ |
1.65 |
$ |
1.55 |
- |
$ |
1.65 | |
Gathering and Processing |
$ |
1.70 |
- |
$ |
1.80 |
$ |
1.60 |
- |
$ |
1.80 | |
Depreciation, Depletion and Amortization |
$ |
13.00 |
- |
$ |
13.50 |
$ |
12.15 |
- |
$ |
13.15 | |
Expenses ($MM) |
|||||||||||
Exploration and Dry Hole |
$ |
40 |
- |
$ |
50 |
$ |
145 |
- |
$ |
185 | |
Impairment |
$ |
80 |
- |
$ |
90 |
$ |
325 |
- |
$ |
365 | |
Capitalized Interest |
$ |
9 |
- |
$ |
11 |
$ |
37 |
- |
$ |
43 | |
Net Interest |
$ |
39 |
- |
$ |
41 |
$ |
136 |
- |
$ |
140 | |
Taxes Other Than Income (% of Wellhead Revenue) |
7.0% |
- |
8.0% |
7.0% |
- |
8.0% | |||||
Income Taxes |
|||||||||||
Effective Rate |
21% |
- |
26% |
21% |
- |
26% | |||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(15) |
- |
$ |
30 |
$ |
5 |
- |
$ |
50 | |
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(0.10) |
- |
$ |
0.90 |
$ |
(0.50) |
- |
$ |
1.50 | |
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.50) |
- |
$ |
(9.50) | |
Other International - above (below) WTI |
$ |
0.75 |
- |
$ |
4.75 |
$ |
(0.65) |
- |
$ |
1.35 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
21% |
- |
27% |
21% |
- |
27% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.70) |
- |
$ |
(0.30) |
$ |
(0.90) |
- |
$ |
(0.30) | |
Realizations |
|||||||||||
Trinidad |
$ |
2.40 |
- |
$ |
2.80 |
$ |
2.50 |
- |
$ |
3.20 | |
Other International |
$ |
4.00 |
- |
$ |
4.50 |
$ |
3.85 |
- |
$ |
4.85 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX U.S. New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-excellent-fourth-quarter-and-full-year-2019-results-announces-2020-capital-program-raises-dividend-by-30-percent-301013042.html
SOURCE EOG Resources, Inc.
HOUSTON, Jan. 14, 2020 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss fourth quarter and full year 2019 results on Friday, February 28, 2020, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-fourth-quarter-and-full-year-2019-results-for-february-28-2020-300987012.html
SOURCE EOG Resources, Inc.
HOUSTON, Dec. 10, 2019 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (EOG) has declared a dividend of $0.2875 per share on EOG's Common Stock, payable January 31, 2020, to stockholders of record as of January 17, 2020. The indicated annual rate is $1.15.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-300972651.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 6, 2019 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported third quarter 2019 net income of $615 million, or $1.06 per share, compared with third quarter 2018 net income of $1.2 billion, or $2.05 per share. Net cash provided by operating activities for the third quarter 2019 was $2.1 billion.
Adjusted non-GAAP net income for the third quarter 2019 was $654 million, or $1.13 per share, compared with adjusted non-GAAP net income of $1.0 billion, or $1.75 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Third Quarter 2019 Operating Review
Total crude oil volumes of 464,100 barrels of oil per day (Bopd) in the third quarter 2019 increased 12 percent compared to the same prior year period and were above the high end of the target range. Natural gas liquids (NGLs) and natural gas volumes each grew 11 percent. EOG incurred total expenditures of $1.6 billion in the third quarter. Cash capital expenditures before acquisitions of $1.5 billion were near the low end of the target range. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
EOG continued to lower operating costs during the third quarter 2019. Per-unit transportation costs declined nine percent compared to the same prior-year period, depreciation, depletion and amortization expenses fell seven percent year-over-year, and lease and well expenses declined three percent year-over-year.
EOG generated $2.0 billion of discretionary cash flow in the third quarter 2019. After considering cash capital expenditures before acquisitions of $1.5 billion and dividend payments of $166 million, EOG generated free cash flow during the third quarter 2019 of $337 million. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG's operating performance has never been better. The company generated outstanding financial results in the third quarter driven by improvements in every area," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We reduced operating expenses, grew volumes at double-digit rates while lowering well costs and generated substantial free cash flow. EOG has never been in a better position to sustain this success long into the future."
New Delaware Basin Plays and Premium Inventory Update
EOG expanded its lineup of premium plays in the Delaware Basin with the addition of the Wolfcamp M and the Third Bone Spring. The drilling locations in these two plays are highly economic at a flat $40 oil price and flat $2.50 natural gas price, consistent with EOG's definition of premium inventory. The company continues to deepen its technical knowledge of the Delaware Basin as it executes its development program. EOG collects significant amounts of data on each well, integrates it with existing models and incorporates analysis from numerous spacing and targeting tests.
EOG has identified an initial 855 net premium drilling locations in the Wolfcamp M, with estimated net resource potential of 1.0 billion barrels of oil equivalent across its 193,000 net acre position. The wells in this deeper section of the Wolfcamp formation produce roughly equal parts oil, NGLs and natural gas. Benefiting from EOG's low well costs, Wolfcamp M wells deliver strong premium economics and exceptionally low finding costs.
To define the play, EOG has gathered extensive subsurface information and has completed six Wolfcamp M wells, including two during 2019. The Green Drake 16 Fed Com #759H was completed in Lea County, NM with a treated lateral length of 7,200 feet and a 30-day initial production rate of 4,165 barrels of oil equivalent per day (Boed), or 2,145 Bopd, 1,070 barrels per day (Bpd) of NGLs and 5.7 million cubic feet per day (MMcfd) of natural gas. In Reeves County, TX, the State Correa #3H was completed with a treated lateral length of 9,900 feet and a 30-day initial production rate of 2,800 Boed, or 1,175 Bopd, 845 Bpd of NGLs and 4.7 MMcfd of natural gas.
EOG has identified an initial 615 net premium drilling locations in the Third Bone Spring, with estimated net resource potential of 585 million barrels of oil equivalent across its 200,000 net acre position. EOG's early focus in the Delaware Basin has been on development of the Wolfcamp formation, which sits below the Third Bone Spring. Each of the Wolfcamp wells has drilled through the Third Bone Spring, providing significant technical data and helping to delineate multiple targets within the play.
EOG has completed over 50 Third Bone Spring wells to date, including 10 net wells in 2019. The McGregor D 5 #592H targeted the Third Bone Spring Carbonate and was completed in Loving County, TX with a treated lateral length of 9,700 feet and a 30-day initial production rate of 2,865 Boed, or 1,990 Bopd, 500 Bpd of NGLs and 2.3 MMcfd of natural gas. In Lea County, NM, the Caravan 28 State Com #601H and the Convoy 28 State Com #606H targeted the Third Bone Spring Sand and were completed with an average treated lateral length of 10,000 feet per well and average 30-day initial production rates per well of 3,985 Boed, or 2,730 Bopd, 670 Bpd of NGLs and 3.5 MMcfd of natural gas.
In total, EOG added 1,700 net premium drilling locations to its undrilled premium inventory in the third quarter 2019. Taking into account approximately 640 net wells drilled to date in 2019 and updated location counts across its portfolio, EOG's premium inventory now totals 10,500 net locations, representing more than 14 years of high-return drilling inventory.
"EOG is a returns-focused company where organic growth is driven by exploration and low-cost development. The announcement of two more premium plays in the Delaware Basin and the addition of 1,700 new net premium drilling locations demonstrate the sustainability of our unique business model," Thomas continued. "EOG continues to demonstrate its ability to generate attractive returns on capital through reinvestment in an improving inventory of premium wells across multiple plays. Our best-in-class assets prove that EOG can adapt to changing industry conditions and create significant shareholder value for years to come."
Financial Review
EOG further strengthened its financial position during the third quarter 2019. At September 30, 2019, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 20 percent. Considering $1.6 billion of cash on the balance sheet at the end of the third quarter, EOG's net debt was $3.6 billion for a net debt-to-total capitalization ratio of 15 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Third Quarter 2019 Results Webcast
Thursday, November 7, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Operating Revenues and Other | $ | 4,303.5 | $ | 4,781.6 | $ | 13,059.7 | $ | 12,700.9 | |||
Net Income | $ | 615.1 | $ | 1,191.0 | $ | 2,098.4 | $ | 2,526.3 | |||
Net Income Per Share | |||||||||||
Basic | $ | 1.06 | $ | 2.06 | $ | 3.63 | $ | 4.38 | |||
Diluted | $ | 1.06 | $ | 2.05 | $ | 3.61 | $ | 4.35 | |||
Average Number of Common Shares | |||||||||||
Basic | 577.8 | 577.3 | 577.5 | 576.4 | |||||||
Diluted | 581.3 | 581.6 | 581.2 | 580.4 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | $ | 2,418,989 | $ | 2,655,278 | $ | 7,148,258 | $ | 7,134,114 | |||
Natural Gas Liquids | 164,736 | 353,704 | 569,748 | 861,473 | |||||||
Natural Gas | 269,625 | 311,713 | 874,489 | 912,324 | |||||||
Gains (Losses) on Mark-to-Market Commodity | 85,902 | (52,081) | 242,622 | (297,735) | |||||||
Gathering, Processing and Marketing | 1,334,450 | 1,360,992 | 4,121,490 | 3,899,250 | |||||||
Gains (Losses) on Asset Dispositions, Net | (523) | 115,944 | 3,650 | 94,658 | |||||||
Other, Net | 30,276 | 36,074 | 99,470 | 96,779 | |||||||
Total | 4,303,455 | 4,781,624 | 13,059,727 | 12,700,863 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 348,883 | 321,568 | 1,032,455 | 936,236 | |||||||
Transportation Costs | 199,365 | 196,027 | 549,988 | 550,781 | |||||||
Gathering and Processing Costs | 127,549 | 114,063 | 351,487 | 324,577 | |||||||
Exploration Costs | 34,540 | 32,823 | 103,386 | 115,137 | |||||||
Dry Hole Costs | 24,138 | 358 | 28,001 | 5,260 | |||||||
Impairments | 105,275 | 44,617 | 289,761 | 160,934 | |||||||
Marketing Costs | 1,343,293 | 1,326,974 | 4,114,265 | 3,853,827 | |||||||
Depreciation, Depletion and Amortization | 953,597 | 918,180 | 2,790,496 | 2,515,445 | |||||||
General and Administrative | 135,758 | 111,284 | 364,210 | 310,065 | |||||||
Taxes Other Than Income | 203,098 | 209,043 | 600,418 | 582,395 | |||||||
Total | 3,475,496 | 3,274,937 | 10,224,467 | 9,354,657 | |||||||
Operating Income | 827,959 | 1,506,687 | 2,835,260 | 3,346,206 | |||||||
Other Income (Expense), Net | 9,118 | 3,308 | 23,233 | (4,516) | |||||||
Income Before Interest Expense and Income Taxes | 837,077 | 1,509,995 | 2,858,493 | 3,341,690 | |||||||
Interest Expense, Net | 39,620 | 63,632 | 144,434 | 189,032 | |||||||
Income Before Income Taxes | 797,457 | 1,446,363 | 2,714,059 | 3,152,658 | |||||||
Income Tax Provision | 182,335 | 255,411 | 615,670 | 626,386 | |||||||
Net Income | $ | 615,122 | $ | 1,190,952 | $ | 2,098,389 | $ | 2,526,272 | |||
Dividends Declared per Common Share | $ | 0.2875 | $ | 0.2200 | $ | 0.7950 | $ | 0.5900 |
EOG RESOURCES, INC. | |||||||||||||||
Operating Highlights | |||||||||||||||
(Unaudited) | |||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||
September 30, | September 30, | ||||||||||||||
2019 | 2018 | % Change | 2019 | 2018 | % Change | ||||||||||
Wellhead Volumes and Prices | |||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||
United States | 463.2 | 409.2 | 13% | 451.2 | 382.9 | 18% | |||||||||
Trinidad | 0.8 | 0.8 | 0% | 0.7 | 0.8 | -13% | |||||||||
Other International (B) | 0.1 | 5.0 | -98% | 0.1 | 4.1 | -98% | |||||||||
Total | 464.1 | 415.0 | 12% | 452.0 | 387.8 | 17% | |||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 56.67 | $ | 69.53 | -18% | $ | 57.95 | $ | 67.35 | -14% | |||||
Trinidad | 48.36 | 61.71 | -22% | 47.26 | 58.91 | -20% | |||||||||
Other International (B) | 59.87 | 72.81 | -18% | 58.43 | 71.83 | -19% | |||||||||
Composite | 56.66 | 69.55 | -19% | 57.93 | 67.38 | -14% | |||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||
United States | 141.3 | 127.8 | 11% | 130.8 | 113.9 | 15% | |||||||||
Other International (B) | - | - | - | - | |||||||||||
Total | 141.3 | 127.8 | 11% | 130.8 | 113.9 | 15% | |||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 12.67 | $ | 30.09 | -58% | $ | 15.96 | $ | 27.71 | -42% | |||||
Other International (B) | - | - | - | - | |||||||||||
Composite | 12.67 | 30.09 | -58% | 15.96 | 27.71 | -42% | |||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||
United States | 1,079 | 948 | 14% | 1,043 | 905 | 15% | |||||||||
Trinidad | 260 | 260 | 0% | 267 | 278 | -4% | |||||||||
Other International (B) | 34 | 28 | 21% | 36 | 31 | 16% | |||||||||
Total | 1,373 | 1,236 | 11% | 1,346 | 1,214 | 11% | |||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||
United States | $ | 1.97 | $ | 2.67 | -26% | $ | 2.23 | $ | 2.66 | -16% | |||||
Trinidad | 2.52 | 2.88 | -12% | 2.71 | 2.91 | -7% | |||||||||
Other International (B) | 4.25 | 3.83 | 11% | 4.29 | 4.10 | 5% | |||||||||
Composite | 2.13 | 2.74 | -22% | 2.38 | 2.75 | -14% | |||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||
United States | 784.3 | 695.0 | 13% | 755.8 | 647.6 | 17% | |||||||||
Trinidad | 44.1 | 44.1 | 0% | 45.1 | 47.2 | -4% | |||||||||
Other International (B) | 5.8 | 9.7 | -40% | 6.2 | 9.2 | -33% | |||||||||
Total | 834.2 | 748.8 | 11% | 807.1 | 704.0 | 15% | |||||||||
Total MMBoe (D) | 76.7 | 68.9 | 11% | 220.3 | 192.2 | 15% |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. | |||||||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2019). | |||||||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | ||||||||
Summary Balance Sheets | ||||||||
(Unaudited; in thousands, except share data) | ||||||||
September 30, | December 31, | |||||||
2019 | 2018 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | $ | 1,583,105 | $ | 1,555,634 | ||||
Accounts Receivable, Net | 1,927,996 | 1,915,215 | ||||||
Inventories | 778,120 | 859,359 | ||||||
Assets from Price Risk Management Activities | 122,627 | 23,806 | ||||||
Income Taxes Receivable | 135,680 | 427,909 | ||||||
Other | 272,203 | 275,467 | ||||||
Total | 4,819,731 | 5,057,390 | ||||||
Property, Plant and Equipment | ||||||||
Oil and Gas Properties (Successful Efforts Method) | 61,620,033 | 57,330,016 | ||||||
Other Property, Plant and Equipment | 4,394,486 | 4,220,665 | ||||||
Total Property, Plant and Equipment | 66,014,519 | 61,550,681 | ||||||
Less: Accumulated Depreciation, Depletion and Amortization | (35,810,197) | (33,475,162) | ||||||
Total Property, Plant and Equipment, Net | 30,204,322 | 28,075,519 | ||||||
Deferred Income Taxes | 1,998 | 777 | ||||||
Other Assets | 1,516,218 | 800,788 | ||||||
Total Assets | $ | 36,542,269 | $ | 33,934,474 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts Payable | $ | 2,395,080 | $ | 2,239,850 | ||||
Accrued Taxes Payable | 302,774 | 214,726 | ||||||
Dividends Payable | 166,215 | 126,971 | ||||||
Current Portion of Long-Term Debt | 1,014,200 | 913,093 | ||||||
Current Portion of Operating Lease Liabilities | 384,348 | - | ||||||
Other | 211,096 | 233,724 | ||||||
Total | 4,473,713 | 3,728,364 | ||||||
Long-Term Debt | 4,163,115 | 5,170,169 | ||||||
Other Liabilities | 1,858,357 | 1,258,355 | ||||||
Deferred Income Taxes | 4,922,804 | 4,413,398 | ||||||
Commitments and Contingencies | ||||||||
Stockholders' Equity | ||||||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and | 205,821 | 205,804 | ||||||
Additional Paid in Capital | 5,769,073 | 5,658,794 | ||||||
Accumulated Other Comprehensive Loss | (3,689) | (1,358) | ||||||
Retained Earnings | 15,179,381 | 13,543,130 | ||||||
Common Stock Held in Treasury, 289,903 Shares at September 30, 2019 | (26,306) | (42,182) | ||||||
Total Stockholders' Equity | 21,124,280 | 19,364,188 | ||||||
Total Liabilities and Stockholders' Equity | $ | 36,542,269 | $ | 33,934,474 |
EOG RESOURCES, INC. | |||||||||||
Summary Statements of Cash Flows | |||||||||||
(Unaudited; in thousands) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Cash Flows from Operating Activities | |||||||||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||||||||
Net Income | $ | 615,122 | $ | 1,190,952 | $ | 2,098,389 | $ | 2,526,272 | |||
Items Not Requiring (Providing) Cash | |||||||||||
Depreciation, Depletion and Amortization | 953,597 | 918,180 | 2,790,496 | 2,515,445 | |||||||
Impairments | 105,275 | 44,617 | 289,761 | 160,934 | |||||||
Stock-Based Compensation Expenses | 54,670 | 49,001 | 132,323 | 116,290 | |||||||
Deferred Income Taxes | 184,282 | 334,116 | 508,576 | 681,702 | |||||||
(Gains) Losses on Asset Dispositions, Net | 523 | (115,944) | (3,650) | (94,658) | |||||||
Other, Net | (1,284) | 1,807 | 4,155 | 15,314 | |||||||
Dry Hole Costs | 24,138 | 358 | 28,001 | 5,260 | |||||||
Mark-to-Market Commodity Derivative Contracts | |||||||||||
Total (Gains) Losses | (85,902) | 52,081 | (242,622) | 297,735 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity | 108,418 | (91,894) | 139,708 | (180,228) | |||||||
Other, Net | (424) | 1,913 | 1,215 | 1,652 | |||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||
Accounts Receivable | 63,891 | (243,778) | (5,855) | (553,529) | |||||||
Inventories | 66,857 | (94,598) | 55,598 | (286,817) | |||||||
Accounts Payable | 7,400 | 81,548 | 134,253 | 537,525 | |||||||
Accrued Taxes Payable | 34,767 | (59,426) | 88,047 | (36,891) | |||||||
Other Assets | (92,814) | (40,491) | 394,573 | (103,334) | |||||||
Other Liabilities | 39,791 | 38,392 | (18,315) | (14,776) | |||||||
Changes in Components of Working Capital Associated with Investing and | (16,643) | 122,763 | (38,677) | 95,484 | |||||||
Net Cash Provided by Operating Activities | 2,061,664 | 2,189,597 | 6,355,976 | 5,683,380 | |||||||
Investing Cash Flows | |||||||||||
Additions to Oil and Gas Properties | (1,420,385) | (1,591,646) | (4,866,882) | (4,571,932) | |||||||
Additions to Other Property, Plant and Equipment | (70,469) | (57,526) | (187,350) | (202,384) | |||||||
Proceeds from Sales of Assets | 17,767 | 3,306 | 35,409 | 11,582 | |||||||
Other Investing Activities | - | (19,993) | - | (19,993) | |||||||
Changes in Components of Working Capital Associated with Investing Activities | 16,621 | (122,791) | 38,677 | (95,541) | |||||||
Net Cash Used in Investing Activities | (1,456,466) | (1,788,650) | (4,980,146) | (4,878,268) | |||||||
Financing Cash Flows | |||||||||||
Long-Term Debt Repayments | - | - | (900,000) | - | |||||||
Dividends Paid | (166,170) | (107,465) | (420,851) | (311,075) | |||||||
Treasury Stock Purchased | (13,835) | (26,535) | (22,238) | (58,558) | |||||||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 863 | 953 | 9,558 | 12,098 | |||||||
Debt Issuance Costs | (114) | - | (5,016) | - | |||||||
Repayment of Capital Lease Obligation | (3,235) | (1,698) | (9,638) | (5,052) | |||||||
Changes in Components of Working Capital Associated with Financing Activities | 22 | 28 | - | 57 | |||||||
Net Cash Used in Financing Activities | (182,469) | (134,717) | (1,348,185) | (362,530) | |||||||
Effect of Exchange Rate Changes on Cash | (109) | (313) | (174) | (2,678) | |||||||
Increase in Cash and Cash Equivalents | 422,620 | 265,917 | 27,471 | 439,904 | |||||||
Cash and Cash Equivalents at Beginning of Period | 1,160,485 | 1,008,215 | 1,555,634 | 834,228 | |||||||
Cash and Cash Equivalents at End of Period | $ | 1,583,105 | $ | 1,274,132 | $ | 1,583,105 | $ | 1,274,132 |
EOG RESOURCES, INC. | |||||||||||||
Third Quarter 2019 Well Results by Play | |||||||||||||
(Unaudited) | |||||||||||||
Wells On Line | Initial Gross 30-Day Average Production Rate | ||||||||||||
Gross | Net | Lateral | Crude Oil and | Natural Gas | Natural Gas | Crude Oil | |||||||
Delaware Basin | |||||||||||||
Wolfcamp | 51 | 48 | 7,300 | 1,950 | 650 | 3.3 | 3,150 | ||||||
Bone Spring | 24 | 21 | 5,900 | 1,600 | 350 | 1.9 | 2,300 | ||||||
Leonard | 2 | 1 | 9,700 | 2,000 | 600 | 3.0 | 3,100 | ||||||
South Texas Eagle Ford | 81 | 74 | 7,900 | 1,150 | 100 | 0.6 | 1,350 | ||||||
South Texas Austin Chalk | 4 | 2 | 4,600 | 1,850 | 350 | 1.8 | 2,500 | ||||||
Powder River Basin | |||||||||||||
Turner / Parkman | 7 | 6 | 9,800 | 800 | 200 | 3.3 | 1,550 | ||||||
Niobrara | 1 | 1 | 10,200 | 1,250 | 250 | 4.0 | 2,200 | ||||||
DJ Basin Codell / Niobrara | 5 | 4 | 9,700 | 800 | 50 | 0.4 | 900 | ||||||
Williston Basin Bakken/Three Forks | 15 | 13 | 10,600 | 2,150 | 300 | 2.0 | 2,800 | ||||||
Anadarko Basin Woodford Oil Window | 16 | 14 | 9,900 | 950 | 100 | 0.7 | 1,150 |
(A) Barrels per day or million cubic feet per day, as applicable. | |||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Reconciliation of Adjusted Net Income | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG's assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||
September 30, 2019 | September 30, 2018 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $ 797,457 | $(182,335) | $ 615,122 | $ 1.06 | $1,446,363 | $(255,411) | $1,190,952 | $ 2.05 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity | (85,902) | 18,854 | (67,048) | (0.12) | 52,081 | (11,472) | 40,609 | 0.07 | |||||||
Net Cash Received from (Payments for) | 108,418 | (23,796) | 84,622 | 0.15 | (91,894) | 20,241 | (71,653) | (0.12) | |||||||
Add: (Gains) Losses on Asset Dispositions, Net | 523 | (89) | 434 | - | (115,944) | 28,934 | (87,010) | (0.15) | |||||||
Add: Certain Impairments | 27,215 | (5,973) | 21,242 | 0.04 | - | - | - | - | |||||||
Less: Tax Reform Impact | - | - | - | - | - | (57,127) | (57,127) | (0.10) | |||||||
Adjustments to Net Income | 50,254 | (11,004) | 39,250 | 0.07 | (155,757) | (19,424) | (175,181) | (0.30) | |||||||
Adjusted Net Income (Non-GAAP) | $ 847,711 | $(193,339) | $ 654,372 | $ 1.13 | $1,290,606 | $(274,835) | $1,015,771 | $ 1.75 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,839 | 577,254 | |||||||||||||
Diluted | 581,271 | 581,559 | |||||||||||||
Nine Months Ended | Nine Months Ended | ||||||||||||||
September 30, 2019 | September 30, 2018 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $2,714,059 | $(615,670) | $2,098,389 | $ 3.61 | $3,152,658 | $(626,386) | $2,526,272 | $ 4.35 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity | (242,622) | 53,251 | (189,371) | (0.34) | 297,735 | (65,582) | 232,153 | 0.40 | |||||||
Net Cash Received from (Payments for) | 139,708 | (30,663) | 109,045 | 0.19 | (180,228) | 39,699 | (140,529) | (0.24) | |||||||
Add: (Gains) Losses on Asset Dispositions, Net | (3,650) | 910 | (2,740) | - | (94,658) | 24,235 | (70,423) | (0.12) | |||||||
Add: Certain Impairments | 116,249 | (25,514) | 90,735 | 0.16 | 20,876 | (4,598) | 16,278 | 0.03 | |||||||
Less: Tax Reform Impact | - | - | - | - | - | (63,651) | (63,651) | (0.11) | |||||||
Adjustments to Net Income | 9,685 | (2,016) | 7,669 | 0.01 | 43,725 | (69,897) | (26,172) | (0.04) | |||||||
Adjusted Net Income (Non-GAAP) | $2,723,744 | $(617,686) | $2,106,058 | $ 3.62 | $3,196,383 | $(696,283) | $2,500,100 | $ 4.31 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,498 | 576,431 | |||||||||||||
Diluted | 581,190 | 580,442 |
EOG RESOURCES, INC. | |||||||||||
Reconciliation of Discretionary Cash Flow | |||||||||||
(Unaudited; in thousands) | |||||||||||
Calculation of Free Cash Flow | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart reconciles the three-month and nine-month periods ended September 30, 2019 and 2018 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable (Payable), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures before acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and nine months ended September 30, 2019 and 2018. EOG management uses this information for comparative purposes within the industry. | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 2,061,664 | $ | 2,189,597 | $ | 6,355,976 | $ | 5,683,380 | |||
Adjustments: | |||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 29,374 | 27,032 | 85,250 | 96,716 | |||||||
Other Non-Current Income Taxes - Net Receivable (Payable) | 33,855 | (129,941) | 179,537 | 62,421 | |||||||
Changes in Components of Working Capital and Other Assets | |||||||||||
and Liabilities | |||||||||||
Accounts Receivable | (63,891) | 243,778 | 5,855 | 553,529 | |||||||
Inventories | (66,857) | 94,598 | (55,598) | 286,817 | |||||||
Accounts Payable | (7,400) | (81,548) | (134,253) | (537,525) | |||||||
Accrued Taxes Payable | (34,767) | 59,426 | (88,047) | 36,891 | |||||||
Other Assets | 92,814 | 40,491 | (394,573) | 103,334 | |||||||
Other Liabilities | (39,791) | (38,392) | 18,315 | 14,776 | |||||||
Changes in Components of Working Capital Associated with | |||||||||||
Investing and Financing Activities | 16,643 | (122,763) | 38,677 | (95,484) | |||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,021,644 | $ | 2,282,278 | $ | 6,011,139 | $ | 6,204,855 | |||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease | -11% | -3% | |||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,021,644 | $ | 2,282,278 | $ | 6,011,139 | $ | 6,204,855 | |||
Less: | |||||||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP)(a) | (1,518,019) | (1,671,922) | (4,846,221) | (4,869,951) | |||||||
Dividends Paid (GAAP) | (166,170) | (107,465) | (420,851) | (311,075) | |||||||
Free Cash Flow (Non-GAAP) | $ | 337,455 | $ | 502,891 | $ | 744,067 | $ | 1,023,829 | |||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three-months and nine-month periods ended September 30, 2019 and 2018: | |||||||||||
Total Expenditures (GAAP) | $ | 1,629,343 | $ | 1,828,348 | $ | 5,394,389 | $ | 5,201,921 | |||
Less: | |||||||||||
Asset Retirement Costs | (90,970) | (10,834) | (151,551) | (41,789) | |||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | - | (1,257) | (586) | (48,937) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | (10,666) | (101,821) | (64,387) | (161,823) | |||||||
Acquisition Costs of Proved Properties | (9,688) | (42,514) | (331,644) | (79,421) | |||||||
Total Cash Capital Expenditures Before Acquisitions (Non-GAAP) | $ | 1,518,019 | $ | 1,671,922 | $ | 4,846,221 | $ | 4,869,951 | |||
EOG RESOURCES, INC. | |||||||||||
Total Expenditures | |||||||||||
(Unaudited; in millions) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Exploration and Development Drilling | $1,173 | $1,340 | $3,865 | $3,843 | |||||||
Facilities | 161 | 178 | 499 | 518 | |||||||
Leasehold Acquisitions | 56 | 159 | 201 | 331 | |||||||
Property Acquisitions | 10 | 42 | 332 | 79 | |||||||
Capitalized Interest | 10 | 7 | 28 | 18 | |||||||
Subtotal | 1,410 | 1,726 | 4,925 | 4,789 | |||||||
Exploration Costs | 34 | 33 | 103 | 115 | |||||||
Dry Hole Costs | 24 | - | 28 | 5 | |||||||
Exploration and Development Expenditures | 1,468 | 1,759 | 5,056 | 4,909 | |||||||
Asset Retirement Costs | 91 | 11 | 151 | 42 | |||||||
Total Exploration and Development Expenditures | 1,559 | 1,770 | 5,207 | 4,951 | |||||||
Other Property, Plant and Equipment | 70 | 58 | 187 | 251 | |||||||
Total Expenditures | $1,629 | $1,828 | $5,394 | $5,202 | |||||||
EOG RESOURCES, INC. | |||||||||||
Reconciliation of Adjusted EBITDAX | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Net Income (GAAP) | $ | 615,122 | $ | 1,190,952 | $ | 2,098,389 | $ | 2,526,272 | |||
Adjustments: | |||||||||||
Interest Expense, Net | 39,620 | 63,632 | 144,434 | 189,032 | |||||||
Income Tax Provision | 182,335 | 255,411 | 615,670 | 626,386 | |||||||
Depreciation, Depletion and Amortization | 953,597 | 918,180 | 2,790,496 | 2,515,445 | |||||||
Exploration Costs | 34,540 | 32,823 | 103,386 | 115,137 | |||||||
Dry Hole Costs | 24,138 | 358 | 28,001 | 5,260 | |||||||
Impairments | 105,275 | 44,617 | 289,761 | 160,934 | |||||||
EBITDAX (Non-GAAP) | 1,954,627 | 2,505,973 | 6,070,137 | 6,138,466 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | (85,902) | 52,081 | (242,622) | 297,735 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity | 108,418 | (91,894) | 139,708 | (180,228) | |||||||
(Gains) Losses on Asset Dispositions, Net | 523 | (115,944) | (3,650) | (94,658) | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 1,977,666 | $ | 2,350,216 | $ | 5,963,573 | $ | 6,161,315 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease | -16% | -3% |
EOG RESOURCES, INC. | ||||||||
Reconciliation of Net Debt and Total Capitalization | ||||||||
Calculation of Net Debt-to-Total Capitalization Ratio | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||||||
At | At | At | ||||||
September 30, | December 31, | September 30, | ||||||
2019 | 2018 | 2018 | ||||||
Total Stockholders' Equity - (a) | $ | 21,124 | $ | 19,364 | $ | 18,538 | ||
Current and Long-Term Debt (GAAP) - (b) | 5,177 | 6,083 | 6,435 | |||||
Less: Cash | (1,583) | (1,556) | (1,274) | |||||
Net Debt (Non-GAAP) - (c) | 3,594 | 4,527 | 5,161 | |||||
Total Capitalization (GAAP) - (a) + (b) | $ | 26,301 | $ | 25,447 | $ | 24,973 | ||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 24,718 | $ | 23,891 | $ | 23,699 | ||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 20% | 24% | 26% | |||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 15% | 19% | 22% |
EOG RESOURCES, INC. | |||||||||
Reconciliation of Total Exploration and Development Expenditures | |||||||||
For Drilling Only and Total Exploration and Development Expenditures | |||||||||
Calculation of Reserve Replacement Costs ($ / BOE) | |||||||||
(Unaudited; in millions, except ratio data) | |||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | |||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $6,419.7 | $4,439.4 | $ 6,445.2 | $4,928.3 | $7,904.8 | ||||
Less: Asset Retirement Costs | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | ||||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | (255.7) | (3,101.8) | - | - | ||||
Acquisition Costs of Proved Properties | (123.7) | (72.6) | (749.0) | (480.6) | (139.1) | ||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) (a) | $5,935.8 | $4,055.5 | $ 2,614.3 | $4,394.2 | $7,570.1 | ||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $6,419.7 | $4,439.4 | $ 6,445.2 | $4,928.3 | $7,904.8 | ||||
Less: Asset Retirement Costs | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | ||||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | (255.7) | (3,101.8) | - | - | ||||
Non-Cash Acquisition Costs of Proved Properties | (70.9) | (26.2) | (732.3) | - | - | ||||
Total Exploration and Development Expenditures (Non-GAAP) (b) | $5,988.6 | $4,101.9 | $ 2,631.0 | $4,874.8 | $7,709.2 | ||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||||
Revisions Due to Price (c) | 34.8 | 154.0 | (100.7) | (573.8) | 52.2 | ||||
Revisions Other Than Price | (39.5) | 48.0 | 252.9 | 107.2 | 48.4 | ||||
Purchases in Place | 11.6 | 2.3 | 42.3 | 56.2 | 14.4 | ||||
Extensions, Discoveries and Other Additions (d) | 669.7 | 420.8 | 209.0 | 245.9 | 519.2 | ||||
Total Proved Reserve Additions (e) | 676.6 | 625.1 | 403.5 | (164.5) | 634.2 | ||||
Sales in Place | (10.8) | (20.7) | (167.6) | (3.5) | (36.3) | ||||
Net Proved Reserve Additions From All Sources (f) | 665.8 | 604.4 | 235.9 | (168.0) | 597.9 | ||||
Production (g) | 265.0 | 224.4 | 207.1 | 211.2 | 219.1 | ||||
RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||||
Total Drilling, Before Revisions (a / d) | $ 8.86 | $ 9.64 | $ 12.51 | $ 17.87 | $ 14.58 | ||||
All-in Total, Net of Revisions (b / e) | $ 8.85 | $ 6.56 | $ 6.52 | $(29.63) | $ 12.16 | ||||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) | $ 9.33 | $ 8.71 | $ 5.22 | $ 11.91 | $ 13.25 |
EOG RESOURCES, INC. | |||
Crude Oil and Natural Gas Financial Commodity | |||
Derivative Contracts | |||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through October 29, 2019. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||
Midland Differential Basis Swap Contracts | |||
Weighted | |||
Average Price | |||
Volume | Differential | ||
(Bbld) | ($/Bbl) | ||
2019 | |||
January 1, 2019 through November 30, 2019 (closed) | 20,000 | $ 1.075 | |
December 2019 | 20,000 | 1.075 | |
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through October 29, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||
Gulf Coast Differential Basis Swap Contracts | |||
Weighted | |||
Average Price | |||
Volume | Differential | ||
(Bbld) | ($/Bbl) | ||
2019 | |||
January 1, 2019 through November 30, 2019 (closed) | 13,000 | $ 5.572 | |
December 2019 | 13,000 | 5.572 | |
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through October 29, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||
Crude Oil Price Swap Contracts | |||
Weighted | |||
Volume | Average Price | ||
(Bbld) | ($/Bbl) | ||
2019 | |||
April 2019 (closed) | 25,000 | $ 60.00 | |
May 1, 2019 through September 30, 2019 (closed) | 150,000 | 62.50 | |
October 1, 2019 through December 31, 2019 | 150,000 | 62.50 | |
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through October 29, 2019. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts. | |||
Rockies Differential Basis Swap Contracts | |||
Weighted | |||
Average Price | |||
Volume | Differential | ||
(MMBtud) | ($/MMBtu) | ||
2020 | |||
January 1, 2020 through December 31, 2020 | 30,000 | $ 0.549 | |
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 29, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||
Natural Gas Price Swap Contracts | |||
Weighted | |||
Volume | Average Price | ||
(MMBtud) | ($/MMBtu) | ||
2019 | |||
April 1, 2019 through October 31, 2019 (closed) | 250,000 | $ 2.90 |
Definitions | |
Bbld | Barrels per day |
$/Bbl | Dollars per barrel |
MMBtud | Million British thermal units per day |
$/MMBtu | Dollars per million British thermal units |
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, | ||||||||
Net Debt and Total Capitalization | ||||||||
Calculations of Return on Capital Employed and Return on Equity | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2018 | 2017 | |||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||
Net Interest Expense (GAAP) | $ | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (51) | |||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 194 | ||||||
Net Income (GAAP) - (b) | $ | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Accompanying | (201) | (1) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 3,218 | ||||||
Total Stockholders' Equity - (d) | $ | 19,364 | $ | 16,283 | ||||
Average Total Stockholders' Equity * - (e) | $ | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | $ | 6,083 | $ | 6,387 | ||||
Less: Cash | (1,556) | (834) | ||||||
Net Debt (Non-GAAP) - (g) | $ | 4,527 | $ | 5,553 | ||||
Total Capitalization (GAAP) - (d) + (f) | $ | 25,447 | $ | 22,670 | ||||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 23,891 | $ | 21,836 | ||||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 22,864 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.8% | |||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 14.9% | |||||||
Return on Equity (ROE) | ||||||||
ROE (GAAP Net Income) - (b) / (e) | 19.2% | |||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 18.1% | |||||||
* Average for the current and immediately preceding year | ||||||||
Adjustments to Net Income (GAAP) | ||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: | ||||||||
Year Ended December 31, 2018 | ||||||||
Before | Income Tax | After | ||||||
Tax | Impact | Tax | ||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (93) | $ | 20 | $ | (73) | ||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | - | (110) | (110) | |||||
Total | $ | (115) | $ | (86) | $ | (201) |
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | $ | 235 |
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | $ | 153 |
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | $ | 2,197 |
Total Stockholders' Equity - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 |
Average Total Stockholders' Equity * - (e) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | $ | 14,352 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 |
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 |
Total Capitalization (GAAP) - (d) + (f) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 21,836 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,602 | $ | 19,124 | $ | 20,206 | $ | 20,771 | $ | 19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 13.4% | -4.8% | -21.6% | 14.7% | 12.1% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.1% | -8.1% | -29.5% | 17.6% | 15.3% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 |
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 |
Net Income (Loss) (GAAP) - (b) | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 |
Total Stockholders' Equity - (d) | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 |
Average Total Stockholders' Equity * - (e) | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 |
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 |
Total Capitalization (GAAP) - (d) + (f) | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 4.4% | 9.5% | 1.6% | 5.8% | 30.5% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 |
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 |
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 |
Total Stockholders' Equity - (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 |
Average Total Stockholders' Equity * - (e) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 |
Current and Long-Term Debt (GAAP) - (f) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 |
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 |
Total Capitalization (GAAP) - (d) + (f) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 60 | $ | 45 | $ | 61 | $ | 62 | ||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 39 | $ | 29 | $ | 40 | $ | 40 | ||
Net Income (Loss) (GAAP) - (b) | $ | 87 | $ | 399 | $ | 397 | $ | 569 | ||
Total Stockholders' Equity - (d) | $ | 1,672 | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 |
Average Total Stockholders' Equity * - (e) | $ | 1,658 | $ | 1,512 | $ | 1,256 | $ | 1,205 | ||
Current and Long-Term Debt (GAAP) - (f) | $ | 1,145 | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 |
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,135 | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 |
Total Capitalization (GAAP) - (d) + (f) | $ | 2,817 | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 2,807 | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 2,652 | $ | 2,358 | $ | 2,158 | $ | 2,256 | ||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.8% | 18.2% | 20.2% | 27.0% | ||||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 5.2% | 26.4% | 31.6% | 47.2% | ||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 348,883 | $ 321,568 | $1,032,455 | $ 936,236 | |||||||
Transportation Costs | 199,365 | 196,027 | 549,988 | 550,781 | |||||||
General and Administrative | 135,758 | 111,284 | 364,210 | 310,065 | |||||||
Cash Operating Expenses | 684,006 | 628,879 | 1,946,653 | 1,797,082 | |||||||
Less: Non-GAAP Adjustments | - | - | - | - | |||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 684,006 | $ 628,879 | $1,946,653 | $1,797,082 | |||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 76,748 | 68,890 | 220,334 | 192,182 | |||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 8.92 | (c) | $ 9.13 | (d) | $ 8.84 | (e) | $ 9.35 | (f) | |||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
Three Months Ended September 30, 2019 compared to Three Months | -2% | ||||||||||
Nine Months Ended September 30, 2019 compared to Nine Months Ended | -6% | ||||||||||
* Includes stock compensation expense and other non-cash items. | |||||||||||
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $1,282,678 | $1,044,847 | $ 927,452 | $1,182,282 | $1,416,413 | ||||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 2,456,523 | 2,219,666 | 2,086,373 | 2,398,195 | 2,790,599 | ||||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||||
Less: Acquisition Costs - Yates Transaction | - | - | (5,100) | - | - | ||||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $2,456,523 | $2,201,880 | $2,039,219 | $2,378,840 | $2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.36 | (c) | $ 9.91 | (d) | $ 9.95 | (e) | $ 11.39 | (f) | $ 12.86 | (g) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
2018 compared to 2017 - [(c) - (d)] / (d) | -6% | ||||||||||
2018 compared to 2016 - [(c) - (e)] / (e) | -6% | ||||||||||
2018 compared to 2015 - [(c) - (f)] / (f) | -18% | ||||||||||
2018 compared to 2014 - [(c) - (g)] / (g) | -27% | ||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | |||||||||
Cost per Barrel of Oil Equivalent (Boe) | |||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||
Three Months Ended | Year-to-Date | ||||||||
March 31, | June 30, | September 30, | September 30, | ||||||
2019 | 2019 | 2019 | 2019 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 69,623 | 73,964 | 76,748 | 220,334 | |||||
Crude Oil and Condensate | $ 2,200,403 | $ 2,528,866 | $ 2,418,989 | $ 7,148,258 | |||||
Natural Gas Liquids | 218,638 | 186,374 | 164,736 | 569,748 | |||||
Natural Gas | 334,972 | 269,892 | 269,625 | 874,489 | |||||
Total Wellhead Revenues - (b) | $ 2,754,013 | $ 2,985,132 | $ 2,853,350 | $ 8,592,495 | |||||
Operating Costs | |||||||||
Lease and Well | $ 336,291 | $ 347,281 | $ 348,883 | $ 1,032,455 | |||||
Transportation Costs | 176,522 | 174,101 | 199,365 | 549,988 | |||||
Gathering and Processing Costs | 111,295 | 112,643 | 127,549 | 351,487 | |||||
General and Administrative | 106,672 | 121,780 | 135,758 | 364,210 | |||||
Taxes Other Than Income | 192,906 | 204,414 | 203,098 | 600,418 | |||||
Interest Expense, Net | 54,906 | 49,908 | 39,620 | 144,434 | |||||
Total Cash Operating Cost (excluding DD&A and Total | $ 978,592 | $ 1,010,127 | $ 1,054,273 | $ 3,042,992 | |||||
Depreciation, Depletion and Amortization (DD&A) | 879,595 | 957,304 | 953,597 | 2,790,496 | |||||
Total Operating Cost (excluding Total Exploration Costs) - (d) | $ 1,858,187 | $ 1,967,431 | $ 2,007,870 | $ 5,833,488 | |||||
Exploration Costs | $ 36,324 | $ 32,522 | $ 34,540 | $ 103,386 | |||||
Dry Hole Costs | 94 | 3,769 | 24,138 | 28,001 | |||||
Impairments | 72,356 | 112,130 | 105,275 | 289,761 | |||||
Total Exploration Costs | 108,774 | 148,421 | 163,953 | 421,148 | |||||
Less: Certain Impairments (Non-GAAP) | (23,745) | (65,289) | (27,215) | (116,249) | |||||
Total Exploration Costs (Non-GAAP) | $ 85,029 | $ 83,132 | $ 136,738 | $ 304,899 | |||||
Total Operating Cost (Non-GAAP) (including Total | $ 1,943,216 | $ 2,050,563 | $ 2,144,608 | $ 6,138,387 | |||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 39.56 | $ 40.36 | $ 37.18 | $ 39.00 | |||||
Total Cash Operating Cost per Boe (excluding DD&A | $ 14.06 | $ 13.65 | $ 13.75 | $ 13.83 | |||||
Composite Average Margin per Boe (excluding DD&A | $ 25.50 | $ 26.71 | $ 23.43 | $ 25.17 | |||||
Total Operating Cost per Boe (excluding Total | $ 26.69 | $ 26.59 | $ 26.18 | $ 26.50 | |||||
Composite Average Margin per Boe (excluding Total | $ 12.87 | $ 13.77 | $ 11.00 | $ 12.50 | |||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 27.91 | $ 27.72 | $ 27.97 | $ 27.88 | |||||
Composite Average Margin per Boe (Non-GAAP) | $ 11.65 | $ 12.64 | $ 9.21 | $ 11.12 | |||||
EOG RESOURCES, INC. | |||||||||
Cost per Barrel of Oil Equivalent (Boe) | |||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||
Year Ended | |||||||||
December 31, | |||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||
Crude Oil and Condensate | $ 9,517,440 | $ 6,256,396 | $ 4,317,341 | $ 4,934,562 | $ 9,742,480 | ||||
Natural Gas Liquids | 1,127,510 | 729,561 | 437,250 | 407,658 | 934,051 | ||||
Natural Gas | 1,301,537 | 921,934 | 742,152 | 1,061,038 | 1,916,386 | ||||
Total Wellhead Revenues - (b) | $ 11,946,487 | $ 7,907,891 | $ 5,496,743 | $ 6,403,258 | $ 12,592,917 | ||||
Operating Costs | |||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||
Gathering and Processing Costs | 436,973 | 148,775 | 122,901 | 146,156 | 145,800 | ||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||
Less: Acquisition Costs | - | - | (5,100) | - | - | ||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||
General and Administrative (Non-GAAP) | 426,969 | 416,681 | 347,661 | 347,239 | 402,010 | ||||
Taxes Other Than Income | 772,481 | 544,662 | 349,710 | 421,744 | 757,564 | ||||
Interest Expense, Net | 245,052 | 274,372 | 281,681 | 237,393 | 201,458 | ||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A | $ 3,911,029 | $ 3,169,689 | $ 2,793,511 | $ 3,184,133 | $ 3,895,421 | ||||
Depreciation, Depletion and Amortization (DD&A) | 3,435,408 | 3,409,387 | 3,553,417 | 3,313,644 | 3,997,041 | ||||
Total Operating Cost (Non-GAAP) (excluding Total | $ 7,346,437 | $ 6,579,076 | $ 6,346,928 | $ 6,497,777 | $ 7,892,462 | ||||
Exploration Costs | $ 148,999 | $ 145,342 | $ 124,953 | $ 149,494 | $ 184,388 | ||||
Dry Hole Costs | 5,405 | 4,609 | 10,657 | 14,746 | 48,490 | ||||
Impairments | 347,021 | 479,240 | 620,267 | 6,613,546 | 743,575 | ||||
Total Exploration Costs | 501,425 | 629,191 | 755,877 | 6,777,786 | 976,453 | ||||
Less: Certain Impairments (Non-GAAP) | (152,671) | (261,452) | (320,617) | (6,307,593) | (824,312) | ||||
Total Exploration Costs (Non-GAAP) | $ 348,754 | $ 367,739 | $ 435,260 | $ 470,193 | $ 152,141 | ||||
Total Operating Cost (Non-GAAP) (including Total | $ 7,695,191 | $ 6,946,815 | $ 6,782,188 | $ 6,967,970 | $ 8,044,603 | ||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 45.51 | $ 35.58 | $ 26.82 | $ 30.66 | $ 58.01 | ||||
Total Cash Operating Cost per Boe (Non-GAAP) | $ 14.90 | $ 14.25 | $ 13.64 | $ 15.25 | $ 17.95 | ||||
Composite Average Margin per Boe (Non-GAAP) (excluding | $ 30.61 | $ 21.33 | $ 13.18 | $ 15.41 | $ 40.06 | ||||
Total Operating Cost per Boe (Non-GAAP) (excluding | $ 27.99 | $ 29.59 | $ 30.98 | $ 31.11 | $ 36.38 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 17.52 | $ 5.99 | $ (4.16) | $ (0.45) | $ 21.63 | ||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 29.32 | $ 31.24 | $ 33.10 | $ 33.36 | $ 37.08 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 16.19 | $ 4.34 | $ (6.28) | $ (2.70) | $ 20.93 |
EOG RESOURCES, INC. | |||||||||||
Fourth Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Fourth Quarter and Full Year 2019 Forecast | |||||||||||
The forecast items for the fourth quarter and full year 2019 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Capital Expenditures | |||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. | |||||||||||
(c) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2019 | Full Year 2019 | ||||||||||
Daily Sales Volumes | |||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||
United States | 459.5 | - | 469.5 | 453.3 | - | 455.8 | |||||
Trinidad | 0.4 | - | 0.6 | 0.6 | - | 0.7 | |||||
Other International | 0.0 | - | 0.2 | 0.1 | - | 0.1 | |||||
Total | 459.9 | - | 470.3 | 454.0 | - | 456.6 | |||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||
Total | 135.0 | - | 145.0 | 131.8 | - | 134.4 | |||||
Natural Gas Volumes (MMcfd) | |||||||||||
United States | 1,085 | - | 1,145 | 1,054 | - | 1,069 | |||||
Trinidad | 225 | - | 255 | 256 | - | 264 | |||||
Other International | 34 | - | 38 | 36 | - | 37 | |||||
Total | 1,344 | - | 1,438 | 1,346 | - | 1,370 | |||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||
United States | 775.3 | - | 805.3 | 760.7 | - | 768.3 | |||||
Trinidad | 37.9 | - | 43.1 | 43.3 | - | 44.6 | |||||
Other International | 5.7 | - | 6.5 | 6.1 | - | 6.3 | |||||
Total | 818.9 | - | 854.9 | 810.1 | - | 819.2 | |||||
Capital Expenditures ($MM) | $ | 1,400 | - | $ | 1,600 | $ | 6,200 | - | $ | 6,400 | |
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2019 | Full Year 2019 | ||||||||||
Operating Costs | |||||||||||
Unit Costs ($/Boe) | |||||||||||
Lease and Well | $ | 4.50 | - | $ | 4.80 | $ | 4.65 | - | $ | 4.75 | |
Transportation Costs | $ | 2.55 | - | $ | 3.05 | $ | 2.50 | - | $ | 2.60 | |
Depreciation, Depletion and Amortization | $ | 12.45 | - | $ | 12.85 | $ | 12.60 | - | $ | 12.70 | |
Expenses ($MM) | |||||||||||
Exploration and Dry Hole | $ | 35 | - | $ | 45 | $ | 165 | - | $ | 175 | |
Impairment | $ | 95 | - | $ | 105 | $ | 270 | - | $ | 280 | |
General and Administrative | $ | 110 | - | $ | 120 | $ | 470 | - | $ | 490 | |
Gathering and Processing | $ | 130 | - | $ | 140 | $ | 480 | - | $ | 490 | |
Capitalized Interest | $ | 9 | - | $ | 11 | $ | 37 | - | $ | 39 | |
Net Interest | $ | 39 | - | $ | 41 | $ | 183 | - | $ | 185 | |
Taxes Other Than Income (% of Wellhead Revenue) | 6.9% | - | 7.3% | 6.8% | - | 7.2% | |||||
Income Taxes | |||||||||||
Effective Rate | 21% | - | 26% | 21% | - | 26% | |||||
Current Tax (Benefit) / Expense ($MM) | $ | (40) | - | $ | 0 | $ | (110) | - | $ | (70) | |
Pricing - (Refer toBenchmark Commodity Pricingin text) | |||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||
Differentials | |||||||||||
United States - above (below) WTI | $ | (1.85) | - | $ | 0.15 | $ | 0.15 | - | $ | 0.65 | |
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (10.00) | - | $ | (9.00) | |
Other International - above (below) WTI | $ | (1.00) | - | $ | 3.00 | $ | 0.69 | - | $ | 2.00 | |
Natural Gas Liquids | |||||||||||
Realizations as % of WTI | 20% | - | 28% | 26% | - | 28% | |||||
Natural Gas ($/Mcf) | |||||||||||
Differentials | |||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.70) | - | $ | (0.30) | $ | (0.50) | - | $ | (0.40) | |
Realizations | |||||||||||
Trinidad | $ | 2.50 | - | $ | 2.90 | $ | 2.65 | - | $ | 2.75 | |
Other International | $ | 3.80 | - | $ | 4.20 | $ | 4.10 | - | $ | 4.30 |
Definitions | |
$/Bbl | U.S. Dollars per barrel |
$/Boe | U.S. Dollars per barrel of oil equivalent |
$/Mcf | U.S. Dollars per thousand cubic feet |
$MM | U.S. Dollars in millions |
MBbld | Thousand barrels per day |
Mboed | Thousand barrels of oil equivalent per day |
MMcfd | Million cubic feet per day |
NYMEX | U.S. New York Mercantile Exchange |
WTI | West Texas Intermediate |
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SOURCE EOG Resources, Inc.
HOUSTON, Oct. 29, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the Bank of America Merrill Lynch Global Energy Conference at 8:30 a.m. Central time (9:30 a.m. Eastern time) on Wednesday, November 13. Lloyd W. "Billy" Helms, Jr., Chief Operating Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available for 90 days.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conference-300947594.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 24, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss third quarter 2019 results on Thursday, November 7, 2019, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-third-quarter-2019-results-for-november-7-2019-300924633.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 12, 2019 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (EOG) has declared a dividend of $0.2875 per share on EOG's Common Stock, payable October 31, 2019, to stockholders of record as of October 17, 2019. The indicated annual rate is $1.15.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 27, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the Barclays CEO Energy-Power Conference at 8:45 a.m. Central time (9:45 a.m. Eastern time) on Wednesday, September 4. Lloyd W. "Billy" Helms, Jr., Chief Operating Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available for six months.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conference-300908000.html
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 1, 2019 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported second quarter 2019 net income of $848 million, or $1.46 per share, compared with second quarter 2018 net income of $697 million, or $1.20 per share. Net cash provided by operating activities for the second quarter 2019 was $2.7 billion.
Adjusted non-GAAP net income for the second quarter 2019 was $762 million, or $1.31 per share, compared with adjusted non-GAAP net income of $795 million, or $1.37 per share, for the same prior year period.
EOG generated $2.1 billion of discretionary cash flow in the second quarter 2019, one percent more than the same prior year period despite a 12 percent decline in the NYMEX WTI benchmark price. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Second Quarter 2019 Operating Review
EOG delivered excellent operational and financial results in the second quarter 2019, extending its strong momentum from the first quarter. The company continues to benefit from operating a consistently-paced development program with meaningful scale across multiple basins. Innovations in drilling, completions and production, along with targeted infrastructure investments, are contributing to the capital productivity improvements realized through the second quarter.
For the second consecutive quarter, crude oil production volumes exceeded the target range while capital expenditures were below the target range. Second quarter 2019 total company crude oil volumes grew 18 percent year-over-year to 455,700 barrels of oil per day, a new company record. Compared to the second quarter 2018, natural gas liquids (NGL) production increased 16 percent, while natural gas volumes grew 10 percent, contributing to total company production growth of 16 percent.
Cash operating costs declined by seven percent during the second quarter 2019 on a per-unit basis compared to the same prior year period. Lower transportation and lease and well costs contributed to the overall cost reduction. EOG's marketing operations added to the strong second quarter financial performance, as the average price of U.S. crude oil sales was $1.18 per barrel higher than the average NYMEX WTI price. Weaker NGL and natural gas markets reduced price realizations for these products compared to the same prior year period.
EOG generated $2.1 billion of discretionary cash flow in the second quarter 2019 and incurred total expenditures of $1.7 billion, including $1.6 billion of cash capital expenditures before acquisitions. After considering dividend payments of $127 million, the company generated free cash flow of $352 million during the second quarter. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"Our goal remains to be one of the best companies in any industry in the S&P 500. EOG is positioned to generate significant shareholder value even in lower oil price environments. Today, EOG can generate double-digit returns, double-digit organic growth, free cash flow and grow the dividend to a market competitive yield. And we are poised to further improve our financial performance going forward," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is committed to disciplined, environmentally responsible operational execution. Every facet of the company is generating improved performance each quarter, from drilling and completions to production and marketing. To put it simply, EOG's business is stronger than ever."
Financial Review
EOG further strengthened its financial position during the second quarter 2019. The company repaid a $900 million bond that reached maturity in June 2019 with cash on hand. At June 30, 2019, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 20 percent. Considering cash on the balance sheet at the end of the second quarter, EOG's net debt was $4.0 billion for a net debt-to-total capitalization ratio of 16 percent. This is down significantly from 24 percent at the end of the same prior year period. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Second Quarter 2019 Results Webcast
Friday, August 2, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Operating Revenues and Other | $ | 4,697.6 | $ | 4,238.1 | $ | 8,756.3 | $ | 7,919.2 | |||
Net Income | $ | 847.8 | $ | 696.7 | $ | 1,483.3 | $ | 1,335.3 | |||
Net Income Per Share | |||||||||||
Basic | $ | 1.47 | $ | 1.21 | $ | 2.57 | $ | 2.32 | |||
Diluted | $ | 1.46 | $ | 1.20 | $ | 2.56 | $ | 2.30 | |||
Average Number of Common Shares | |||||||||||
Basic | 577.5 | 576.1 | 577.3 | 576.0 | |||||||
Diluted | 580.2 | 580.4 | 580.2 | 580.0 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | $ | 2,528,866 | $ | 2,377,528 | $ | 4,729,269 | $ | 4,478,836 | |||
Natural Gas Liquids | 186,374 | 286,354 | 405,012 | 507,769 | |||||||
Natural Gas | 269,892 | 300,845 | 604,864 | 600,611 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 177,300 | (185,883) | 156,720 | (245,654) | |||||||
Gathering, Processing and Marketing | 1,501,386 | 1,436,436 | 2,787,040 | 2,538,258 | |||||||
Gains (Losses) on Asset Dispositions, Net | 8,009 | (6,317) | 4,173 | (21,286) | |||||||
Other, Net | 25,803 | 29,114 | 69,194 | 60,705 | |||||||
Total | 4,697,630 | 4,238,077 | 8,756,272 | 7,919,239 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 347,281 | 314,604 | 683,572 | 614,668 | |||||||
Transportation Costs | 174,101 | 177,797 | 350,623 | 354,754 | |||||||
Gathering and Processing Costs | 112,643 | 109,169 | 223,938 | 210,514 | |||||||
Exploration Costs | 32,522 | 47,478 | 68,846 | 82,314 | |||||||
Dry Hole Costs | 3,769 | 4,902 | 3,863 | 4,902 | |||||||
Impairments | 112,130 | 51,708 | 184,486 | 116,317 | |||||||
Marketing Costs | 1,500,915 | 1,420,463 | 2,770,972 | 2,526,853 | |||||||
Depreciation, Depletion and Amortization | 957,304 | 848,674 | 1,836,899 | 1,597,265 | |||||||
General and Administrative | 121,780 | 104,083 | 228,452 | 198,781 | |||||||
Taxes Other Than Income | 204,414 | 194,268 | 397,320 | 373,352 | |||||||
Total | 3,566,859 | 3,273,146 | 6,748,971 | 6,079,720 | |||||||
Operating Income | 1,130,771 | 964,931 | 2,007,301 | 1,839,519 | |||||||
Other Income (Expense), Net | 8,503 | (8,551) | 14,115 | (7,824) | |||||||
Income Before Interest Expense and Income Taxes | 1,139,274 | 956,380 | 2,021,416 | 1,831,695 | |||||||
Interest Expense, Net | 49,908 | 63,444 | 104,814 | 125,400 | |||||||
Income Before Income Taxes | 1,089,366 | 892,936 | 1,916,602 | 1,706,295 | |||||||
Income Tax Provision | 241,525 | 196,205 | 433,335 | 370,975 | |||||||
Net Income | $ | 847,841 | $ | 696,731 | $ | 1,483,267 | $ | 1,335,320 | |||
Dividends Declared per Common Share | $ | 0.2875 | $ | 0.1850 | $ | 0.5075 | $ | 0.3700 |
EOG RESOURCES, INC. | |||||||||||||||
Operating Highlights | |||||||||||||||
(Unaudited) | |||||||||||||||
Three Months Ended | Six Months Ended | ||||||||||||||
June 30, | June 30, | ||||||||||||||
2019 | 2018 | % Change | 2019 | 2018 | % Change | ||||||||||
Wellhead Volumes and Prices | |||||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||||||
United States | 454.9 | 379.2 | 20% | 445.1 | 369.5 | 20% | |||||||||
Trinidad | 0.6 | 0.8 | -25% | 0.7 | 0.9 | -22% | |||||||||
Other International (B) | 0.2 | 4.6 | -96% | - | 3.6 | -100% | |||||||||
Total | 455.7 | 384.6 | 18% | 445.8 | 374.0 | 19% | |||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 61.01 | $ | 67.91 | -10% | $ | 58.63 | $ | 66.13 | -11% | |||||
Trinidad | 49.56 | 60.57 | -18% | 46.62 | 57.59 | -19% | |||||||||
Other International (B) | 55.07 | 70.88 | -22% | 57.78 | 71.14 | -19% | |||||||||
Composite | 60.99 | 67.93 | -10% | 58.61 | 66.16 | -11% | |||||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||||||
United States | 131.1 | 112.9 | 16% | 125.4 | 106.8 | 17% | |||||||||
Other International (B) | - | - | - | - | |||||||||||
Total | 131.1 | 112.9 | 16% | 125.4 | 106.8 | 17% | |||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||||||
United States | $ | 15.63 | $ | 27.86 | -44% | $ | 17.84 | $ | 26.27 | -32% | |||||
Other International (B) | - | - | - | - | |||||||||||
Composite | 15.63 | 27.86 | -44% | 17.84 | 26.27 | -32% | |||||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||||||
United States | 1,047 | 914 | 15% | 1,025 | 884 | 16% | |||||||||
Trinidad | 273 | 282 | -3% | 270 | 288 | -6% | |||||||||
Other International (B) | 36 | 32 | 13% | 37 | 30 | 23% | |||||||||
Total | 1,356 | 1,228 | 10% | 1,332 | 1,202 | 11% | |||||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||||||
United States | $ | 1.98 | $ | 2.56 | -22% | $ | 2.37 | $ | 2.65 | -11% | |||||
Trinidad | 2.69 | 2.98 | -10% | 2.80 | 2.93 | -4% | |||||||||
Other International (B) | 4.25 | 4.10 | 4% | 4.31 | 4.22 | 2% | |||||||||
Composite | 2.19 | 2.69 | -19% | 2.51 | 2.76 | -9% | |||||||||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||||||||||||
United States | 760.4 | 644.4 | 18% | 741.3 | 623.6 | 19% | |||||||||
Trinidad | 46.1 | 47.8 | -4% | 45.6 | 48.8 | -7% | |||||||||
Other International (B) | 6.3 | 10.0 | -37% | 6.4 | 8.8 | -27% | |||||||||
Total | 812.8 | 702.2 | 16% | 793.3 | 681.2 | 16% | |||||||||
Total MMBoe (D) | 74.0 | 63.9 | 16% | 143.6 | 123.3 | 16% | |||||||||
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. | |||||||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2019). | |||||||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
June 30, | December 31, | ||||
2019 | 2018 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 1,160,485 | $ | 1,555,634 | |
Accounts Receivable, Net | 2,001,953 | 1,915,215 | |||
Inventories | 853,128 | 859,359 | |||
Assets from Price Risk Management Activities | 134,951 | 23,806 | |||
Income Taxes Receivable | 121,364 | 427,909 | |||
Other | 223,640 | 275,467 | |||
Total | 4,495,521 | 5,057,390 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 60,214,151 | 57,330,016 | |||
Other Property, Plant and Equipment | 4,328,675 | 4,220,665 | |||
Total Property, Plant and Equipment | 64,542,826 | 61,550,681 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (34,818,395) | (33,475,162) | |||
Total Property, Plant and Equipment, Net | 29,724,431 | 28,075,519 | |||
Deferred Income Taxes | 1,489 | 777 | |||
Other Assets | 1,530,060 | 800,788 | |||
Total Assets | $ | 35,751,501 | $ | 33,934,474 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 2,387,403 | $ | 2,239,850 | |
Accrued Taxes Payable | 268,837 | 214,726 | |||
Dividends Payable | 165,999 | 126,971 | |||
Current Portion of Long-Term Debt | 1,013,876 | 913,093 | |||
Current Portion of Operating Lease Liabilities | 396,547 | - | |||
Other | 181,395 | 233,724 | |||
Total | 4,414,057 | 3,728,364 | |||
Long-Term Debt | 4,165,284 | 5,170,169 | |||
Other Liabilities | 1,803,475 | 1,258,355 | |||
Deferred Income Taxes | 4,738,409 | 4,413,398 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 580,931,822 Shares Issued at June 30, 2019 and 580,408,117 Shares Issued at December 31, 2018 | 205,809 | 205,804 | |||
Additional Paid in Capital | 5,729,318 | 5,658,794 | |||
Accumulated Other Comprehensive Loss | (4,528) | (1,358) | |||
Retained Earnings | 14,731,609 | 13,543,130 | |||
Common Stock Held in Treasury, 305,941 Shares at June 30, 2019 and 385,042 Shares at December 31, 2018 | (31,932) | (42,182) | |||
Total Stockholders' Equity | 20,630,276 | 19,364,188 | |||
Total Liabilities and Stockholders' Equity | $ | 35,751,501 | $ | 33,934,474 | |
EOG RESOURCES, INC. | |||||||||||
Summary Statements of Cash Flows | |||||||||||
(Unaudited; in thousands) | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Cash Flows from Operating Activities | |||||||||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||||||||
Net Income | $ | 847,841 | $ | 696,731 | $ | 1,483,267 | $ | 1,335,320 | |||
Items Not Requiring (Providing) Cash | |||||||||||
Depreciation, Depletion and Amortization | 957,304 | 848,674 | 1,836,899 | 1,597,265 | |||||||
Impairments | 112,130 | 51,708 | 184,486 | 116,317 | |||||||
Stock-Based Compensation Expenses | 38,566 | 31,803 | 77,653 | 67,289 | |||||||
Deferred Income Taxes | 217,970 | 176,224 | 324,294 | 347,586 | |||||||
(Gains) Losses on Asset Dispositions, Net | (8,009) | 6,317 | (4,173) | 21,286 | |||||||
Other, Net | 2,487 | 11,494 | 5,439 | 13,507 | |||||||
Dry Hole Costs | 3,769 | 4,902 | 3,863 | 4,902 | |||||||
Mark-to-Market Commodity Derivative Contracts | |||||||||||
Total (Gains) Losses | (177,300) | 185,883 | (156,720) | 245,654 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 10,444 | (66,369) | 31,290 | (88,334) | |||||||
Other, Net | 663 | 217 | 1,639 | (261) | |||||||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||||||||
Accounts Receivable | 239,250 | (200,097) | (69,746) | (309,751) | |||||||
Inventories | 7,720 | (85,420) | (11,259) | (192,219) | |||||||
Accounts Payable | (67,229) | 402,325 | 126,853 | 455,977 | |||||||
Accrued Taxes Payable | (61,718) | 585 | 53,280 | 22,535 | |||||||
Other Assets | 494,322 | (53,980) | 487,387 | (62,843) | |||||||
Other Liabilities | (4,014) | (24,113) | (58,106) | (53,168) | |||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities | 72,347 | (45,267) | (22,034) | (27,279) | |||||||
Net Cash Provided by Operating Activities | 2,686,543 | 1,941,617 | 4,294,312 | 3,493,783 | |||||||
Investing Cash Flows | |||||||||||
Additions to Oil and Gas Properties | (1,507,024) | (1,615,175) | (3,446,497) | (2,980,286) | |||||||
Additions to Other Property, Plant and Equipment | (55,918) | (68,758) | (116,881) | (144,858) | |||||||
Proceeds from Sales of Assets | 2,593 | 5,447 | 17,642 | 8,276 | |||||||
Changes in Components of Working Capital Associated with Investing Activities | (72,325) | 45,295 | 22,056 | 27,250 | |||||||
Net Cash Used in Investing Activities | (1,632,674) | (1,633,191) | (3,523,680) | (3,089,618) | |||||||
Financing Cash Flows | |||||||||||
Long-Term Debt Repayments | (900,000) | - | (900,000) | - | |||||||
Dividends Paid | (127,135) | (106,584) | (254,681) | (203,610) | |||||||
Treasury Stock Purchased | (2,155) | (15,247) | (8,403) | (32,023) | |||||||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 8,292 | 9,692 | 8,695 | 11,145 | |||||||
Debt Issuance Costs | (4,902) | - | (4,902) | - | |||||||
Repayment of Capital Lease Obligation | (3,213) | (1,683) | (6,403) | (3,354) | |||||||
Changes in Components of Working Capital Associated with Financing Activities | (22) | (28) | (22) | 29 | |||||||
Net Cash Used in Financing Activities | (1,029,135) | (113,850) | (1,165,716) | (227,813) | |||||||
Effect of Exchange Rate Changes on Cash | (59) | (2,455) | (65) | (2,365) | |||||||
Increase (Decrease) in Cash and Cash Equivalents | 24,675 | 192,121 | (395,149) | 173,987 | |||||||
Cash and Cash Equivalents at Beginning of Period | 1,135,810 | 816,094 | 1,555,634 | 834,228 | |||||||
Cash and Cash Equivalents at End of Period | $ | 1,160,485 | $ | 1,008,215 | $ | 1,160,485 | $ | 1,008,215 |
EOG RESOURCES, INC. | ||||||||||||||
Second Quarter 2019 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells On Line | Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross | Net | Lateral Length (ft) | Crude Oil and Condensate (Bbld) (A) | Natural Gas Liquids (Bbld) (A) | Natural Gas (MMcfd) (A) | Crude Oil Equivalent(Boed) (B) | ||||||||
Delaware Basin | ||||||||||||||
Wolfcamp | 63 | 57 | 6,500 | 1,950 | 450 | 2.9 | 2,900 | |||||||
Bone Spring | 5 | 5 | 5,200 | 1,300 | 300 | 1.6 | 1,850 | |||||||
Leonard | 3 | 3 | 4,700 | 1,200 | 600 | 3.1 | 2,300 | |||||||
South Texas Eagle Ford | 86 | 78 | 7,300 | 1,100 | 150 | 0.6 | 1,350 | |||||||
South Texas Austin Chalk | 6 | 4 | 4,300 | 1,450 | 250 | 1.0 | 1,850 | |||||||
Powder River Basin | ||||||||||||||
Turner | 6 | 5 | 8,400 | 700 | 150 | 2.7 | 1,300 | |||||||
Mowry | 2 | 1 | 9,500 | 700 | 250 | 6.0 | 1,950 | |||||||
Niobrara | 5 | 3 | 9,800 | 1,000 | 100 | 2.1 | 1,450 | |||||||
DJ Basin Codell | 18 | 12 | 11,400 | 800 | 50 | 0.3 | 900 | |||||||
Anadarko Basin Woodford Oil Window | 11 | 9 | 9,500 | 650 | 50 | 0.5 | 800 |
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Reconciliation of Adjusted Net Income | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG's assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||
June 30, 2019 | June 30, 2018 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $ 1,089,366 | $ (241,525) | $ 847,841 | $ 1.46 | $ 892,936 | $ (196,205) | $ 696,731 | $ 1.20 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | (177,300) | 38,930 | (138,370) | (0.24) | 185,883 | (40,944) | 144,939 | 0.25 | |||||||
Net Cash Received from (Payments for Settlements of Commodity Derivative Contracts) | 10,444 | (2,276) | 8,168 | 0.01 | (66,369) | 14,619 | (51,750) | (0.09) | |||||||
Add: (Gains) Losses on Asset Dispositions | (8,009) | 1,734 | (6,275) | (0.01) | 6,317 | (1,375) | 4,942 | 0.01 | |||||||
Add: Impairments | 65,289 | (14,311) | 50,978 | 0.09 | - | - | - | - | |||||||
Adjustments to Net Income | (109,576) | 24,077 | (85,499) | (0.15) | 125,831 | (27,700) | 98,131 | 0.17 | |||||||
Adjusted Net Income (Non-GAAP) | $ 979,790 | $ (217,448) | $ 762,342 | $ 1.31 | $ 1,018,767 | $ (223,905) | $ 794,862 | $ 1.37 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,460 | 576,135 | |||||||||||||
Diluted | 580,247 | 580,375 | |||||||||||||
Six Months Ended | Six Months Ended | ||||||||||||||
June 30, 2019 | June 30, 2018 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $ 1,916,602 | $ (433,335) | $ 1,483,267 | $ 2.56 | $ 1,706,295 | $ (370,975) | $ 1,335,320 | $ 2.30 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts | (156,720) | 34,397 | (122,323) | (0.21) | 245,654 | (54,110) | 191,544 | 0.33 | |||||||
Net Cash Received from (Payments for Settlements of Commodity Derivative Contracts) | 31,290 | (6,868) | 24,422 | 0.04 | (88,334) | 19,457 | (68,877) | (0.12) | |||||||
Add: (Gains) Losses on Asset Dispositions | (4,173) | 998 | (3,175) | (0.01) | 21,286 | (4,699) | 16,587 | 0.03 | |||||||
Add: Impairments | 89,034 | (19,541) | 69,493 | 0.12 | 20,876 | (4,598) | 16,278 | 0.03 | |||||||
Less: Tax Reform Impact | - | - | - | - | - | (6,524) | (6,524) | (0.01) | |||||||
Adjustments to Net Income | (40,569) | 8,986 | (31,583) | (0.06) | 199,482 | (50,474) | 149,008 | 0.26 | |||||||
Adjusted Net Income (Non-GAAP) | $ 1,876,033 | $ (424,349) | $ 1,451,684 | $ 2.50 | $ 1,905,777 | $ (421,449) | $ 1,484,328 | $ 2.56 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,333 | 575,953 | |||||||||||||
Diluted | 580,204 | 580,007 |
EOG RESOURCES, INC. | |||||||||||
Reconciliation of Discretionary Cash Flow | |||||||||||
(Unaudited; in thousands) | |||||||||||
Calculation of Free Cash Flow | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart reconciles the three-month and six-month periods ended June 30, 2019 and 2018 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures (excluding acquisitions) incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and six months ended June 30, 2019 and 2018. EOG management uses this information for comparative purposes within the industry. | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 2,686,543 | $ | 1,941,617 | $ | 4,294,312 | $ | 3,493,783 | |||
Adjustments: | |||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 26,089 | 41,748 | 55,876 | 69,684 | |||||||
Other Non-Current Income Taxes - Net Receivable | 42,764 | 73,441 | 145,682 | 192,362 | |||||||
Changes in Components of Working Capital and Other Assets | |||||||||||
and Liabilities | |||||||||||
Accounts Receivable | (239,250) | 200,097 | 69,746 | 309,751 | |||||||
Inventories | (7,720) | 85,420 | 11,259 | 192,219 | |||||||
Accounts Payable | 67,229 | (402,325) | (126,853) | (455,977) | |||||||
Accrued Taxes Payable | 61,718 | (585) | (53,280) | (22,535) | |||||||
Other Assets | (494,322) | 53,980 | (487,387) | 62,843 | |||||||
Other Liabilities | 4,014 | 24,113 | 58,106 | 53,168 | |||||||
Changes in Components of Working Capital Associated with | |||||||||||
Investing and Financing Activities | (72,347) | 45,267 | 22,034 | 27,279 | |||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,074,718 | $ | 2,062,773 | $ | 3,989,495 | $ | 3,922,577 | |||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 1% | 2% | |||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,074,718 | $ | 2,062,773 | $ | 3,989,495 | $ | 3,922,577 | |||
Less: | |||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) | (1,595,726) | (1,720,198) | (3,328,202) | (3,198,028) | |||||||
Dividends Paid (GAAP) | (127,135) | (106,584) | (254,681) | (203,610) | |||||||
Free Cash Flow (Non-GAAP) | $ | 351,857 | $ | 235,991 | $ | 406,612 | $ | 520,939 | |||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three-month and six-month periods ended June 30, 2019 and 2018: | |||||||||||
Total Expenditures (GAAP) | $ | 1,663,127 | $ | 1,826,932 | $ | 3,765,046 | $ | 3,373,573 | |||
Less: | |||||||||||
Asset Retirement Costs | (55,425) | (18,856) | (60,581) | (30,956) | |||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (586) | (45) | (586) | (47,680) | |||||||
Non-Cash Acquisition Costs of Unproved Properties | (10,240) | (51,193) | (53,721) | (60,002) | |||||||
Acquisition Costs of Proved Properties | (1,150) | (36,640) | (321,956) | (36,907) | |||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,595,726 | $ | 1,720,198 | $ | 3,328,202 | $ | 3,198,028 |
EOG RESOURCES, INC. | |||||||||||
Reconciliation of Adjusted EBITDAX | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Net Income (GAAP) | $ | 847,841 | $ | 696,731 | $ | 1,483,267 | $ | 1,335,320 | |||
Adjustments: | |||||||||||
Interest Expense, Net | 49,908 | 63,444 | 104,814 | 125,400 | |||||||
Income Tax Provision | 241,525 | 196,205 | 433,335 | 370,975 | |||||||
Depreciation, Depletion and Amortization | 957,304 | 848,674 | 1,836,899 | 1,597,265 | |||||||
Exploration Costs | 32,522 | 47,478 | 68,846 | 82,314 | |||||||
Dry Hole Costs | 3,769 | 4,902 | 3,863 | 4,902 | |||||||
Impairments | 112,130 | 51,708 | 184,486 | 116,317 | |||||||
EBITDAX (Non-GAAP) | 2,244,999 | 1,909,142 | 4,115,510 | 3,632,493 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | (177,300) | 185,883 | (156,720) | 245,654 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 10,444 | (66,369) | 31,290 | (88,334) | |||||||
(Gains) Losses on Asset Dispositions, Net | (8,009) | 6,317 | (4,173) | 21,286 | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 2,070,134 | $ | 2,034,973 | $ | 3,985,907 | $ | 3,811,099 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 2% | 5% |
EOG RESOURCES, INC. | ||||||||
Reconciliation of Net Debt and Total Capitalization | ||||||||
Calculation of Net Debt-to-Total Capitalization Ratio | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||||||
At | At | At | ||||||
June 30, | December 31, | June 30, | ||||||
2019 | 2018 | 2018 | ||||||
Total Stockholders' Equity - (a) | $ | 20,630 | $ | 19,364 | $ | 17,452 | ||
Current and Long-Term Debt (GAAP) - (b) | 5,179 | 6,083 | 6,435 | |||||
Less: Cash | (1,160) | (1,556) | (1,008) | |||||
Net Debt (Non-GAAP) - (c) | 4,019 | 4,527 | 5,427 | |||||
Total Capitalization (GAAP) - (a) + (b) | $ | 25,809 | $ | 25,447 | $ | 23,887 | ||
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 24,649 | $ | 23,891 | $ | 22,879 | ||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 20% | 24% | 27% | |||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 16% | 19% | 24% |
EOG RESOURCES, INC. | ||||
Crude Oil and Natural Gas Financial Commodity | ||||
Derivative Contracts | ||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through July 29, 2019. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||
Midland Differential Basis Swap Contracts | ||||
Weighted | ||||
Average Price | ||||
Volume | Differential | |||
(Bbld) | ($/Bbl) | |||
2019 | ||||
January 1, 2019 through August 31, 2019 (closed) | 20,000 | $ 1.075 | ||
September 1, 2019 through December 31, 2019 | 20,000 | 1.075 | ||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through July 29, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||
Gulf Coast Differential Basis Swap Contracts | ||||
Weighted | ||||
Average Price | ||||
Volume | Differential | |||
(Bbld) | ($/Bbl) | |||
2019 | ||||
January 1, 2019 through August 31, 2019 (closed) | 13,000 | $ 5.572 | ||
September 1, 2019 through December 31, 2019 | 13,000 | 5.572 | ||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through July 29, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||
Crude Oil Price Swap Contracts | ||||
Weighted | ||||
Volume | Average Price | |||
(Bbld) | ($/Bbl) | |||
2019 | ||||
April 2019 (closed) | 25,000 | $ 60.00 | ||
May 1, 2019 through June 30, 2019 (closed) | 150,000 | 62.50 | ||
July 1, 2019 through December 31, 2019 | 150,000 | 62.50 | ||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through July 29, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||
Natural Gas Price Swap Contracts | ||||
Weighted | ||||
Volume | Average Price | |||
(MMBtud) | ($/MMBtu) | |||
2019 | ||||
April 1, 2019 through August 31, 2019 (closed) | 250,000 | $ 2.90 | ||
September 1, 2019 through October 31, 2019 | 250,000 | 2.90 | ||
Definitions | ||||
Bbld | Barrels per day | |||
$/Bbl | Dollars per barrel | |||
MMBtud | Million British thermal units per day | |||
$/MMBtu | Dollars per million British thermal units | |||
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Reconciliation of After-Tax Net Interest Expense, Adjusted Net Income, | ||||||||
Net Debt and Total Capitalization | ||||||||
Calculations of Return on Capital Employed and Return on Equity | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2018 | 2017 | |||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||
Net Interest Expense (GAAP) | $ | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (51) | |||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 194 | ||||||
Net Income (GAAP) - (b) | $ | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) | (201) | (1) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 3,218 | ||||||
Total Stockholders' Equity - (d) | $ | 19,364 | $ | 16,283 | ||||
Average Total Stockholders' Equity * - (e) | $ | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | $ | 6,083 | $ | 6,387 | ||||
Less: Cash | (1,556) | (834) | ||||||
Net Debt (Non-GAAP) - (g) | $ | 4,527 | $ | 5,553 | ||||
Total Capitalization (GAAP) - (d) + (f) | $ | 25,447 | $ | 22,670 | ||||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 23,891 | $ | 21,836 | ||||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 22,864 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.8% | |||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 14.9% | |||||||
Return on Equity (ROE) | ||||||||
ROE (GAAP Net Income) - (b) / (e) | 19.2% | |||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 18.1% | |||||||
* Average for the current and immediately preceding year | ||||||||
Adjustments to Net Income (GAAP) | ||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: | ||||||||
Year Ended December 31, 2018 | ||||||||
Before | Income Tax | After | ||||||
Tax | Impact | Tax | ||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (93) | $ | 20 | $ | (73) | ||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | - | (110) | (110) | |||||
Total | $ | (115) | $ | (86) | $ | (201) |
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | $ | 235 |
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | $ | 153 |
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | $ | 2,197 |
Total Stockholders' Equity - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 |
Average Total Stockholders' Equity * - (e) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | $ | 14,352 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 |
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 |
Total Capitalization (GAAP) - (d) + (f) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 21,836 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,602 | $ | 19,124 | $ | 20,206 | $ | 20,771 | $ | 19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 13.4% | -4.8% | -21.6% | 14.7% | 12.1% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.1% | -8.1% | -29.5% | 17.6% | 15.3% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 |
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 |
Net Income (Loss) (GAAP) - (b) | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 |
Total Stockholders' Equity - (d) | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 |
Average Total Stockholders' Equity * - (e) | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 |
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 |
Total Capitalization (GAAP) - (d) + (f) | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 4.4% | 9.5% | 1.6% | 5.8% | 30.5% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 |
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 |
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 |
Total Stockholders' Equity - (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 |
Average Total Stockholders' Equity * - (e) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 |
Current and Long-Term Debt (GAAP) - (f) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 |
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 |
Total Capitalization (GAAP) - (d) + (f) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Reconciliation of After-Tax Net Interest Expense, | ||||||||||
Net Debt and Total Capitalization | ||||||||||
Calculation of Return on Capital Employed | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 60 | $ | 45 | $ | 61 | $ | 62 | ||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 39 | $ | 29 | $ | 40 | $ | 40 | ||
Net Income (Loss) (GAAP) - (b) | $ | 87 | $ | 399 | $ | 397 | $ | 569 | ||
Total Stockholders' Equity - (d) | $ | 1,672 | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 |
Average Total Stockholders' Equity * - (e) | $ | 1,658 | $ | 1,512 | $ | 1,256 | $ | 1,205 | ||
Current and Long-Term Debt (GAAP) - (f) | $ | 1,145 | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 |
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,135 | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 |
Total Capitalization (GAAP) - (d) + (f) | $ | 2,817 | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 2,807 | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 2,652 | $ | 2,358 | $ | 2,158 | $ | 2,256 | ||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.8% | 18.2% | 20.2% | 27.0% | ||||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 5.2% | 26.4% | 31.6% | 47.2% | ||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Three Months Ended | Six Months Ended | ||||||||||
June 30, | June 30, | ||||||||||
2019 | 2018 | 2019 | 2018 | ||||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 347,281 | $ 314,604 | $ 683,572 | $ 614,668 | |||||||
Transportation Costs | 174,101 | 177,797 | 350,623 | 354,754 | |||||||
General and Administrative | 121,780 | 104,083 | 228,452 | 198,781 | |||||||
Cash Operating Expenses | 643,162 | 596,484 | 1,262,647 | 1,168,203 | |||||||
Less: Non-GAAP Adjustments | - | - | - | - | |||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 643,162 | $ 596,484 | $ 1,262,647 | $ 1,168,203 | |||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 73,964 | 63,898 | 143,587 | 123,291 | |||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 8.70 | (c) | $ 9.33 | (d) | $ 8.79 | (e) | $ 9.48 | (f) | |||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - Percentage Decrease | |||||||||||
Three Months Ended June 30, 2019 compared to Three Months Ended June 30, 2018 - [(c) - (d)] / (d) | -7% | ||||||||||
Six Months Ended June 30, 2019 compared to Six Months Ended June 30, 2018 - [(e) - (f)] / (f) | -7% | ||||||||||
* Includes stock compensation expense and other non-cash items. | |||||||||||
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 2,456,523 | 2,219,666 | 2,086,373 | 2,398,195 | 2,790,599 | ||||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||||
Less: Acquisition Costs - Yates Transaction | - | - | (5,100) | - | - | ||||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 2,456,523 | $ 2,201,880 | $ 2,039,219 | $ 2,378,840 | $ 2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.36 | (c) | $ 9.91 | (d) | $ 9.95 | (e) | $ 11.39 | (f) | $ 12.86 | (g) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - Percentage Decrease | |||||||||||
2018 compared to 2017 - [(c) - (d)] / (d) | -6% | ||||||||||
2018 compared to 2016 - [(c) - (e)] / (e) | -6% | ||||||||||
2018 compared to 2015 - [(c) - (f)] / (f) | -18% | ||||||||||
2018 compared to 2014 - [(c) - (g)] / (g) | -27% | ||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | ||||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||||
Three Months Ended | Year-To-Date | |||||||||
March 31, | June 30, | June 30, | ||||||||
2019 | 2019 | 2019 | ||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 69,623 | 73,964 | 143,587 | |||||||
Crude Oil and Condensate | $ 2,200,403 | $ 2,528,866 | $ 4,729,269 | |||||||
Natural Gas Liquids | 218,638 | 186,374 | 405,012 | |||||||
Natural Gas | 334,972 | 269,892 | 604,864 | |||||||
Total Wellhead Revenues - (b) | $ 2,754,013 | $ 2,985,132 | $ 5,739,145 | |||||||
Operating Costs | ||||||||||
Lease and Well | $ 336,291 | $ 347,281 | $ 683,572 | |||||||
Transportation Costs | 176,522 | 174,101 | 350,623 | |||||||
Gathering and Processing Costs | 111,295 | 112,643 | 223,938 | |||||||
General and Administrative | 106,672 | 121,780 | 228,452 | |||||||
Taxes Other Than Income | 192,906 | 204,414 | 397,320 | |||||||
Interest Expense, Net | 54,906 | 49,908 | 104,814 | |||||||
Total Cash Operating Cost (excluding DD&A and Total Exploration Costs) - (c) | $ 978,592 | $ 1,010,127 | $ 1,988,719 | |||||||
Depreciation, Depletion and Amortization (DD&A) | 879,595 | 957,304 | 1,836,899 | |||||||
Total Operating Cost (excluding Total Exploration Costs) - (d) | $ 1,858,187 | $ 1,967,431 | $ 3,825,618 | |||||||
Exploration Costs | $ 36,324 | $ 32,522 | $ 68,846 | |||||||
Dry Hole Costs | 94 | 3,769 | 3,863 | |||||||
Impairments | 72,356 | 112,130 | 184,486 | |||||||
Total Exploration Costs | 108,774 | 148,421 | 257,195 | |||||||
Less: Impairments (Non-GAAP) | (23,745) | (65,289) | (89,034) | |||||||
Total Exploration Costs (Non-GAAP) | $ 85,029 | $ 83,132 | $ 168,161 | |||||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | $ 1,943,216 | $ 2,050,563 | $ 3,993,779 | |||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 39.56 | $ 40.36 | $ 39.97 | |||||||
Total Cash Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (c) / (a) | $ 14.06 | $ 13.65 | $ 13.85 | |||||||
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | $ 25.50 | $ 26.71 | $ 26.12 | |||||||
Total Operating Cost per Boe (excluding Total Exploration Costs) - (d) / (a) | $ 26.69 | $ 26.59 | $ 26.64 | |||||||
Composite Average Margin per Boe (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | $ 12.87 | $ 13.77 | $ 13.33 | |||||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | $ 27.91 | $ 27.72 | $ 27.81 | |||||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | $ 11.65 | $ 12.64 | $ 12.16 | |||||||
EOG RESOURCES, INC. | ||||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||||
Year Ended | ||||||||||
December 31, | ||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | |||||
Crude Oil and Condensate | $ 9,517,440 | $ 6,256,396 | $ 4,317,341 | $ 4,934,562 | $ 9,742,480 | |||||
Natural Gas Liquids | 1,127,510 | 729,561 | 437,250 | 407,658 | 934,051 | |||||
Natural Gas | 1,301,537 | 921,934 | 742,152 | 1,061,038 | 1,916,386 | |||||
Total Wellhead Revenues - (b) | $ 11,946,487 | $ 7,907,891 | $ 5,496,743 | $ 6,403,258 | $ 12,592,917 | |||||
Operating Costs | ||||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | |||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | |||||
Gathering and Processing Costs | 436,973 | 148,775 | 122,901 | 146,156 | 145,800 | |||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | |||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | |||||
Less: Acquisition Costs | - | - | (5,100) | - | - | |||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | |||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | |||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | |||||
General and Administrative (Non-GAAP) | 426,969 | 416,681 | 347,661 | 347,239 | 402,010 | |||||
Taxes Other Than Income | 772,481 | 544,662 | 349,710 | 421,744 | 757,564 | |||||
Interest Expense, Net | 245,052 | 274,372 | 281,681 | 237,393 | 201,458 | |||||
Total Cash Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) | $ 3,911,029 | $ 3,169,689 | $ 2,793,511 | $ 3,184,133 | $ 3,895,421 | |||||
Depreciation, Depletion and Amortization (DD&A) | 3,435,408 | 3,409,387 | 3,553,417 | 3,313,644 | 3,997,041 | |||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (d) | $ 7,346,437 | $ 6,579,076 | $ 6,346,928 | $ 6,497,777 | $ 7,892,462 | |||||
Exploration Costs | $ 148,999 | $ 145,342 | $ 124,953 | $ 149,494 | $ 184,388 | |||||
Dry Hole Costs | 5,405 | 4,609 | 10,657 | 14,746 | 48,490 | |||||
Impairments | 347,021 | 479,240 | 620,267 | 6,613,546 | 743,575 | |||||
Total Exploration Costs | 501,425 | 629,191 | 755,877 | 6,777,786 | 976,453 | |||||
Less: Impairments (Non-GAAP) | (152,671) | (261,452) | (320,617) | (6,307,593) | (824,312) | |||||
Total Exploration Costs (Non-GAAP) | $ 348,754 | $ 367,739 | $ 435,260 | $ 470,193 | $ 152,141 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration Costs) - (e) | $ 7,695,191 | $ 6,946,815 | $ 6,782,188 | $ 6,967,970 | $ 8,044,603 | |||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 45.51 | $ 35.58 | $ 26.82 | $ 30.66 | $ 58.01 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (c) / (a) | $ 14.90 | $ 14.25 | $ 13.64 | $ 15.25 | $ 17.95 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding DD&A and Total Exploration Costs) - [(b) / (a) - (c) / (a)] | $ 30.61 | $ 21.33 | $ 13.18 | $ 15.41 | $ 40.06 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding Total Exploration Costs) - (d) / (a) | $ 27.99 | $ 29.59 | $ 30.98 | $ 31.11 | $ 36.38 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding Total Exploration Costs) - [(b) / (a) - (d) / (a)] | $ 17.52 | $ 5.99 | $ (4.16) | $ (0.45) | $ 21.63 | |||||
Total Operating Cost per Boe (Non-GAAP) (including Total Exploration Costs) - (e) / (a) | $ 29.32 | $ 31.24 | $ 33.10 | $ 33.36 | $ 37.08 | |||||
Composite Average Margin per Boe (Non-GAAP) (including Total Exploration Costs) - [(b) / (a) - (e) / (a)] | $ 16.19 | $ 4.34 | $ (6.28) | $ (2.70) | $ 20.93 |
EOG RESOURCES, INC. | ||||||||||||||
Third Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing | ||||||||||||||
(a) Third Quarter and Full Year 2019 Forecast | ||||||||||||||
The forecast items for the third quarter and full year 2019 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | ||||||||||||||
(b) Capital Expenditures | ||||||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. | ||||||||||||||
(c) Benchmark Commodity Pricing | ||||||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | ||||||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | ||||||||||||||
Estimated Ranges | ||||||||||||||
(Unaudited) | ||||||||||||||
3Q 2019 | Full Year 2019 | |||||||||||||
Daily Sales Volumes | ||||||||||||||
Crude Oil and Condensate Volumes (MBbld) | ||||||||||||||
United States | 453.0 | - | 463.0 | 450.0 | - | 455.0 | ||||||||
Trinidad | 0.5 | - | 0.7 | 0.5 | - | 0.7 | ||||||||
Other International | 0.0 | - | 0.2 | 0.0 | - | 0.2 | ||||||||
Total | 453.5 | - | 463.9 | 450.5 | - | 455.9 | ||||||||
Natural Gas Liquids Volumes (MBbld) | ||||||||||||||
Total | 128.0 | - | 138.0 | 125.0 | - | 135.0 | ||||||||
Natural Gas Volumes (MMcfd) | ||||||||||||||
United States | 1,010 | - | 1,070 | 1,020 | - | 1,070 | ||||||||
Trinidad | 235 | - | 265 | 260 | - | 280 | ||||||||
Other International | 30 | - | 40 | 30 | - | 40 | ||||||||
Total | 1,275 | - | 1,375 | 1,310 | - | 1,390 | ||||||||
Crude Oil Equivalent Volumes (MBoed) | ||||||||||||||
United States | 749.3 | - | 779.3 | 745.0 | - | 768.3 | ||||||||
Trinidad | 39.7 | - | 44.9 | 43.8 | - | 47.4 | ||||||||
Other International | 5.0 | - | 6.9 | 5.0 | - | 6.9 | ||||||||
Total | 794.0 | - | 831.1 | 793.8 | - | 822.6 | ||||||||
Capital Expenditures ($MM) | $ | 1,500 | - | $ | 1,700 | $ | 6,100 | - | $ | 6,500 | ||||
Estimated Ranges | ||||||||||||||
(Unaudited) | ||||||||||||||
3Q 2019 | Full Year 2019 | |||||||||||||
Operating Costs | ||||||||||||||
Unit Costs ($/Boe) | ||||||||||||||
Lease and Well | $ | 4.70 | - | $ | 5.00 | $ | 4.50 | - | $ | 5.10 | ||||
Transportation Costs | $ | 2.20 | - | $ | 2.70 | $ | 2.25 | - | $ | 2.75 | ||||
Depreciation, Depletion and Amortization | $ | 12.70 | - | $ | 13.10 | $ | 12.25 | - | $ | 13.25 | ||||
Expenses ($MM) | ||||||||||||||
Exploration and Dry Hole | $ | 45 | - | $ | 55 | $ | 140 | - | $ | 180 | ||||
Impairment | $ | 75 | - | $ | 85 | $ | 250 | - | $ | 300 | ||||
General and Administrative | $ | 120 | - | $ | 130 | $ | 450 | - | $ | 490 | ||||
Gathering and Processing | $ | 120 | - | $ | 130 | $ | 440 | - | $ | 480 | ||||
Capitalized Interest | $ | 9 | - | $ | 11 | $ | 30 | - | $ | 40 | ||||
Net Interest | $ | 39 | - | $ | 41 | $ | 180 | - | $ | 190 | ||||
Taxes Other Than Income (% of Wellhead Revenue) | 7.0% | - | 7.4% | 7.0% | - | 7.4% | ||||||||
Income Taxes | ||||||||||||||
Effective Rate | 21% | - | 26% | 21% | - | 26% | ||||||||
Current Tax (Benefit) / Expense ($MM) | $ | (35) | - | $ | 5 | $ | (85) | - | $ | (45) | ||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | ||||||||||||||
Crude Oil and Condensate ($/Bbl) | ||||||||||||||
Differentials | ||||||||||||||
United States - above (below) WTI | $ | 0.00 | - | $ | 0.60 | $ | (0.50) | - | $ | 1.50 | ||||
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (11.50) | - | $ | (9.50) | ||||
Other International - above (below) WTI | $ | 0.00 | - | $ | 4.00 | $ | (0.50) | - | $ | 1.50 | ||||
Natural Gas Liquids | ||||||||||||||
Realizations as % of WTI | 18% | - | 26% | 22% | - | 32% | ||||||||
Natural Gas ($/Mcf) | ||||||||||||||
Differentials | ||||||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.60) | - | $ | (0.20) | $ | (0.70) | - | $ | (0.20) | ||||
Realizations | ||||||||||||||
Trinidad | $ | 2.30 | - | $ | 2.70 | $ | 2.40 | - | $ | 3.10 | ||||
Other International | $ | 4.00 | - | $ | 4.40 | $ | 3.75 | - | $ | 4.75 | ||||
Definitions | ||||||||||||||
$/Bbl | U.S. Dollars per barrel | |||||||||||||
$/Boe | U.S. Dollars per barrel of oil equivalent | |||||||||||||
$/Mcf | U.S. Dollars per thousand cubic feet | |||||||||||||
$MM | U.S. Dollars in millions | |||||||||||||
MBbld | Thousand barrels per day | |||||||||||||
MBoed | Thousand barrels of oil equivalent per day | |||||||||||||
MMcfd | Million cubic feet per day | |||||||||||||
NYMEX | U.S. New York Mercantile Exchange | |||||||||||||
WTI | West Texas Intermediate | |||||||||||||
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-outstanding-second-quarter-2019-results-generates-significant-returns-growth-and-cash-flow-at-lower-oil-prices-300895359.html
SOURCE EOG Resources, Inc.
HOUSTON, June 18, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss second quarter 2019 results on Friday, August 2, 2019, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-second-quarter-2019-results-for-august-2-2019-300870791.html
SOURCE EOG Resources, Inc.
HOUSTON, June 5, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the J.P. Morgan Energy Conference at 7:00 a.m. Central time (8:00 a.m. Eastern time) on Tuesday, June 18. Kenneth W. Boedeker, Executive Vice President, Exploration and Production, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available for thirty days.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conference-300862832.html
SOURCE EOG Resources, Inc.
HOUSTON, May 8, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the UBS Global Oil and Gas Conference at 2:00 p.m. Central time on Wednesday, May 22. Ezra Y. Yacob, Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the Bernstein Strategic Decisions Conference at 9:00 a.m. Central time (10:00 a.m. Eastern time) on Wednesday, May 29. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcasts. If you are unable to listen live, a replay will be available for six months.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conferences-300846737.html
SOURCE EOG Resources, Inc.
HOUSTON, May 2, 2019 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported first quarter 2019 net income of $635 million, or $1.10 per share, compared with first quarter 2018 net income of $639 million, or $1.10 per share. Net cash from operating activities for the first quarter 2019 was $1.6 billion. Discretionary cash flow for the first quarter 2019 of $1.9 billion increased three percent compared to the first quarter 2018, despite a 13 percent drop in the average WTI NYMEX price compared to the same prior year period.
Adjusted non-GAAP net income for the first quarter 2019 was $689 million, or $1.19 per share, compared with adjusted non-GAAP net income of $689 million, or $1.19 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
First Quarter 2019 Review
EOG delivered stellar operational and financial performance in the first quarter 2019. Crude oil production volumes exceeded the target range, while capital expenditures were below the target range. Total company crude oil volumes grew 20 percent compared to the first quarter 2018, to 435,900 barrels of oil per day (Bopd). Natural gas liquids production increased 19 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 17 percent.
Cash operating costs declined by eight percent during the first quarter 2019 on a per-unit basis compared to the same prior year period. Lower transportation, lease operating and general and administrative costs contributed to the overall cost reduction. EOG's marketing operations added to the strong first quarter financial performance, as the average price on U.S. crude oil sales was $1.21 per barrel higher than the average WTI NYMEX price. The company also achieved reductions in well costs during the first quarter 2019.
EOG generated $1.9 billion of discretionary cash flow in the first quarter 2019. The company incurred total expenditures of $2.1 billion, including $1.7 billion of cash capital expenditures before acquisitions. After considering dividend payments of $128 million, EOG generated free cash flow during the first quarter of $55 million. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG's consistent long-term strategy of exploration-led organic growth, focus on operating and capital cost control and disciplined capital allocation is generating robust financial results. We are growing more efficiently than ever before," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We are on track to reduce well costs five percent for the year. Combined with strong price realizations, EOG is positioned to further improve margins and returns. The tremendous first quarter results demonstrate that EOG is achieving its goal of performing with the best companies in the S&P 500."
Dividend Increase
EOG's Board of Directors declared a quarterly dividend of $0.2875 per share on the common stock, an increase of 31 percent. The dividend will be payable July 31, 2019, to holders of record as of July 17, 2019. The indicated annual rate is $1.15 per share.
"EOG's commitment to increasing cash returns to stockholders continues, as we have now increased our dividend by 72 percent during the past 14 months. This is made possible through our relentless efforts to lower costs, increase returns and fundamentally reset the business to be profitable even in a low oil price environment. We are confident our results will continue to improve, guided by our unique culture and sustainable business model," Thomas said.
Crude Oil Export Capacity
EOG has reached agreements that provide access to crude oil export capacity on the Gulf Coast. Export capacity available to EOG will increase from 100,000 Bopd in 2020 to 250,000 Bopd in 2022 and subsequent years. The company expects to sell a portion of its crude oil from its Eagle Ford and Delaware Basin plays to export markets. The new agreements complement EOG's existing pipeline and terminal tankage capacity, further increasing the reliability and diversification of its marketing operations.
"These agreements extend control of our crude oil production to the water's edge and open significant new markets to EOG. We enhance our flexibility to capture the highest margins for our crude oil by maintaining firm capacity for our production downstream, providing access to a diverse group of potential customers in multiple end markets," commented D. Lance Terveen, Senior Vice President, Marketing.
Operating Highlights
EOG brought on line 78 wells in the Delaware Basin during the first quarter 2019 using one less rig and completion crew than it did in the first quarter 2018 to bring on line 70 wells. This tremendous operating performance, as well as infrastructure investments such as water handling and reuse, are enabling EOG to achieve further cost reductions.
The South Texas Eagle Ford remains a foundation asset for EOG, capable of sustaining high-return growth for at least 10 years. EOG is improving capital productivity across the entire 120-mile length of its acreage position in the heart of this world class resource play. The further adoption of local sources of sand supply, increased efficiencies in completion operations and the continued development of new completion designs are contributing to lower costs with consistent well productivity. With less than 40 percent of its identified locations in the play developed, there is significant opportunity to convert additional acreage to premium status.
In the Powder River Basin Turner, EOG brought five wells to sales during the first quarter. The company also further progressed plans for infrastructure development, including crude oil and natural gas gathering pipelines and water handling systems. EOG brought on line 25 wells in the Wyoming DJ Basin Codell during the first quarter. With low well costs and a high oil mix, EOG's Codell development program realizes low finding costs and premium rates of return.
EOG brought on line four wells in the Eastern Anadarko Basin Woodford Oil Window during the first quarter. The drilling program in the first quarter was focused on further delineating the play and testing additional targets.
In the Williston Basin, EOG drilled two wells during the first quarter and deferred completions until the summer as part of its seasonal development program.
Financial Review
At March 31, 2019, EOG's total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 23 percent. Considering cash on the balance sheet at the end of the first quarter, EOG's net debt was $4.9 billion for a net debt-to-total capitalization ratio of 20 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
First Quarter 2019 Results Webcast
Friday, May 3, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||
Financial Report | |||||
(Unaudited; in millions, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2019 | 2018 | ||||
Operating Revenues and Other | $ | 4,058.6 | $ | 3,681.2 | |
Net Income | $ | 635.4 | $ | 638.6 | |
Net Income Per Share | |||||
Basic | $ | 1.10 | $ | 1.11 | |
Diluted | $ | 1.10 | $ | 1.10 | |
Average Number of Common Shares | |||||
Basic | 577.2 | 575.8 | |||
Diluted | 580.2 | 579.7 | |||
Summary Income Statements | |||||
(Unaudited; in thousands, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2019 | 2018 | ||||
Operating Revenues and Other | |||||
Crude Oil and Condensate | $ | 2,200,403 | $ | 2,101,308 | |
Natural Gas Liquids | 218,638 | 221,415 | |||
Natural Gas | 334,972 | 299,766 | |||
Losses on Mark-to-Market Commodity | (20,580) | (59,771) | |||
Gathering, Processing and Marketing | 1,285,654 | 1,101,822 | |||
Losses on Asset Dispositions, Net | (3,836) | (14,969) | |||
Other, Net | 43,391 | 31,591 | |||
Total | 4,058,642 | 3,681,162 | |||
Operating Expenses | |||||
Lease and Well | 336,291 | 300,064 | |||
Transportation Costs | 176,522 | 176,957 | |||
Gathering and Processing Costs | 111,295 | 101,345 | |||
Exploration Costs | 36,324 | 34,836 | |||
Dry Hole Costs | 94 | - | |||
Impairments | 72,356 | 64,609 | |||
Marketing Costs | 1,270,057 | 1,106,390 | |||
Depreciation, Depletion and Amortization | 879,595 | 748,591 | |||
General and Administrative | 106,672 | 94,698 | |||
Taxes Other Than Income | 192,906 | 179,084 | |||
Total | 3,182,112 | 2,806,574 | |||
Operating Income | 876,530 | 874,588 | |||
Other Income, Net | 5,612 | 727 | |||
Income Before Interest Expense and Income Taxes | 882,142 | 875,315 | |||
Interest Expense, Net | 54,906 | 61,956 | |||
Income Before Income Taxes | 827,236 | 813,359 | |||
Income Tax Provision | 191,810 | 174,770 | |||
Net Income | $ | 635,426 | $ | 638,589 | |
Dividends Declared per Common Share | $ | 0.2200 | $ | 0.1850 | |
EOG RESOURCES, INC. | |||||
Operating Highlights | |||||
(Unaudited) | |||||
Three Months Ended | |||||
March 31, | |||||
2019 | 2018 | ||||
Wellhead Volumes and Prices | |||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||
United States | 435.1 | 359.7 | |||
Trinidad | 0.7 | 0.9 | |||
Other International (B) | 0.1 | 2.7 | |||
Total | 435.9 | 363.3 | |||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||
United States | $ | 56.11 | $ | 64.24 | |
Trinidad | 43.68 | 54.86 | |||
Other International (B) | 60.13 | 71.61 | |||
Composite | 56.09 | 64.27 | |||
Natural Gas Liquids Volumes (MBbld) (A) | |||||
United States | 119.8 | 100.6 | |||
Other International (B) | - | - | |||
Total | 119.8 | 100.6 | |||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||
United States | $ | 20.28 | $ | 24.46 | |
Other International (B) | - | - | |||
Composite | 20.28 | 24.46 | |||
Natural Gas Volumes (MMcfd) (A) | |||||
United States | 1,003 | 853 | |||
Trinidad | 267 | 293 | |||
Other International (B) | 38 | 30 | |||
Total | 1,308 | 1,176 | |||
Average Natural Gas Prices ($/Mcf) (C) | |||||
United States | $ | 2.77 | $ | 2.76 | |
Trinidad | 2.91 | 2.88 | |||
Other International (B) | 4.37 | 4.36 | |||
Composite | 2.85 | 2.83 | |||
Crude Oil Equivalent Volumes (MBoed) (D) | |||||
United States | 722.0 | 602.5 | |||
Trinidad | 45.1 | 49.8 | |||
Other International (B) | 6.5 | 7.6 | |||
Total | 773.6 | 659.9 | |||
Total MMBoe (D) | 69.6 | 59.4 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | ||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. | ||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018). | ||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
March 31, | December 31, | ||||
2019 | 2018 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 1,135,810 | $ | 1,555,634 | |
Accounts Receivable, Net | 2,203,438 | 1,915,215 | |||
Inventories | 860,764 | 859,359 | |||
Assets from Price Risk Management Activities | 3,909 | 23,806 | |||
Income Taxes Receivable | 440,217 | 427,909 | |||
Other | 263,747 | 275,467 | |||
Total | 4,907,885 | 5,057,390 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 58,691,746 | 57,330,016 | |||
Other Property, Plant and Equipment | 4,277,888 | 4,220,665 | |||
Total Property, Plant and Equipment | 62,969,634 | 61,550,681 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (33,840,631) | (33,475,162) | |||
Total Property, Plant and Equipment, Net | 29,129,003 | 28,075,519 | |||
Deferred Income Taxes | 1,224 | 777 | |||
Other Assets | 1,625,423 | 800,788 | |||
Total Assets | $ | 35,663,535 | $ | 33,934,474 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 2,452,337 | $ | 2,239,850 | |
Accrued Taxes Payable | 239,524 | 214,726 | |||
Dividends Payable | 126,979 | 126,971 | |||
Liabilities from Price Risk Management Activities | 746 | - | |||
Current Portion of Long-Term Debt | 914,861 | 913,093 | |||
Current Portion of Operating Lease Liabilities | 396,294 | - | |||
Other | 170,527 | 233,724 | |||
Total | 4,301,268 | 3,728,364 | |||
Long-Term Debt | 5,166,050 | 5,170,169 | |||
Other Liabilities | 1,772,248 | 1,258,355 | |||
Deferred Income Taxes | 4,520,172 | 4,413,398 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and | 205,807 | 205,804 | |||
Additional Paid in Capital | 5,695,197 | 5,658,794 | |||
Accumulated Other Comprehensive Loss | (2,869) | (1,358) | |||
Retained Earnings | 14,050,676 | 13,543,130 | |||
Common Stock Held in Treasury, 425,637 Shares at March 31, 2019 | (45,014) | (42,182) | |||
Total Stockholders' Equity | 19,903,797 | 19,364,188 | |||
Total Liabilities and Stockholders' Equity | $ | 35,663,535 | $ | 33,934,474 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Three Months Ended | |||||
March 31, | |||||
2019 | 2018 | ||||
Cash Flows from Operating Activities | |||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||
Net Income | $ | 635,426 | $ | 638,589 | |
Items Not Requiring (Providing) Cash | |||||
Depreciation, Depletion and Amortization | 879,595 | 748,591 | |||
Impairments | 72,356 | 64,609 | |||
Stock-Based Compensation Expenses | 39,087 | 35,486 | |||
Deferred Income Taxes | 106,324 | 171,362 | |||
Losses on Asset Dispositions, Net | 3,836 | 14,969 | |||
Other, Net | 2,952 | 2,013 | |||
Dry Hole Costs | 94 | - | |||
Mark-to-Market Commodity Derivative Contracts | |||||
Total Losses | 20,580 | 59,771 | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | 20,846 | (21,965) | |||
Other, Net | 976 | (478) | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||
Accounts Receivable | (308,996) | (109,654) | |||
Inventories | (18,979) | (106,799) | |||
Accounts Payable | 194,082 | 53,652 | |||
Accrued Taxes Payable | 114,998 | 21,950 | |||
Other Assets | (6,935) | (8,863) | |||
Other Liabilities | (54,092) | (29,055) | |||
Changes in Components of Working Capital Associated with Investing and Financing | (94,381) | 17,988 | |||
Net Cash Provided by Operating Activities | 1,607,769 | 1,552,166 | |||
Investing Cash Flows | |||||
Additions to Oil and Gas Properties | (1,939,473) | (1,365,111) | |||
Additions to Other Property, Plant and Equipment | (60,963) | (76,100) | |||
Proceeds from Sales of Assets | 15,049 | 2,829 | |||
Changes in Components of Working Capital Associated with Investing Activities | 94,381 | (18,045) | |||
Net Cash Used in Investing Activities | (1,891,006) | (1,456,427) | |||
Financing Cash Flows | |||||
Dividends Paid | (127,546) | (97,026) | |||
Treasury Stock Purchased | (6,248) | (16,776) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 403 | 1,453 | |||
Repayment of Capital Lease Obligation | (3,190) | (1,671) | |||
Changes in Components of Working Capital Associated with Financing Activities | - | 57 | |||
Net Cash Used in Financing Activities | (136,581) | (113,963) | |||
Effect of Exchange Rate Changes on Cash | (6) | 90 | |||
Decrease in Cash and Cash Equivalents | (419,824) | (18,134) | |||
Cash and Cash Equivalents at Beginning of Period | 1,555,634 | 834,228 | |||
Cash and Cash Equivalents at End of Period | $ | 1,135,810 | $ | 816,094 |
EOG RESOURCES, INC. | ||||||||||||||
First Quarter 2019 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells On Line | Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross | Net | Lateral | Crude Oil and | Natural Gas | Natural Gas | Crude Oil | ||||||||
Delaware Basin | ||||||||||||||
Wolfcamp | 61 | 53 | 7,800 | 1,950 | 400 | 3.8 | 2,950 | |||||||
Bone Spring | 12 | 10 | 5,500 | 1,500 | 300 | 1.9 | 2,100 | |||||||
Leonard | 5 | 5 | 7,600 | 1,650 | 650 | 4.3 | 3,000 | |||||||
South Texas Eagle Ford | 93 | 89 | 8,300 | 1,350 | 150 | 0.8 | 1,650 | |||||||
Powder River Basin | ||||||||||||||
Turner | 5 | 4 | 9,800 | 650 | 650 | 1.0 | 1,450 | |||||||
DJ Basin Codell | 25 | 13 | 9,600 | 600 | 50 | 0.3 | 700 | |||||||
Anadarko Basin Woodford Oil Window | 4 | 3 | 9,700 | 900 | 100 | 0.6 | 1,100 |
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) | |||||||||||||||
To Net Income (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month periods ended March 31, 2019 and 2018 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market losses from these transactions, to eliminate the net losses on asset dispositions in 2019 and 2018, to add back impairment charges related to certain of EOG's assets in 2019 and 2018 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||
March 31, 2019 | March 31, 2018 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $827,236 | $(191,810) | $635,426 | $ 1.10 | $813,359 | $(174,770) | $638,589 | $ 1.10 | |||||||
Adjustments: | |||||||||||||||
Losses on Mark-to-Market Commodity | 20,580 | (4,533) | 16,047 | 0.02 | 59,771 | (13,166) | 46,605 | 0.08 | |||||||
Net Cash Received from (Payments for) | 20,846 | (4,592) | 16,254 | 0.03 | (21,965) | 4,838 | (17,127) | (0.03) | |||||||
Add: Losses on Asset Dispositions | 3,836 | (736) | 3,100 | 0.01 | 14,969 | (3,324) | 11,645 | 0.02 | |||||||
Add: Impairments | 23,745 | (5,230) | 18,515 | 0.03 | 20,876 | (4,598) | 16,278 | 0.03 | |||||||
Less: Tax Reform Impact | - | - | - | - | - | (6,524) | (6,524) | (0.01) | |||||||
Adjustments to Net Income | 69,007 | (15,091) | 53,916 | 0.09 | 73,651 | (22,774) | 50,877 | 0.09 | |||||||
Adjusted Net Income (Non-GAAP) | $896,243 | $(206,901) | $689,342 | $ 1.19 | $887,010 | $(197,544) | $689,466 | $ 1.19 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,207 | 575,775 | |||||||||||||
Diluted | 580,222 | 579,726 |
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||
(Unaudited; in thousands) | ||||||
Calculation of Free Cash Flow (Non-GAAP) | ||||||
(Unaudited; in thousands) | ||||||
The following chart reconciles the three-month periods ended March 31, 2019 and 2018 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months ended March 31, 2019 and 2018. EOG management uses this information for comparative purposes within the industry. | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2019 | 2018 | |||||
Net Cash Provided by Operating Activities (GAAP) | $ | 1,607,769 | $ | 1,552,166 | ||
Adjustments: | ||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 29,787 | 27,936 | ||||
Other Non-Current Income Taxes - Net Receivable | 102,918 | 118,921 | ||||
Changes in Components of Working Capital and Other Assets | ||||||
and Liabilities | ||||||
Accounts Receivable | 308,996 | 109,654 | ||||
Inventories | 18,979 | 106,799 | ||||
Accounts Payable | (194,082) | (53,652) | ||||
Accrued Taxes Payable | (114,998) | (21,950) | ||||
Other Assets | 6,935 | 8,863 | ||||
Other Liabilities | 54,092 | 29,055 | ||||
Changes in Components of Working Capital Associated with | ||||||
Investing and Financing Activities | 94,381 | (17,988) | ||||
Discretionary Cash Flow (Non-GAAP) | $ | 1,914,777 | $ | 1,859,804 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 3% | |||||
Discretionary Cash Flow (Non-GAAP) | $ | 1,914,777 | $ | 1,859,804 | ||
Less: | ||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) | (1,732,476) | (1,478,097) | ||||
Dividends Paid (GAAP) | (127,546) | (97,026) | ||||
Free Cash Flow (Non-GAAP) | $ | 54,755 | $ | 284,681 | ||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three-month periods ended March 31, 2019 and 2018: | ||||||
Total Expenditures (GAAP) | $ | 2,101,919 | $ | 1,546,641 | ||
Less: | ||||||
Asset Retirement Costs | (5,156) | (12,100) | ||||
Non-Cash Expenditures of Other Property, Plant and Equipment | - | (47,635) | ||||
Non-Cash Acquisition Costs of Unproved Properties | (43,481) | (8,809) | ||||
Acquisition Costs of Proved Properties | (320,806) | - | ||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,732,476 | $ | 1,478,097 |
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | ||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | ||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | ||||||
(Non-GAAP) to Net Income (GAAP) | ||||||
(Unaudited; in thousands) | ||||||
The following chart adjusts the three-month periods ended March 31, 2019 and 2018 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) losses from these transactions and to eliminate the losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2019 | 2018 | |||||
Net Income (GAAP) | $ | 635,426 | $ | 638,589 | ||
Adjustments: | ||||||
Interest Expense, Net | 54,906 | 61,956 | ||||
Income Tax Provision | 191,810 | 174,770 | ||||
Depreciation, Depletion and Amortization | 879,595 | 748,591 | ||||
Exploration Costs | 36,324 | 34,836 | ||||
Dry Hole Costs | 94 | - | ||||
Impairments | 72,356 | 64,609 | ||||
EBITDAX (Non-GAAP) | 1,870,511 | 1,723,351 | ||||
Total Losses on MTM Commodity Derivative Contracts | 20,580 | 59,771 | ||||
Net Cash Received from (Payments for) Settlements of Commodity | 20,846 | (21,965) | ||||
Losses on Asset Dispositions, Net | 3,836 | 14,969 | ||||
Adjusted EBITDAX (Non-GAAP) | $ | 1,915,773 | $ | 1,776,126 | ||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 8% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At | At | ||||
March 31, | December 31, | ||||
2019 | 2018 | ||||
Total Stockholders' Equity - (a) | $ | 19,904 | $ | 19,364 | |
Current and Long-Term Debt (GAAP) - (b) | 6,081 | 6,083 | |||
Less: Cash | (1,136) | (1,556) | |||
Net Debt (Non-GAAP) - (c) | 4,945 | 4,527 | |||
Total Capitalization (GAAP) - (a) + (b) | $ | 25,985 | $ | 25,447 | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 24,849 | $ | 23,891 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 23% | 24% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 20% | 19% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through April 26, 2019. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2019 | |||||||||||
January 1, 2019 through May 31, 2019 (closed) | 20,000 | $ 1.075 | |||||||||
June 1, 2019 through December 31, 2019 | 20,000 | 1.075 | |||||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through April 26, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2019 | |||||||||||
January 1, 2019 through May 31, 2019 (closed) | 13,000 | $ 5.572 | |||||||||
June 1, 2019 through December 31, 2019 | 13,000 | 5.572 | |||||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through April 26, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume | Average Price | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2019 | |||||||||||
April 2019 | 25,000 | $ 60.00 | |||||||||
May 1, 2019 through December 31, 2019 | 150,000 | 62.50 | |||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through April 26, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume | Average Price | ||||||||||
(MMBtud) | ($/MMBtu) | ||||||||||
2019 | |||||||||||
April 1, 2019 through May 31, 2019 (closed) | 250,000 | $ 2.90 | |||||||||
June 1, 2019 through October 31, 2019 | 250,000 | 2.90 | |||||||||
Definitions | |||||||||||
Bbld | Barrels per day | ||||||||||
$/Bbl | Dollars per barrel | ||||||||||
MMBtud | Million British thermal units per day | ||||||||||
$/MMBtu | Dollars per million British thermal units | ||||||||||
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), | ||||||||
Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as Used in the Calculations of Return on Capital | ||||||||
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income | ||||||||
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2018 | 2017 | |||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||
Net Interest Expense (GAAP) | $ | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (51) | |||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 194 | ||||||
Net Income (GAAP) - (b) | $ | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) | (201) | (1) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 3,218 | ||||||
Total Stockholders' Equity - (d) | $ | 19,364 | $ | 16,283 | ||||
Average Total Stockholders' Equity * - (e) | $ | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | $ | 6,083 | $ | 6,387 | ||||
Less: Cash | (1,556) | (834) | ||||||
Net Debt (Non-GAAP) - (g) | $ | 4,527 | $ | 5,553 | ||||
Total Capitalization (GAAP) - (d) + (f) | $ | 25,447 | $ | 22,670 | ||||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 23,891 | $ | 21,836 | ||||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 22,864 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.8% | |||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 14.9% | |||||||
Return on Equity (ROE) | ||||||||
ROE (GAAP Net Income) - (b) / (e) | 19.2% | |||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 18.1% | |||||||
* Average for the current and immediately preceding year | ||||||||
Adjustments to Net Income (GAAP) | ||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: | ||||||||
Year Ended December 31, 2018 | ||||||||
Before | Income Tax | After | ||||||
Tax | Impact | Tax | ||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (93) | $ | 20 | $ | (73) | ||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | - | (110) | (110) | |||||
Total | $ | (115) | $ | (86) | $ | (201) |
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as Used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | $ | 235 |
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | $ | 153 |
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | $ | 2,197 |
Total Stockholders' Equity - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 |
Average Total Stockholders' Equity * - (e) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | $ | 14,352 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 |
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 |
Total Capitalization (GAAP) - (d) + (f) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 21,836 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,602 | $ | 19,124 | $ | 20,206 | $ | 20,771 | $ | 19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 13.4% | -4.8% | -21.6% | 14.7% | 12.1% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.1% | -8.1% | -29.5% | 17.6% | 15.3% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as Used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 |
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 |
Net Income (Loss) (GAAP) - (b) | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 |
Total Stockholders' Equity - (d) | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 |
Average Total Stockholders' Equity * - (e) | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 |
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 |
Total Capitalization (GAAP) - (d) + (f) | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 4.4% | 9.5% | 1.6% | 5.8% | 30.5% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as Used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 |
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 |
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 |
Total Stockholders' Equity - (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 |
Average Total Stockholders' Equity * - (e) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 |
Current and Long-Term Debt (GAAP) - (f) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 |
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 |
Total Capitalization (GAAP) - (d) + (f) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as Used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 60 | $ | 45 | $ | 61 | $ | 62 | ||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 39 | $ | 29 | $ | 40 | $ | 40 | ||
Net Income (Loss) (GAAP) - (b) | $ | 87 | $ | 399 | $ | 397 | $ | 569 | ||
Total Stockholders' Equity - (d) | $ | 1,672 | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 |
Average Total Stockholders' Equity * - (e) | $ | 1,658 | $ | 1,512 | $ | 1,256 | $ | 1,205 | ||
Current and Long-Term Debt (GAAP) - (f) | $ | 1,145 | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 |
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,135 | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 |
Total Capitalization (GAAP) - (d) + (f) | $ | 2,817 | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 2,807 | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 2,652 | $ | 2,358 | $ | 2,158 | $ | 2,256 | ||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.8% | 18.2% | 20.2% | 27.0% | ||||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 5.2% | 26.4% | 31.6% | 47.2% | ||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
1st Quarter | |||||||||||
2019 | 2018 | ||||||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 336,291 | $ 300,064 | |||||||||
Transportation Costs | 176,522 | 176,957 | |||||||||
General and Administrative | 106,672 | 94,698 | |||||||||
Cash Operating Expenses | 619,485 | 571,719 | |||||||||
Less: Non-GAAP Adjustments | - | - | |||||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 619,485 | $ 571,719 | |||||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 69,623 | 59,394 | |||||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 8.90 | (c) | $ 9.63 | (d) | |||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
1Q19 compared to 1Q18 - [(c) - (d)] / (d) | -8% | ||||||||||
* Includes stock compensation expense and other non-cash items. | |||||||||||
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 2,456,523 | 2,219,666 | 2,086,373 | 2,398,195 | 2,790,599 | ||||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||||
Less: Acquisition Costs - Yates Transaction | - | - | (5,100) | - | - | ||||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 2,456,523 | $ 2,201,880 | $ 2,039,219 | $ 2,378,840 | $ 2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.36 | (c) | $ 9.91 | (d) | $ 9.95 | (e) | $ 11.39 | (f) | $ 12.86 | (g) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
2018 compared to 2017 - [(c) - (d)] / (d) | -6% | ||||||||||
2018 compared to 2016 - [(c) - (e)] / (e) | -6% | ||||||||||
2018 compared to 2015 - [(c) - (f)] / (f) | -18% | ||||||||||
2018 compared to 2014 - [(c) - (g)] / (g) | -27% | ||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | ||||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||||
Three Months Ended | ||||||||||
March 31, | ||||||||||
2019 | ||||||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 69,623 | |||||||||
Crude Oil and Condensate | $ 2,200,403 | |||||||||
Natural Gas Liquids | 218,638 | |||||||||
Natural Gas | 334,972 | |||||||||
Total Wellhead Revenues - (b) | $ 2,754,013 | |||||||||
Operating Costs | ||||||||||
Lease and Well | $ 336,291 | |||||||||
Transportation Costs | 176,522 | |||||||||
Gathering and Processing Costs | 111,295 | |||||||||
General and Administrative | 106,672 | |||||||||
Taxes Other Than Income | 192,906 | |||||||||
Interest Expense, Net | 54,906 | |||||||||
Total Cash Operating Cost (excluding | $ 978,592 | |||||||||
Depreciation, Depletion and Amortization (DD&A) | 879,595 | |||||||||
Total Operating Cost (excluding Total Exploration | $ 1,858,187 | |||||||||
Exploration Costs | $ 36,324 | |||||||||
Dry Hole Costs | 94 | |||||||||
Impairments | 72,356 | |||||||||
Total Exploration Costs | 108,774 | |||||||||
Less: Impairments (Non-GAAP) | (23,745) | |||||||||
Total Exploration Costs (Non-GAAP) | $ 85,029 | |||||||||
Total Operating Cost (Non-GAAP) (including Total Exploration | $ 1,943,216 | |||||||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 39.56 | |||||||||
Total Cash Operating Cost per Boe | $ 14.06 | |||||||||
Composite Average Margin per Boe (excluding | $ 25.50 | |||||||||
Total Operating Cost per Boe (excluding Total | $ 26.69 | |||||||||
Composite Average Margin per Boe (excluding Total | $ 12.87 | |||||||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 27.91 | |||||||||
Composite Average Margin per Boe (Non-GAAP) | $ 11.65 | |||||||||
EOG RESOURCES, INC. | ||||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||||
Year Ended | ||||||||||
December 31, | ||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | |||||
Crude Oil and Condensate | $ 9,517,440 | $ 6,256,396 | $ 4,317,341 | $ 4,934,562 | $ 9,742,480 | |||||
Natural Gas Liquids | 1,127,510 | 729,561 | 437,250 | 407,658 | 934,051 | |||||
Natural Gas | 1,301,537 | 921,934 | 742,152 | 1,061,038 | 1,916,386 | |||||
Total Wellhead Revenues - (b) | $ 11,946,487 | $ 7,907,891 | $ 5,496,743 | $ 6,403,258 | $ 12,592,917 | |||||
Operating Costs | ||||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | |||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | |||||
Gathering and Processing Costs | 436,973 | 148,775 | 122,901 | 146,156 | 145,800 | |||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | |||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | |||||
Less: Acquisition Costs | - | - | (5,100) | - | - | |||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | |||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | |||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | |||||
General and Administrative (Non-GAAP) | 426,969 | 416,681 | 347,661 | 347,239 | 402,010 | |||||
Taxes Other Than Income | 772,481 | 544,662 | 349,710 | 421,744 | 757,564 | |||||
Interest Expense, Net | 245,052 | 274,372 | 281,681 | 237,393 | 201,458 | |||||
Total Cash Operating Cost (Non-GAAP) (excluding | $ 3,911,029 | $ 3,169,689 | $ 2,793,511 | $ 3,184,133 | $ 3,895,421 | |||||
Depreciation, Depletion and Amortization (DD&A) | 3,435,408 | 3,409,387 | 3,553,417 | 3,313,644 | 3,997,041 | |||||
Total Operating Cost (Non-GAAP) (excluding Total Exploration | $ 7,346,437 | $ 6,579,076 | $ 6,346,928 | $ 6,497,777 | $ 7,892,462 | |||||
Exploration Costs | $ 148,999 | $ 145,342 | $ 124,953 | $ 149,494 | $ 184,388 | |||||
Dry Hole Costs | 5,405 | 4,609 | 10,657 | 14,746 | 48,490 | |||||
Impairments | 347,021 | 479,240 | 620,267 | 6,613,546 | 743,575 | |||||
Total Exploration Costs | 501,425 | 629,191 | 755,877 | 6,777,786 | 976,453 | |||||
Less: Impairments (Non-GAAP) | (152,671) | (261,452) | (320,617) | (6,307,593) | (824,312) | |||||
Total Exploration Costs (Non-GAAP) | $ 348,754 | $ 367,739 | $ 435,260 | $ 470,193 | $ 152,141 | |||||
Total Operating Cost (Non-GAAP) (including Total Exploration | $ 7,695,191 | $ 6,946,815 | $ 6,782,188 | $ 6,967,970 | $ 8,044,603 | |||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 45.51 | $ 35.58 | $ 26.82 | $ 30.66 | $ 58.01 | |||||
Total Cash Operating Cost per Boe (Non-GAAP) | $ 14.90 | $ 14.25 | $ 13.64 | $ 15.25 | $ 17.95 | |||||
Composite Average Margin per Boe (Non-GAAP) (excluding | $ 30.61 | $ 21.33 | $ 13.18 | $ 15.41 | $ 40.06 | |||||
Total Operating Cost per Boe (Non-GAAP) (excluding | $ 27.99 | $ 29.59 | $ 30.98 | $ 31.11 | $ 36.38 | |||||
Composite Average Margin per Boe (Non-GAAP) | $ 17.52 | $ 5.99 | $ (4.16) | $ (0.45) | $ 21.63 | |||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 29.32 | $ 31.24 | $ 33.10 | $ 33.36 | $ 37.08 | |||||
Composite Average Margin per Boe (Non-GAAP) | $ 16.19 | $ 4.34 | $ (6.28) | $ (2.70) | $ 20.93 |
EOG RESOURCES, INC. | |||||||||||
Second Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Second Quarter and Full Year 2019 Forecast | |||||||||||
The forecast items for the second quarter and full year 2019 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Capital Expenditures | |||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. | |||||||||||
(c) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
2Q 2019 | Full Year 2019 | ||||||||||
Daily Sales Volumes | |||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||
United States | 446.5 | - | 454.1 | 442.6 | - | 458.2 | |||||
Trinidad | 0.5 | - | 0.7 | 0.4 | - | 0.6 | |||||
Other International | 0.0 | - | 0.2 | 0.0 | - | 0.2 | |||||
Total | 447.0 | - | 455.0 | 443.0 | - | 459.0 | |||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||
Total | 122.0 | - | 132.0 | 120.0 | - | 140.0 | |||||
Natural Gas Volumes (MMcfd) | |||||||||||
United States | 1,025 | - | 1,075 | 1,030 | - | 1,130 | |||||
Trinidad | 245 | - | 275 | 250 | - | 290 | |||||
Other International | 30 | - | 40 | 30 | - | 40 | |||||
Total | 1,300 | - | 1,390 | 1,310 | - | 1,460 | |||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||
United States | 739.3 | - | 765.3 | 734.3 | - | 786.5 | |||||
Trinidad | 41.3 | - | 46.5 | 42.1 | - | 48.9 | |||||
Other International | 5.0 | - | 6.9 | 5.0 | - | 6.9 | |||||
Total | 785.6 | - | 818.7 | 781.4 | - | 842.3 | |||||
Capital Expenditures ($MM) | $ | 1,600 | - | $ | 1,800 | $ | 6,100 | - | $ | 6,500 | |
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
2Q 2019 | Full Year 2019 | ||||||||||
Operating Costs | |||||||||||
Unit Costs ($/Boe) | |||||||||||
Lease and Well | $ | 4.65 | - | $ | 5.05 | $ | 4.50 | - | $ | 5.30 | |
Transportation Costs | $ | 2.30 | - | $ | 2.80 | $ | 2.50 | - | $ | 3.00 | |
Depreciation, Depletion and Amortization | $ | 12.75 | - | $ | 13.25 | $ | 12.25 | - | $ | 13.25 | |
Expenses ($MM) | |||||||||||
Exploration and Dry Hole | $ | 30 | - | $ | 40 | $ | 155 | - | $ | 195 | |
Impairment | $ | 55 | - | $ | 65 | $ | 190 | - | $ | 230 | |
General and Administrative | $ | 110 | - | $ | 120 | $ | 450 | - | $ | 490 | |
Gathering and Processing | $ | 110 | - | $ | 120 | $ | 440 | - | $ | 480 | |
Capitalized Interest | $ | 7 | - | $ | 9 | $ | 30 | - | $ | 35 | |
Net Interest | $ | 50 | - | $ | 52 | $ | 185 | - | $ | 195 | |
Taxes Other Than Income (% of Wellhead Revenue) | 7.0% | - | 7.4% | 7.0% | - | 7.4% | |||||
Income Taxes | |||||||||||
Effective Rate | 21% | - | 26% | 21% | - | 26% | |||||
Current Tax (Benefit) / Expense ($MM) | $ | - | - | $ | 40 | $ | (10) | - | $ | 30 | |
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||
Differentials | |||||||||||
United States - above (below) WTI | $ | 0.50 | - | $ | 1.50 | $ | (0.50) | - | $ | 1.50 | |
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (11.00) | - | $ | (9.00) | |
Other International - above (below) WTI | $ | (9.00) | - | $ | (5.00) | $ | (1.00) | - | $ | 1.00 | |
Natural Gas Liquids | |||||||||||
Realizations as % of WTI | 32% | - | 40% | 32% | - | 40% | |||||
Natural Gas ($/Mcf) | |||||||||||
Differentials | |||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.60) | - | $ | (0.20) | $ | (0.80) | - | $ | (0.20) | |
Realizations | |||||||||||
Trinidad | $ | 2.60 | - | $ | 3.00 | $ | 2.50 | - | $ | 3.20 | |
Other International | $ | 4.20 | - | $ | 4.70 | $ | 4.00 | - | $ | 5.00 | |
Definitions | |||||||||||
$/Bbl U.S. Dollars per barrel | |||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent | |||||||||||
$/Mcf U.S. Dollars per thousand cubic feet | |||||||||||
$MM U.S. Dollars in millions | |||||||||||
MBbld Thousand barrels per day | |||||||||||
MBoed Thousand barrels of oil equivalent per day | |||||||||||
MMcfd Million cubic feet per day | |||||||||||
NYMEX U.S. New York Mercantile Exchange | |||||||||||
WTI West Texas Intermediate |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-outstanding-first-quarter-2019-results-and-raises-dividend-by-31-percent-300843203.html
SOURCE EOG Resources, Inc.
HOUSTON, March 20, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss first quarter 2019 results on Friday, May 3, 2019, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-first-quarter-2019-results-for-may-3-2019-300815992.html
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 26, 2019 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported fourth quarter 2018 net income of $893 million, or $1.54 per share. This compares to fourth quarter 2017 net income of $2.4 billion, or $4.20 per share. For the full year 2018, EOG reported a company record net income of $3.4 billion, or $5.89 per share, compared to $2.6 billion, or $4.46 per share, for the full year 2017. Net cash from operating activities for the fourth quarter and full year 2018 was $2.1 billion and $7.8 billion, respectively.
Adjusted non-GAAP net income for the fourth quarter 2018 was $718 million, or $1.24 per share, compared to adjusted non-GAAP net income of $401 million, or $0.69 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2018 was $3.2 billion, or $5.54 per share, compared to adjusted non-GAAP net income of $648 million, or $1.12 per share, for the full year 2017. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Fourth Quarter and Full Year 2018 Review
EOG delivered exceptional financial and operating performance in 2018. The company generated record net income and free cash flow, while ending the year with strong improvements in well productivity and additional cost reductions. Total company crude oil volumes grew 19 percent to 399,900 barrels of oil per day (Bopd). Natural gas liquids production increased 31 percent, while natural gas volumes grew 11 percent, contributing to total company production growth of 18 percent.
In the fourth quarter 2018, EOG exceeded the high end of its target range for U.S. crude oil volumes by producing 430,300 Bopd, an increase of 17 percent compared to the same prior year period. Per-unit operating expenses declined during the fourth quarter 2018 compared to the same prior year period. Lower general and administrative expenses, transportation costs and depreciation, depletion and amortization expenses each contributed to the overall cost reduction.
EOG generated $2.1 billion of discretionary cash flow and incurred total expenditures of $1.5 billion in the fourth quarter 2018. After considering cash exploration and development expenditures, excluding acquisitions, of $1.3 billion and dividend payments of $127 million, the company generated free cash flow during the fourth quarter of $637 million. For the full year 2018 EOG generated a company record $1.7 billion of free cash flow. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"Our goal at EOG is to be one of the best companies in the S&P 500. Our stellar 2018 performance delivered a premium combination of high returns and double-digit production growth while generating record free cash flow," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Our 2018 results show that we can be competitive with the best companies across all sectors, and we remain relentlessly focused on further improving our cost structure and operating performance."
2019 Capital Plan
EOG's capital plan is custom-designed each year to increase returns and capital efficiencies. In 2019, EOG is allocating more capital to opportunistic, high quality new drilling potential and somewhat less capital to drilling in established areas. The company's disciplined growth strategy emphasizes generating free cash flow while lowering well costs and per-unit operating expenses and driving improvement in well productivity. Retaining high-quality equipment and crews during the fourth quarter of 2018 positioned the company to further improve efficiencies and returns in 2019.
EOG expects to grow U.S. crude oil production by 12 to 16 percent, fund capital investment and pay the dividend with net cash from operating activities in 2019 at $50 oil. Exploration and development expenditures for 2019 are expected to range from $6.1 to $6.5 billion, including facilities and gathering, processing and other expenditures, excluding acquisitions and non-cash exchanges.
EOG expects to complete approximately 740 net wells in 2019 compared to 763 net wells in 2018. Activity will remain focused in EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and Bakken. The company's investment in new potential areas in the United States includes spending for leasing and related infrastructure to drill wells in a number of new prospects in 2019.
"EOG's disciplined 2019 capital plan delivers improved capital efficiency and strong high-return growth while making investments in new organic high-quality drilling potential to improve the future performance of the company," Thomas said. "Our focus on innovation and operational execution, as well as our investment in new drilling potential, will continue to increase the quality of EOG's premium portfolio. EOG is poised to further improve its position as one of the lowest cost oil producers in the global market, able to create shareholder value through commodity price cycles."
Operating Highlights
EOG completed 262 net wells in the Delaware Basin and increased crude oil production 47% to 126,800 Bopd in 2018. The company made significant progress during 2018 in improving well productivity and reducing well costs. EOG refined spacing and development patterns, reduced drilling days and applied new completion technology designed to lower costs and improve well productivity.
EOG continues to drive growth and operating efficiencies in its premier South Texas Eagle Ford asset. In 2018, the company grew crude oil production 9% to 171,000 Bopd. Of the 304 net wells completed in 2018, EOG drilled a total of 65 wells with lateral lengths greater than 10,000 feet. These wells included the Slytherin C#3H, which, at 13,500 feet, was a company record in the Eagle Ford.
EOG's Powder River Basin and Wyoming DJ Basin activity both contributed to the company's 2018 crude oil production growth. In the Powder River Basin, the company brought eight wells on line during the fourth quarter targeting the Turner, Mowry and Parkman formations. The company plans to add infrastructure and further delineate the field and test additional targets in 2019 to be positioned to execute a more robust development program in the Niobrara and Mowry in 2020 and beyond. In the Wyoming DJ Basin, EOG generated further cost reductions during 2018 through efficiency improvements in drilling, completion and production operations. The company brought 20 wells to sales in the fourth quarter, all targeting the Codell formation. EOG expects further crude oil production growth from its high rate of return drilling in the DJ Basin in 2019.
EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window, where it brought five wells on line in the fourth quarter. The company made significant progress in reducing well costs during 2018, and, as a result, has lowered its 2019 well cost target to $7.6 million.
In the Williston Basin, EOG realized significant operational improvements in 2018. The company drilled 20 net wells with an average treated lateral length of 9,500 feet per well. Efficient drilling performance delivered, on average, an additional 1,000 feet of lateral length per well in 2018 for the same cost as 2017. EOG's Austin 45-1113H well set a company record in the basin with a spud-to-total depth time of 8.4 days.
Reserves
At year-end 2018, total company net proved reserves were 2,928 million barrels of oil equivalent (MMBoe), an increase of 16 percent compared to year-end 2017. Net proved reserve additions from all sources, excluding revisions due to price, replaced 238 percent of EOG's 2018 production at a finding and development cost of $9.33 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 35 MMBoe and asset divestitures decreased net proved reserves by 11 MMBoe. For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
For the 31st consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.
Financial Review
At December 31, 2018, EOG's total debt outstanding was $6.1 billion for a debt-to-total capitalization ratio of 24 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG's net debt was $4.5 billion for a net debt-to-total capitalization ratio of 19 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG completed its previously announced agreement to divest all of its U.K. operations in the fourth quarter 2018. Proceeds from the U.K. divestment and other asset sales in 2018 totaled $227 million.
Fourth Quarter 2018 Results Webcast
Wednesday, February 27, 2019, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow or discretionary cash flow, and certain related estimates regarding future performance, results and financial position. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves, "resource potential" and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2018, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||
December 31, | December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | $ | 4,574.5 | $ | 3,340.4 | $ | 17,275.4 | $ | 11,208.3 | |||
Net Income | $ | 892.8 | $ | 2,430.5 | $ | 3,419.0 | $ | 2,582.6 | |||
Net Income Per Share | |||||||||||
Basic | $ | 1.55 | $ | 4.22 | $ | 5.93 | $ | 4.49 | |||
Diluted | $ | 1.54 | $ | 4.20 | $ | 5.89 | $ | 4.46 | |||
Average Number of Common Shares | |||||||||||
Basic | 577.0 | 575.4 | 576.6 | 574.6 | |||||||
Diluted | 580.3 | 579.2 | 580.4 | 578.7 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||
December 31, | December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | $ | 2,383,326 | $ | 1,929,471 | $ | 9,517,440 | $ | 6,256,396 | |||
Natural Gas Liquids | 266,037 | 249,172 | 1,127,510 | 729,561 | |||||||
Natural Gas | 389,213 | 246,922 | 1,301,537 | 921,934 | |||||||
Gains (Losses) on Mark-to-Market Commodity | 132,095 | (45,032) | (165,640) | 19,828 | |||||||
Gathering, Processing and Marketing | 1,331,105 | 1,008,385 | 5,230,355 | 3,298,087 | |||||||
Gains (Losses) on Asset Dispositions, Net | 79,904 | (65,220) | 174,562 | (99,096) | |||||||
Other, Net | (7,144) | 16,741 | 89,635 | 81,610 | |||||||
Total | 4,574,536 | 3,340,439 | 17,275,399 | 11,208,320 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 346,442 | 281,941 | 1,282,678 | 1,044,847 | |||||||
Transportation Costs | 196,095 | 191,717 | 746,876 | 740,352 | |||||||
Gathering and Processing Costs | 112,396 | 43,295 | 436,973 | 148,775 | |||||||
Exploration Costs | 33,862 | 22,941 | 148,999 | 145,342 | |||||||
Dry Hole Costs | 145 | 4,532 | 5,405 | 4,609 | |||||||
Impairments | 186,087 | 153,442 | 347,021 | 479,240 | |||||||
Marketing Costs | 1,349,416 | 1,009,566 | 5,203,243 | 3,330,237 | |||||||
Depreciation, Depletion and Amortization | 919,963 | 881,745 | 3,435,408 | 3,409,387 | |||||||
General and Administrative | 116,904 | 117,005 | 426,969 | 434,467 | |||||||
Taxes Other Than Income | 190,086 | 158,343 | 772,481 | 544,662 | |||||||
Total | 3,451,396 | 2,864,527 | 12,806,053 | 10,281,918 | |||||||
Operating Income | 1,123,140 | 475,912 | 4,469,346 | 926,402 | |||||||
Other Income, Net | 21,220 | 803 | 16,704 | 9,152 | |||||||
Income Before Interest Expense and Income Taxes | 1,144,360 | 476,715 | 4,486,050 | 935,554 | |||||||
Interest Expense, Net | 56,020 | 63,362 | 245,052 | 274,372 | |||||||
Income Before Income Taxes | 1,088,340 | 413,353 | 4,240,998 | 661,182 | |||||||
Income Tax Provision (Benefit) | 195,572 | (2,017,115) | 821,958 | (1,921,397) | |||||||
Net Income | $ | 892,768 | $ | 2,430,468 | $ | 3,419,040 | $ | 2,582,579 | |||
Dividends Declared per Common Share | $ | 0.2200 | $ | 0.1675 | $ | 0.8100 | $ | 0.6700 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||
December 31, | December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Wellhead Volumes and Prices | |||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||
United States | 430.3 | 366.9 | 394.8 | 335.0 | |||||||
Trinidad | 0.8 | 1.1 | 0.8 | 0.9 | |||||||
Other International (B) | 4.5 | 0.1 | 4.3 | 0.8 | |||||||
Total | 435.6 | 368.1 | 399.9 | 336.7 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||
United States | $ | 59.37 | $ | 56.95 | $ | 65.16 | $ | 50.91 | |||
Trinidad | 51.80 | 46.56 | 57.26 | 42.30 | |||||||
Other International (B) | 70.44 | 45.72 | 71.45 | 57.20 | |||||||
Composite | 59.47 | 56.97 | 65.21 | 50.91 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||
United States | 122.8 | 100.6 | 116.1 | 88.4 | |||||||
Other International (B) | - | - | - | - | |||||||
Total | 122.8 | 100.6 | 116.1 | 88.4 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||
United States | $ | 23.54 | $ | 26.92 | $ | 26.60 | $ | 22.61 | |||
Other International (B) | - | - | - | - | |||||||
Composite | 23.54 | 26.92 | 26.60 | 22.61 | |||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||
United States | 974 | 829 | 923 | 765 | |||||||
Trinidad | 230 | 299 | 266 | 313 | |||||||
Other International (B) | 32 | 32 | 30 | 25 | |||||||
Total | 1,236 | 1,160 | 1,219 | 1,103 | |||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||
United States | $ | 3.50 | $ | 2.17 | $ | 2.88 | $ | 2.20 | |||
Trinidad | 3.03 | 2.52 | 2.94 | 2.38 | |||||||
Other International (B) | 4.02 | 4.23 | 4.08 | 3.89 | |||||||
Composite | 3.42 | (D) | 2.31 | 2.92 | (D) | 2.29 | |||||
Crude Oil Equivalent Volumes (MBoed) (E) | |||||||||||
United States | 715.5 | 605.6 | 664.7 | 551.0 | |||||||
Trinidad | 39.0 | 51.0 | 45.1 | 53.0 | |||||||
Other International (B) | 10.0 | 5.4 | 9.4 | 4.9 | |||||||
Total | 764.5 | 662.0 | 719.2 | 608.9 | |||||||
Total MMBoe (E) | 70.3 | 60.9 | 262.5 | 222.3 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018). | |||||||||||
(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.44 per Mcf for the three and twelve months ended December 31, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09). (see Note 1 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas Revenues. | |||||||||||
(E) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
December 31, | December 31, | ||||
2018 | 2017 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 1,555,634 | $ | 834,228 | |
Accounts Receivable, Net | 1,915,215 | 1,597,494 | |||
Inventories | 859,359 | 483,865 | |||
Assets from Price Risk Management Activities | 23,806 | 7,699 | |||
Income Taxes Receivable | 427,909 | 113,357 | |||
Other | 275,467 | 242,465 | |||
Total | 5,057,390 | 3,279,108 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 57,330,016 | 52,555,741 | |||
Other Property, Plant and Equipment | 4,220,665 | 3,960,759 | |||
Total Property, Plant and Equipment | 61,550,681 | 56,516,500 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (33,475,162) | (30,851,463) | |||
Total Property, Plant and Equipment, Net | 28,075,519 | 25,665,037 | |||
Deferred Income Taxes | 777 | 17,506 | |||
Other Assets | 800,788 | 871,427 | |||
Total Assets | $ | 33,934,474 | $ | 29,833,078 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 2,239,850 | $ | 1,847,131 | |
Accrued Taxes Payable | 214,726 | 148,874 | |||
Dividends Payable | 126,971 | 96,410 | |||
Liabilities from Price Risk Management Activities | - | 50,429 | |||
Current Portion of Long-Term Debt | 913,093 | 356,235 | |||
Other | 233,724 | 226,463 | |||
Total | 3,728,364 | 2,725,542 | |||
Long-Term Debt | 5,170,169 | 6,030,836 | |||
Other Liabilities | 1,258,355 | 1,275,213 | |||
Deferred Income Taxes | 4,413,398 | 3,518,214 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and | 205,804 | 205,788 | |||
Additional Paid in Capital | 5,658,794 | 5,536,547 | |||
Accumulated Other Comprehensive Loss | (1,358) | (19,297) | |||
Retained Earnings | 13,543,130 | 10,593,533 | |||
Common Stock Held in Treasury, 385,042 Shares and 350,961 Shares at | (42,182) | (33,298) | |||
Total Stockholders' Equity | 19,364,188 | 16,283,273 | |||
Total Liabilities and Stockholders' Equity | $ | 33,934,474 | $ | 29,833,078 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Twelve Months Ended | |||||
December 31, | |||||
2018 | 2017 | ||||
Cash Flows from Operating Activities | |||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||
Net Income | $ | 3,419,040 | $ | 2,582,579 | |
Items Not Requiring (Providing) Cash | |||||
Depreciation, Depletion and Amortization | 3,435,408 | 3,409,387 | |||
Impairments | 347,021 | 479,240 | |||
Stock-Based Compensation Expenses | 155,337 | 133,849 | |||
Deferred Income Taxes | 894,156 | (1,473,872) | |||
(Gains) Losses on Asset Dispositions, Net | (174,562) | 99,096 | |||
Other, Net | 7,066 | 6,546 | |||
Dry Hole Costs | 5,405 | 4,609 | |||
Mark-to-Market Commodity Derivative Contracts | |||||
Total (Gains) Losses | 165,640 | (19,828) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (258,906) | 7,438 | |||
Other, Net | 3,108 | 1,204 | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||
Accounts Receivable | (368,180) | (392,131) | |||
Inventories | (395,408) | (174,548) | |||
Accounts Payable | 439,347 | 324,192 | |||
Accrued Taxes Payable | (92,461) | (63,937) | |||
Other Assets | (125,435) | (658,609) | |||
Other Liabilities | 10,949 | (89,871) | |||
Changes in Components of Working Capital Associated with Investing and Financing | 301,083 | 89,992 | |||
Net Cash Provided by Operating Activities | 7,768,608 | 4,265,336 | |||
Investing Cash Flows | |||||
Additions to Oil and Gas Properties | (5,839,294) | (3,950,918) | |||
Additions to Other Property, Plant and Equipment | (237,181) | (173,324) | |||
Proceeds from Sales of Assets | 227,446 | 226,768 | |||
Other Investing Activities | (19,993) | - | |||
Changes in Components of Working Capital Associated with Investing Activities | (301,140) | (89,935) | |||
Net Cash Used in Investing Activities | (6,170,162) | (3,987,409) | |||
Financing Cash Flows | |||||
Long-Term Debt Repayments | (350,000) | (600,000) | |||
Dividends Paid | (438,045) | (386,531) | |||
Treasury Stock Purchased | (63,456) | (63,408) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 20,560 | 20,840 | |||
Repayment of Capital Lease Obligation | (8,219) | (6,555) | |||
Changes in Components of Working Capital Associated with Financing Activities | 57 | (57) | |||
Net Cash Used in Financing Activities | (839,103) | (1,035,711) | |||
Effect of Exchange Rate Changes on Cash | (37,937) | (7,883) | |||
Increase (Decrease) in Cash and Cash Equivalents | 721,406 | (765,667) | |||
Cash and Cash Equivalents at Beginning of Period | 834,228 | 1,599,895 | |||
Cash and Cash Equivalents at End of Period | $ | 1,555,634 | $ | 834,228 |
EOG RESOURCES, INC. | |||||||||||||
Fourth Quarter 2018 Well Results by Play | |||||||||||||
(Unaudited) | |||||||||||||
Wells Online | Initial Gross 30-Day Average Production Rate | ||||||||||||
Gross | Net | Lateral | Crude Oil and | Natural Gas | Natural Gas | Crude Oil | |||||||
Delaware Basin | |||||||||||||
Wolfcamp | 42 | 37 | 7,000 | 1,950 | 600 | 3.7 | 3,150 | ||||||
Bone Spring | 13 | 11 | 5,300 | 1,550 | 300 | 1.9 | 2,150 | ||||||
Leonard | 2 | 1 | 4,600 | 1,200 | 550 | 3.7 | 2,350 | ||||||
South Texas Eagle Ford | 82 | 78 | 7,300 | 1,300 | 150 | 0.8 | 1,600 | ||||||
South Texas Austin Chalk | 6 | 5 | 5,500 | 2,650 | 550 | 2.6 | 3,650 | ||||||
Powder River Basin | |||||||||||||
Turner | 4 | 3 | 9,700 | 800 | 200 | 2.4 | 1,400 | ||||||
Mowry | 2 | 2 | 9,200 | 700 | 450 | 5.5 | 2,050 | ||||||
DJ Basin Codell | 20 | 10 | 9,600 | 700 | 50 | 0.3 | 800 | ||||||
Williston Basin Bakken/Three Forks | 7 | 5 | 10,100 | 550 | 25 | 0.1 | 600 | ||||||
Anadarko Basin Woodford Oil Window | 5 | 4 | 9,200 | 600 | 75 | 0.4 | 750 |
(A) Barrels per day or million cubic feet per day, as applicable. | |||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) | |||||||||||||||
To Net Income (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back certain joint interest billings deemed uncollectible in 2017 and to eliminate certain adjustments in 2018 and 2017 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||
December 31, 2018 | December 31, 2017 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $ 1,088,340 | $ (195,572) | $ 892,768 | $ 1.54 | $ 413,353 | $ 2,017,115 | $ 2,430,468 | $ 4.20 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity | (132,095) | 29,096 | (102,999) | (0.18) | 45,032 | (16,142) | 28,890 | 0.05 | |||||||
Net Cash Received from (Payments for) | (78,678) | 17,330 | (61,348) | (0.11) | 2,708 | (971) | 1,737 | - | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (79,904) | 13,625 | (66,279) | (0.11) | 65,220 | (23,315) | 41,905 | 0.07 | |||||||
Add: Impairments | 131,795 | (29,031) | 102,764 | 0.18 | 100,304 | (35,954) | 64,350 | 0.11 | |||||||
Add: Joint Interest Billings Deemed Uncollectible | - | - | - | - | 4,528 | (1,623) | 2,905 | 0.01 | |||||||
Less: Tax Reform Impact | - | (46,684) | (46,684) | (0.08) | - | (2,169,376) | (2,169,376) | (3.75) | |||||||
Adjustments to Net Income | (158,882) | (15,664) | (174,546) | (0.30) | 217,792 | (2,247,381) | (2,029,589) | (3.51) | |||||||
Adjusted Net Income (Non-GAAP) | $ 929,458 | $ (211,236) | $ 718,222 | $ 1.24 | $ 631,145 | $ (230,266) | $ 400,879 | $ 0.69 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,035 | 575,394 | |||||||||||||
Diluted | 580,288 | 579,203 | |||||||||||||
Twelve Months Ended | Twelve Months Ended | ||||||||||||||
December 31, 2018 | December 31, 2017 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $ 4,240,998 | $ (821,958) | $ 3,419,040 | $ 5.89 | $ 661,182 | $ 1,921,397 | $ 2,582,579 | $ 4.46 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity | 165,640 | (36,486) | 129,154 | 0.22 | (19,828) | 7,107 | (12,721) | (0.02) | |||||||
Net Cash Received from (Payments for) | (258,906) | 57,029 | (201,877) | (0.35) | 7,438 | (2,666) | 4,772 | 0.01 | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (174,562) | 37,860 | (136,702) | (0.24) | 99,096 | (35,270) | 63,826 | 0.11 | |||||||
Add: Impairments | 152,671 | (33,629) | 119,042 | 0.21 | 261,452 | (93,718) | 167,734 | 0.29 | |||||||
Add: Legal Settlement - Early Lease Termination | - | - | - | - | 10,202 | (3,657) | 6,545 | 0.01 | |||||||
Add: Joint Venture Transaction Costs | - | - | - | - | 3,056 | (1,095) | 1,961 | - | |||||||
Add: Joint Interest Billings Deemed Uncollectible | - | - | - | - | 4,528 | (1,623) | 2,905 | 0.01 | |||||||
Less: Tax Reform Impact | - | (110,335) | (110,335) | (0.19) | - | (2,169,376) | (2,169,376) | (3.75) | |||||||
Adjustments to Net Income | (115,157) | (85,561) | (200,718) | (0.35) | 365,944 | (2,300,298) | (1,934,354) | (3.34) | |||||||
Adjusted Net Income (Non-GAAP) | $ 4,125,841 | $ (907,519) | $ 3,218,322 | $ 5.54 | $ 1,027,126 | $ (378,901) | $ 648,225 | $ 1.12 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 576,578 | 574,620 | |||||||||||||
Diluted | 580,441 | 578,693 |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | |||||||||||
To Net Cash Provided by Operating Activities (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
Calculation of Free Cash Flow (Non-GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable (Payable), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and twelve months ended December 31, 2018. EOG management uses this information for comparative purposes within the industry. | |||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||
December 31, | December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 2,085,228 | $ | 1,327,548 | $ | 7,768,608 | $ | 4,265,336 | |||
Adjustments: | |||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 27,270 | 16,420 | 123,986 | 122,688 | |||||||
Other Non-Current Income Taxes - Net Receivable (Payable) | 86,572 | (513,404) | 148,993 | (513,404) | |||||||
Changes in Components of Working Capital and Other Assets | |||||||||||
and Liabilities | |||||||||||
Accounts Receivable | (185,349) | 366,686 | 368,180 | 392,131 | |||||||
Inventories | 108,591 | 156,874 | 395,408 | 174,548 | |||||||
Accounts Payable | 98,178 | (211,298) | (439,347) | (324,192) | |||||||
Accrued Taxes Payable | 55,570 | 13,970 | 92,461 | 63,937 | |||||||
Other Assets | 22,101 | 574,669 | 125,435 | 658,609 | |||||||
Other Liabilities | (25,725) | 20,647 | (10,949) | 89,871 | |||||||
Changes in Components of Working Capital Associated with | |||||||||||
Investing and Financing Activities | (205,599) | (210,365) | (301,083) | (89,992) | |||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,066,837 | $ | 1,541,747 | $ | 8,271,692 | $ | 4,839,532 | |||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 34% | 71% | |||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,066,837 | $ | 8,271,692 | |||||||
Less: | |||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) | (1,302,999) | (6,172,950) | |||||||||
Dividends Paid (GAAP) | (126,970) | (438,045) | |||||||||
Free Cash Flow (Non-GAAP) | $ | 636,868 | $ | 1,660,697 | |||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and twelve months ended December 31, 2018: | |||||||||||
Total Expenditures (GAAP) | $ | 1,504,438 | $ | 6,706,359 | |||||||
Less: | |||||||||||
Asset Retirement Costs | (27,910) | (69,699) | |||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (547) | (49,484) | |||||||||
Non-Cash Acquisition Costs of Unproved Properties | (128,719) | (290,542) | |||||||||
Acquisition Costs of Proved Properties | (44,263) | (123,684) | |||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,302,999 | $ | 6,172,950 |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Income (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||
December 31, | December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Net Income (GAAP) | $ | 892,768 | $ | 2,430,468 | $ | 3,419,040 | $ | 2,582,579 | |||
Adjustments: | |||||||||||
Interest Expense, Net | 56,020 | 63,362 | 245,052 | 274,372 | |||||||
Income Tax Provision (Benefit) | 195,572 | (2,017,115) | 821,958 | (1,921,397) | |||||||
Depreciation, Depletion and Amortization | 919,963 | 881,745 | 3,435,408 | 3,409,387 | |||||||
Exploration Costs | 33,862 | 22,941 | 148,999 | 145,342 | |||||||
Dry Hole Costs | 145 | 4,532 | 5,405 | 4,609 | |||||||
Impairments | 186,087 | 153,442 | 347,021 | 479,240 | |||||||
EBITDAX (Non-GAAP) | 2,284,417 | 1,539,375 | 8,422,883 | 4,974,132 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | (132,095) | 45,032 | 165,640 | (19,828) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity | (78,678) | 2,708 | (258,906) | 7,438 | |||||||
(Gains) Losses on Asset Dispositions, Net | (79,904) | 65,220 | (174,562) | 99,096 | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 1,993,740 | $ | 1,652,335 | $ | 8,155,055 | $ | 5,060,838 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 21% | 61% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At | At | ||||
December 31, | December 31, | ||||
2018 | 2017 | ||||
Total Stockholders' Equity - (a) | $ | 19,364 | $ | 16,283 | |
Current and Long-Term Debt (GAAP) - (b) | 6,083 | 6,387 | |||
Less: Cash | (1,556) | (834) | |||
Net Debt (Non-GAAP) - (c) | 4,527 | 5,553 | |||
Total Capitalization (GAAP) - (a) + (b) | $ | 25,447 | $ | 22,670 | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 23,891 | $ | 21,836 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 24% | 28% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 19% | 25% |
EOG RESOURCES, INC. | |||||||
Reserves Supplemental Data | |||||||
(Unaudited) | |||||||
2018 NET PROVED RESERVES RECONCILIATION SUMMARY | |||||||
United | Other | ||||||
States | Trinidad | International | Total | ||||
CRUDE OIL AND CONDENSATE (MMBbl) | |||||||
Beginning Reserves | 1,304.1 | 0.9 | 8.0 | 1,313.0 | |||
Revisions | (13.2) | (0.2) | - | (13.4) | |||
Purchases in Place | 2.7 | - | - | 2.7 | |||
Extensions, Discoveries and Other Additions | 383.0 | - | - | 383.0 | |||
Sales in Place | (0.8) | - | (6.3) | (7.1) | |||
Production | (144.1) | (0.3) | (1.5) | (145.9) | |||
Ending Reserves | 1,531.7 | 0.4 | 0.2 | 1,532.3 | |||
NATURAL GAS LIQUIDS (MMBbl) | |||||||
Beginning Reserves | 503.5 | - | - | 503.5 | |||
Revisions | 23.9 | - | - | 23.9 | |||
Purchases in Place | 2.0 | - | - | 2.0 | |||
Extensions, Discoveries and Other Additions | 127.4 | - | - | 127.4 | |||
Sales in Place | - | - | - | - | |||
Production | (42.5) | - | - | (42.5) | |||
Ending Reserves | 614.3 | - | - | 614.3 | |||
NATURAL GAS (Bcf) | |||||||
Beginning Reserves | 3,898.5 | 313.4 | 51.2 | 4,263.1 | |||
Revisions | (127.2) | 20.7 | 15.0 | (91.5) | |||
Purchases in Place | 41.3 | - | - | 41.3 | |||
Extensions, Discoveries and Other Additions | 951.4 | - | 4.6 | 956.0 | |||
Sales in Place | (22.2) | - | - | (22.2) | |||
Production | (351.2) | (97.1) | (11.2) | (459.5) | |||
Ending Reserves | 4,390.6 | 237.0 | 59.6 | 4,687.2 | |||
OIL EQUIVALENTS (MMBoe) | |||||||
Beginning Reserves | 2,457.3 | 53.1 | 16.6 | 2,527.0 | |||
Revisions | (10.5) | 3.3 | 2.5 | (4.7) | |||
Purchases in Place | 11.6 | - | - | 11.6 | |||
Extensions, Discoveries and Other Additions | 669.0 | - | 0.7 | 669.7 | |||
Sales in Place | (4.5) | - | (6.3) | (10.8) | |||
Production | (245.1) | (16.5) | (3.4) | (265.0) | |||
Ending Reserves | 2,877.8 | 39.9 | 10.1 | 2,927.8 | |||
Net Proved Developed Reserves (MMBoe) | |||||||
At December 31, 2017 | 1,300.7 | 50.8 | 12.8 | 1,364.3 | |||
At December 31, 2018 | 1,503.4 | 37.7 | 7.0 | 1,548.1 | |||
2018 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) | |||||||
United | Other | ||||||
States | Trinidad | International | Total | ||||
Acquisition Cost of Unproved Properties | $ 486.0 | $ 1.3 | $ - | $ 487.3 | |||
Exploration Costs | 157.2 | 22.5 | 13.9 | 193.6 | |||
Development Costs | 5,515.4 | (0.8) | 30.8 | 5,545.4 | |||
Total Drilling | 6,158.6 | 23.0 | 44.7 | 6,226.3 | |||
Acquisition Cost of Proved Properties | 123.7 | - | - | 123.7 | |||
Asset Retirement Costs | 90.0 | (12.1) | (8.2) | 69.7 | |||
Total Exploration and Development Expenditures | 6,372.3 | 10.9 | 36.5 | 6,419.7 | |||
Gathering, Processing and Other | 286.0 | 0.4 | 0.3 | 286.7 | |||
Total Expenditures | 6,658.3 | 11.3 | 36.8 | 6,706.4 | |||
Proceeds from Sales in Place | (53.3) | - | (174.1) | (227.4) | |||
Net Expenditures | $ 6,605.0 | $ 11.3 | $ (137.3) | $ 6,479.0 | |||
RESERVE REPLACEMENT COSTS ($ / Boe ) * | |||||||
All-in Total, Net of Revisions | $ 8.84 | $ 6.97 | $ 13.97 | $ 8.85 | |||
All-in Total, Excluding Revisions Due to Price | $ 9.32 | $ 6.97 | $ 13.97 | $ 9.33 | |||
RESERVE REPLACEMENT * | |||||||
Drilling Only | 273% | 0% | 21% | 253% | |||
All-in Total, Net of Revisions and Dispositions | 272% | 20% | -91% | 251% | |||
All-in Total, Excluding Revisions Due to Price | 257% | 20% | -91% | 238% | |||
All-in Total, Liquids | 281% | -67% | -420% | 275% | |||
* See attached reconciliation schedule for calculation methodology | |||||||
EOG RESOURCES, INC. | |||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) | |||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) | |||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | |||||||
(Unaudited; in millions, except ratio data) | |||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | |||||||
For the Twelve Months Ended December 31, 2018 | |||||||
United | Other | ||||||
States | Trinidad | International | Total | ||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ 6,372.3 | $ 10.9 | $ 36.5 | $ 6,419.7 | |||
Less: Asset Retirement Costs | (90.0) | 12.1 | 8.2 | (69.7) | |||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | - | - | (290.5) | |||
Total Acquisition Costs of Proved Properties | (123.7) | - | - | (123.7) | |||
Total Exploration and Development Expenditures (Non-GAAP) (a) | $ 5,868.1 | $ 23.0 | $ 44.7 | $ 5,935.8 | |||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ 6,372.3 | $ 10.9 | $ 36.5 | $ 6,419.7 | |||
Less: Asset Retirement Costs | (90.0) | 12.1 | 8.2 | (69.7) | |||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | - | - | (290.5) | |||
Non-Cash Acquisition Costs of Proved Properties | (70.9) | - | - | (70.9) | |||
Total Exploration and Development Expenditures (Non-GAAP) (b) | $ 5,920.9 | $ 23.0 | $ 44.7 | $ 5,988.6 | |||
Total Expenditures (GAAP) | $ 6,658.3 | $ 11.3 | $ 36.8 | $ 6,706.4 | |||
Less: Asset Retirement Costs | (90.0) | 12.1 | 8.2 | (69.7) | |||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | - | - | (290.5) | |||
Non-Cash Acquisition Costs of Proved Properties | (70.9) | - | - | (70.9) | |||
Non-Cash Capital - Other Miscellaneous | (49.5) | - | - | (49.5) | |||
Total Cash Expenditures (Non-GAAP) | $ 6,157.4 | $ 23.4 | $ 45.0 | $ 6,225.8 | |||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||
Revisions Due to Price (c) | 34.8 | - | - | 34.8 | |||
Revisions Other Than Price | (45.3) | 3.3 | 2.5 | (39.5) | |||
Purchases in Place | 11.6 | - | - | 11.6 | |||
Extensions, Discoveries and Other Additions (d) | 669.0 | - | 0.7 | 669.7 | |||
Total Proved Reserve Additions (e) | 670.1 | 3.3 | 3.2 | 676.6 | |||
Sales in Place | (4.5) | - | (6.3) | (10.8) | |||
Net Proved Reserve Additions From All Sources (f) | 665.6 | 3.3 | (3.1) | 665.8 | |||
Production (g) | 245.1 | 16.5 | 3.4 | 265.0 | |||
RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||
Total Drilling, Before Revisions (a / d) | $ 8.77 | $ - | $ 63.86 | $ 8.86 | |||
All-in Total, Net of Revisions (b / e) | $ 8.84 | $ 6.97 | $ 13.97 | $ 8.85 | |||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) | $ 9.32 | $ 6.97 | $ 13.97 | $ 9.33 | |||
RESERVE REPLACEMENT | |||||||
Drilling Only (d / g) | 273% | 0% | 21% | 253% | |||
All-in Total, Net of Revisions and Dispositions (f / g) | 272% | 20% | -91% | 251% | |||
All-in Total, Excluding Revisions Due to Price ((f - c ) / g) | 257% | 20% | -91% | 238% | |||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) | |||||||
Revisions | 10.7 | (0.2) | - | 10.5 | |||
Purchases in Place | 4.7 | - | - | 4.7 | |||
Extensions, Discoveries and Other Additions (h) | 510.4 | - | - | 510.4 | |||
Total Proved Reserve Additions | 525.8 | (0.2) | - | 525.6 | |||
Sales in Place | (0.8) | - | (6.3) | (7.1) | |||
Net Proved Reserve Additions From All Sources (i) | 525.0 | (0.2) | (6.3) | 518.5 | |||
Production (j) | 186.6 | 0.3 | 1.5 | 188.4 | |||
RESERVE REPLACEMENT - LIQUIDS | |||||||
Drilling Only (h / j) | 274% | 0% | 0% | 271% | |||
All-in Total, Net of Revisions and Dispositions (i / j) | 281% | -67% | -420% | 275% | |||
EOG RESOURCES, INC. | |||||||
Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) | |||||||
As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) | |||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | |||||||
(Unaudited; in millions, except ratio data) | |||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. | |||||||
For the Twelve Months Ended December 31, 2018 | |||||||
Total | |||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ 6,419.7 | ||||||
Less: Asset Retirement Costs | (69.7) | ||||||
Acquisition Costs of Unproved Properties | (487.3) | ||||||
Acquisition Costs of Proved Properties | (123.7) | ||||||
Drillbit Exploration and Development Expenditures (Non-GAAP) (j) | $ 5,739.0 | ||||||
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) | 669.7 | ||||||
Add: Conversion of Proved Undeveloped Reserves to Proved Developed | 265.7 | ||||||
Less: Proved Undeveloped Extensions and Discoveries | (490.7) | ||||||
Proved Developed Reserves - Extensions and Discoveries (MMBoe) | 444.7 | ||||||
Total Proved Reserves - Revisions (MMBoe) | (4.7) | ||||||
Less: Proved Undeveloped Reserves - Revisions | 8.2 | ||||||
Proved Developed - Revisions Due to Price | (31.8) | ||||||
Proved Developed Reserves - Revisions Other Than Price (MMBoe) | (28.3) | ||||||
Proved Developed Reserves - Extensions and Discoveries plus Revisions Other than Price (MMBoe) (k) | 416.4 | ||||||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) | $ 13.78 |
EOG RESOURCES, INC. | |||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures | |||||||||
For Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP) | |||||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) | |||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | |||||||||
(Unaudited; in millions, except ratio data) | |||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | |||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ 6,419.7 | $ 4,439.4 | $ 6,445.2 | $ 4,928.3 | $ 7,904.8 | ||||
Less: Asset Retirement Costs | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | ||||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | (255.7) | (3,101.8) | - | - | ||||
Acquisition Costs of Proved Properties | (123.7) | (72.6) | (749.0) | (480.6) | (139.1) | ||||
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) (a) | $ 5,935.8 | $ 4,055.5 | $ 2,614.3 | $ 4,394.2 | $ 7,570.1 | ||||
Total Costs Incurred in Exploration and Development Activities (GAAP) | $ 6,419.7 | $ 4,439.4 | $ 6,445.2 | $ 4,928.3 | $ 7,904.8 | ||||
Less: Asset Retirement Costs | (69.7) | (55.6) | 19.9 | (53.5) | (195.6) | ||||
Non-Cash Acquisition Costs of Unproved Properties | (290.5) | (255.7) | (3,101.8) | - | - | ||||
Non-Cash Acquisition Costs of Proved Properties | (70.9) | (26.2) | (732.3) | - | - | ||||
Total Exploration and Development Expenditures (Non-GAAP) (b) | $ 5,988.6 | $ 4,101.9 | $ 2,631.0 | $ 4,874.8 | $ 7,709.2 | ||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) | |||||||||
Revisions Due to Price (c) | 34.8 | 154.0 | (100.7) | (573.8) | 52.2 | ||||
Revisions Other Than Price | (39.5) | 48.0 | 252.9 | 107.2 | 48.4 | ||||
Purchases in Place | 11.6 | 2.3 | 42.3 | 56.2 | 14.4 | ||||
Extensions, Discoveries and Other Additions (d) | 669.7 | 420.8 | 209.0 | 245.9 | 519.2 | ||||
Total Proved Reserve Additions (e) | 676.6 | 625.1 | 403.5 | (164.5) | 634.2 | ||||
Sales in Place | (10.8) | (20.7) | (167.6) | (3.5) | (36.3) | ||||
Net Proved Reserve Additions From All Sources (f) | 665.8 | 604.4 | 235.9 | (168.0) | 597.9 | ||||
Production (g) | 265.0 | 224.4 | 207.1 | 211.2 | 219.1 | ||||
RESERVE REPLACEMENT COSTS ($ / Boe) | |||||||||
Total Drilling, Before Revisions (a / d) | $ 8.86 | $ 9.64 | $ 12.51 | $ 17.87 | $ 14.58 | ||||
All-in Total, Net of Revisions (b / e) | $ 8.85 | $ 6.56 | $ 6.52 | $ (29.63) | $ 12.16 | ||||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) | $ 9.33 | $ 8.71 | $ 5.22 | $ 11.91 | $ 13.25 |
EOG RESOURCES, INC. | ||||||||
Crude Oil and Natural Gas Financial Commodity | ||||||||
Derivative Contracts | ||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 19, 2019. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||||||
Midland Differential Basis Swap Contracts | ||||||||
Weighted | ||||||||
Average Price | ||||||||
Volume | Differential | |||||||
(Bbld) | ($/Bbl) | |||||||
2018 | ||||||||
January 1, 2018 through December 31, 2018 (closed) | 15,000 | $ 1.063 | ||||||
2019 | ||||||||
January 1, 2019 through February 28, 2019 (closed) | 20,000 | $ 1.075 | ||||||
March 1, 2019 through December 31, 2019 | 20,000 | 1.075 | ||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 19, 2019. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | ||||||||
Gulf Coast Differential Basis Swap Contracts | ||||||||
Weighted | ||||||||
Average Price | ||||||||
Volume | Differential | |||||||
(Bbld) | ($/Bbl) | |||||||
2018 | ||||||||
January 1, 2018 through September 30, 2018 (closed) | 37,000 | $ 3.818 | ||||||
October 1, 2018 through December 31, 2018 (closed) | 52,000 | 3.911 | ||||||
2019 | ||||||||
January 1, 2019 through February 28, 2019 (closed) | 13,000 | $ 5.572 | ||||||
March 1, 2019 through December 31, 2019 | 13,000 | 5.572 | ||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2019, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | ||||||||
Crude Oil Price Swap Contracts | ||||||||
Weighted | ||||||||
Volume | Average Price | |||||||
(Bbld) | ($/Bbl) | |||||||
2018 | ||||||||
January 1, 2018 through November 30, 2018 (closed) | 134,000 | $ 60.04 | ||||||
On November 20, 2018, EOG entered into crude oil price swap contracts for the period December 1, 2018 through December 31, 2018, with notional volumes of 134,000 Bbld at an average price of $53.75 per Bbl. These contracts offset the crude oil price swap contracts for the same time period with notional volumes of 134,000 Bbld at an average price of $60.04 per Bbl. The net cash EOG received for settling these contracts was $26.1 million. The offsetting contracts are excluded from the above table. | ||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||||||
Natural Gas Price Swap Contracts | ||||||||
Weighted | ||||||||
Volume | Average Price | |||||||
(MMBtud) | ($/MMBtu) | |||||||
2018 | ||||||||
March 1, 2018 through November 30, 2018 (closed) | 35,000 | $ 3.00 | ||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. | ||||||||
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 19, 2019, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | ||||||||
Natural Gas Option Contracts | ||||||||
Call Options Sold | Put Options Purchased | |||||||
Weighted | Weighted | |||||||
Volume | Average Price | Volume | Average Price | |||||
(MMBtud) | ($/MMBtu) | (MMBtud) | ($/MMBtu) | |||||
2018 | ||||||||
March 1, 2018 through November 30, 2018 (closed) | 120,000 | $ 3.38 | 96,000 | $ 2.94 | ||||
Definitions | ||||||||
Bbld | Barrels per day | |||||||
$/Bbl | Dollars per barrel | |||||||
MMBtud | Million British thermal units per day | |||||||
$/MMBtu | Dollars per million British thermal units | |||||||
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), | ||||||||
Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of Return on Capital | ||||||||
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), Net Income | ||||||||
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||
(Unaudited; in millions, except ratio data) | ||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||
2018 | 2017 | |||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||
Net Interest Expense (GAAP) | $ | 245 | ||||||
Tax Benefit Imputed (based on 21%) | (51) | |||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 194 | ||||||
Net Income (GAAP) - (b) | $ | 3,419 | ||||||
Adjustments to Net Income, Net of Tax (See Accompanying Schedule) | (201) | (1) | ||||||
Adjusted Net Income (Non-GAAP) - (c) | $ | 3,218 | ||||||
Total Stockholders' Equity - (d) | $ | 19,364 | $ | 16,283 | ||||
Average Total Stockholders' Equity * - (e) | $ | 17,824 | ||||||
Current and Long-Term Debt (GAAP) - (f) | $ | 6,083 | $ | 6,387 | ||||
Less: Cash | (1,556) | (834) | ||||||
Net Debt (Non-GAAP) - (g) | $ | 4,527 | $ | 5,553 | ||||
Total Capitalization (GAAP) - (d) + (f) | $ | 25,447 | $ | 22,670 | ||||
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 23,891 | $ | 21,836 | ||||
Average Total Capitalization (Non-GAAP) * - (h) | $ | 22,864 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.8% | |||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) | 14.9% | |||||||
Return on Equity (ROE) | ||||||||
ROE (GAAP Net Income) - (b) / (e) | 19.2% | |||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) | 18.1% | |||||||
* Average for the current and immediately preceding year | ||||||||
Adjustments to Net Income (GAAP) | ||||||||
(1) See below schedule for detail of adjustments to Net Income (GAAP) in 2018: | ||||||||
Year Ended December 31, 2018 | ||||||||
Before | Income Tax | After | ||||||
Tax | Impact | Tax | ||||||
Adjustments: | ||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (93) | $ | 20 | $ | (73) | ||
Add: Impairments of Certain Assets | 153 | (34) | 119 | |||||
Less: Net Gains on Asset Dispositions | (175) | 38 | (137) | |||||
Less: Tax Reform Impact | - | (110) | (110) | |||||
Total | $ | (115) | $ | (86) | $ | (201) |
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | $ | 235 |
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | (82) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | $ | 153 |
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | $ | 2,197 |
Total Stockholders' Equity - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 |
Average Total Stockholders' Equity * - (e) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | $ | 14,352 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 |
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 |
Total Capitalization (GAAP) - (d) + (f) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 21,836 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 20,602 | $ | 19,124 | $ | 20,206 | $ | 20,771 | $ | 19,365 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 13.4% | -4.8% | -21.6% | 14.7% | 12.1% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.1% | -8.1% | -29.5% | 17.6% | 15.3% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2012 | 2011 | 2010 | 2009 | 2008 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 |
Tax Benefit Imputed (based on 35%) | (75) | (74) | (46) | (35) | (18) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 |
Net Income (Loss) (GAAP) - (b) | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 |
Total Stockholders' Equity - (d) | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 |
Average Total Stockholders' Equity * - (e) | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 |
Current and Long-Term Debt (GAAP) - (f) | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 |
Less: Cash | (876) | (616) | (789) | (686) | (331) | |||||
Net Debt (Non-GAAP) - (g) | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 |
Total Capitalization (GAAP) - (d) + (f) | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 4.4% | 9.5% | 1.6% | 5.8% | 30.5% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 |
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | |||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 |
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 |
Total Stockholders' Equity - (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 |
Average Total Stockholders' Equity * - (e) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 |
Current and Long-Term Debt (GAAP) - (f) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 |
Less: Cash | (54) | (218) | (644) | (21) | (4) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 |
Total Capitalization (GAAP) - (d) + (f) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 |
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | |||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | |||||
* Average for the current and immediately preceding year | ||||||||||
EOG RESOURCES, INC. | ||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | ||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | ||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||
2002 | 2001 | 2000 | 1999 | 1998 | ||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||
(Calculated Using GAAP Net Income) | ||||||||||
Net Interest Expense (GAAP) | $ | 60 | $ | 45 | $ | 61 | $ | 62 | ||
Tax Benefit Imputed (based on 35%) | (21) | (16) | (21) | (22) | ||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 39 | $ | 29 | $ | 40 | $ | 40 | ||
Net Income (Loss) (GAAP) - (b) | $ | 87 | $ | 399 | $ | 397 | $ | 569 | ||
Total Stockholders' Equity - (d) | $ | 1,672 | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 |
Average Total Stockholders' Equity * - (e) | $ | 1,658 | $ | 1,512 | $ | 1,256 | $ | 1,205 | ||
Current and Long-Term Debt (GAAP) - (f) | $ | 1,145 | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 |
Less: Cash | (10) | (3) | (20) | (25) | (6) | |||||
Net Debt (Non-GAAP) - (g) | $ | 1,135 | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 |
Total Capitalization (GAAP) - (d) + (f) | $ | 2,817 | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 |
Total Capitalization (Non-GAAP) - (d) + (g) | $ | 2,807 | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 |
Average Total Capitalization (Non-GAAP) * - (h) | $ | 2,652 | $ | 2,358 | $ | 2,158 | $ | 2,256 | ||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) | 4.8% | 18.2% | 20.2% | 27.0% | ||||||
Return on Equity (ROE) (GAAP) | ||||||||||
ROE (GAAP Net Income) - (b) / (e) | 5.2% | 26.4% | 31.6% | 47.2% | ||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 2,456,523 | 2,219,666 | 2,086,373 | 2,398,195 | 2,790,599 | ||||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||||
Less: Acquisition Costs - Yates Transaction | - | - | (5,100) | - | - | ||||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 2,456,523 | $ 2,201,880 | $ 2,039,219 | $ 2,378,840 | $ 2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.36 | (c) | $ 9.91 | (d) | $ 9.95 | (e) | $ 11.39 | (f) | $ 12.86 | (g) | |
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
2018 compared to 2017 - [(c) - (d)] / (d) | -6% | ||||||||||
2018 compared to 2016 - [(c) - (e)] / (e) | -6% | ||||||||||
2018 compared to 2015 - [(c) - (f)] / (f) | -18% | ||||||||||
2018 compared to 2014 - [(c) - (g)] / (g) | -27% | ||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | |||||||||
Cost per Barrel of Oil Equivalent (Boe) | |||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||
Three Months Ended | |||||||||
March 31, | June 30, | September 30, | December 31, | ||||||
2018 | 2018 | 2018 | 2018 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 59,394 | 63,898 | 68,890 | 70,334 | |||||
Crude Oil and Condensate | $ 2,101,308 | $ 2,377,528 | $ 2,655,278 | $ 2,383,326 | |||||
Natural Gas Liquids | 221,415 | 286,354 | 353,704 | 266,037 | |||||
Natural Gas | 299,766 | 300,845 | 311,713 | 389,213 | |||||
Total Wellhead Revenues - (b) | $ 2,622,489 | $ 2,964,727 | $ 3,320,695 | $ 3,038,576 | |||||
Operating Costs | |||||||||
Lease and Well | $ 300,064 | $ 314,604 | $ 321,568 | $ 346,442 | |||||
Transportation Costs | 176,957 | 177,797 | 196,027 | 196,095 | |||||
Gathering and Processing Costs | 101,345 | 109,169 | 114,063 | 112,396 | |||||
General and Administrative | 94,698 | 104,083 | 111,284 | 116,904 | |||||
Taxes Other Than Income | 179,084 | 194,268 | 209,043 | 190,086 | |||||
Interest Expense, Net | 61,956 | 63,444 | 63,632 | 56,020 | |||||
Total Cash Operating Cost (excluding | $ 914,104 | $ 963,365 | $ 1,015,617 | $ 1,017,943 | |||||
Depreciation, Depletion and Amortization (DD&A) | 748,591 | 848,674 | 918,180 | 919,963 | |||||
Total Operating Cost (excluding Exploration | $ 1,662,695 | $ 1,812,039 | $ 1,933,797 | $ 1,937,906 | |||||
Exploration Costs | $ 34,836 | $ 47,478 | $ 32,823 | $ 33,862 | |||||
Dry Hole Costs | - | 4,902 | 358 | 145 | |||||
Impairments | 64,609 | 51,708 | 44,617 | 186,087 | |||||
Total Exploration Costs | 99,445 | 104,088 | 77,798 | 220,094 | |||||
Less: Impairments (Non-GAAP) | (20,876) | - | - | (131,795) | |||||
Total Exploration Costs (Non-GAAP) | $ 78,569 | $ 104,088 | $ 77,798 | $ 88,299 | |||||
Total Operating Cost (Non-GAAP) (including Exploration | $ 1,741,264 | $ 1,916,127 | $ 2,011,595 | $ 2,026,205 | |||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 44.15 | $ 46.40 | $ 48.20 | $ 43.20 | |||||
Total Cash Operating Cost per Boe | $ 15.39 | $ 15.07 | $ 14.75 | $ 14.48 | |||||
Composite Average Margin per Boe (excluding | $ 28.76 | $ 31.33 | $ 33.45 | $ 28.72 | |||||
Total Operating Cost per Boe (excluding | $ 27.99 | $ 28.35 | $ 28.08 | $ 27.56 | |||||
Composite Average Margin per Boe (excluding | $ 16.16 | $ 18.05 | $ 20.12 | $ 15.64 | |||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 29.31 | $ 29.98 | $ 29.21 | $ 28.82 | |||||
Composite Average Margin per Boe (Non-GAAP) | $ 14.84 | $ 16.42 | $ 18.99 | $ 14.38 | |||||
EOG RESOURCES, INC. | |||||||||
Cost per Barrel of Oil Equivalent (Boe) | |||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||
Year Ended | |||||||||
December 31, | |||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||
Volume - Thousand Barrels of Oil Equivalent - (a) | 262,516 | 222,251 | 204,929 | 208,862 | 217,073 | ||||
Crude Oil and Condensate | $ 9,517,440 | $ 6,256,396 | $ 4,317,341 | $ 4,934,562 | $ 9,742,480 | ||||
Natural Gas Liquids | 1,127,510 | 729,561 | 437,250 | 407,658 | 934,051 | ||||
Natural Gas | 1,301,537 | 921,934 | 742,152 | 1,061,038 | 1,916,386 | ||||
Total Wellhead Revenues - (b) | $ 11,946,487 | $ 7,907,891 | $ 5,496,743 | $ 6,403,258 | $ 12,592,917 | ||||
Operating Costs | |||||||||
Lease and Well | $ 1,282,678 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||
Transportation Costs | 746,876 | 740,352 | 764,106 | 849,319 | 972,176 | ||||
Gathering and Processing Costs | 436,973 | 148,775 | 122,901 | 146,156 | 145,800 | ||||
General and Administrative | 426,969 | 434,467 | 394,815 | 366,594 | 402,010 | ||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||
Less: Acquisition Costs | - | - | (5,100) | - | - | ||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||
General and Administrative (Non-GAAP) | 426,969 | 416,681 | 347,661 | 347,239 | 402,010 | ||||
Taxes Other Than Income | 772,481 | 544,662 | 349,710 | 421,744 | 757,564 | ||||
Interest Expense, Net | 245,052 | 274,372 | 281,681 | 237,393 | 201,458 | ||||
Total Cash Operating Cost (Non-GAAP) (excluding | $ 3,911,029 | $ 3,169,689 | $ 2,793,511 | $ 3,184,133 | $ 3,895,421 | ||||
Depreciation, Depletion and Amortization (DD&A) | 3,435,408 | 3,409,387 | 3,553,417 | 3,313,644 | 3,997,041 | ||||
Total Operating Cost (Non-GAAP) (excluding Exploration | $ 7,346,437 | $ 6,579,076 | $ 6,346,928 | $ 6,497,777 | $ 7,892,462 | ||||
Exploration Costs | $ 148,999 | $ 145,342 | $ 124,953 | $ 149,494 | $ 184,388 | ||||
Dry Hole Costs | 5,405 | 4,609 | 10,657 | 14,746 | 48,490 | ||||
Impairments | 347,021 | 479,240 | 620,267 | 6,613,546 | 743,575 | ||||
Total Exploration Costs | 501,425 | 629,191 | 755,877 | 6,777,786 | 976,453 | ||||
Less: Impairments (Non-GAAP) | (152,671) | (261,452) | (320,617) | (6,307,593) | (824,312) | ||||
Total Exploration Costs (Non-GAAP) | $ 348,754 | $ 367,739 | $ 435,260 | $ 470,193 | $ 152,141 | ||||
Total Operating Cost (Non-GAAP) (including Exploration | $ 7,695,191 | $ 6,946,815 | $ 6,782,188 | $ 6,967,970 | $ 8,044,603 | ||||
Composite Average Wellhead Revenue per Boe - (b) / (a) | $ 45.51 | $ 35.58 | $ 26.82 | $ 30.66 | $ 58.01 | ||||
Total Cash Operating Cost per Boe (Non-GAAP) | $ 14.90 | $ 14.25 | $ 13.64 | $ 15.25 | $ 17.95 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 30.61 | $ 21.33 | $ 13.18 | $ 15.41 | $ 40.06 | ||||
Total Operating Cost per Boe (Non-GAAP) (excluding | $ 27.99 | $ 29.59 | $ 30.98 | $ 31.11 | $ 36.38 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 17.52 | $ 5.99 | $ (4.16) | $ (0.45) | $ 21.63 | ||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 29.32 | $ 31.24 | $ 33.10 | $ 33.36 | $ 37.08 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 16.19 | $ 4.34 | $ (6.28) | $ (2.70) | $ 20.93 |
EOG RESOURCES, INC. | |||||||||||
First Quarter and Full Year 2019 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) First Quarter and Full Year 2019 Forecast | |||||||||||
The forecast items for the first quarter and full year 2019 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Capital Expenditures | |||||||||||
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Exploration Costs, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs and any Non-Cash Exchanges. | |||||||||||
(c) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
1Q 2019 | Full Year 2019 | ||||||||||
Daily Sales Volumes | |||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||
United States | 426.6 | - | 434.2 | 442.6 | - | 458.2 | |||||
Trinidad | 0.4 | - | 0.6 | 0.4 | - | 0.6 | |||||
Other International | 0.0 | - | 0.2 | 0.0 | - | 0.2 | |||||
Total | 427.0 | - | 435.0 | 443.0 | - | 459.0 | |||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||
Total | 115.0 | - | 125.0 | 120.0 | - | 140.0 | |||||
Natural Gas Volumes (MMcfd) | |||||||||||
United States | 950 | - | 1,000 | 1,030 | - | 1,130 | |||||
Trinidad | 245 | - | 275 | 250 | - | 290 | |||||
Other International | 30 | - | 40 | 30 | - | 40 | |||||
Total | 1,225 | - | 1,315 | 1,310 | - | 1,460 | |||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||
United States | 699.9 | - | 725.9 | 734.3 | - | 786.5 | |||||
Trinidad | 41.2 | - | 46.4 | 42.1 | - | 48.9 | |||||
Other International | 5.0 | - | 6.9 | 5.0 | - | 6.9 | |||||
Total | 746.1 | - | 779.2 | 781.4 | - | 842.3 | |||||
Capital Expenditures ($MM) | $ | 1,750 | - | $ | 1,950 | $ | 6,100 | - | $ | 6,500 | |
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
1Q 2019 | Full Year 2019 | ||||||||||
Operating Costs | |||||||||||
Unit Costs ($/Boe) | |||||||||||
Lease and Well | $ | 4.90 | - | $ | 5.30 | $ | 4.50 | - | $ | 5.30 | |
Transportation Costs | $ | 2.50 | - | $ | 3.00 | $ | 2.60 | - | $ | 3.10 | |
Depreciation, Depletion and Amortization | $ | 12.50 | - | $ | 13.00 | $ | 12.25 | - | $ | 13.25 | |
Expenses ($MM) | |||||||||||
Exploration and Dry Hole | $ | 35 | - | $ | 45 | $ | 155 | - | $ | 195 | |
Impairment | $ | 55 | - | $ | 65 | $ | 190 | - | $ | 230 | |
General and Administrative | $ | 110 | - | $ | 120 | $ | 450 | - | $ | 490 | |
Gathering and Processing | $ | 100 | - | $ | 110 | $ | 440 | - | $ | 480 | |
Capitalized Interest | $ | 6 | - | $ | 8 | $ | 25 | - | $ | 30 | |
Net Interest | $ | 54 | - | $ | 56 | $ | 190 | - | $ | 200 | |
Taxes Other Than Income (% of Wellhead Revenue) | 7.2% | - | 7.6% | 7.2% | - | 7.6% | |||||
Income Taxes | |||||||||||
Effective Rate | 20% | - | 25% | 20% | - | 25% | |||||
Current Tax (Benefit) / Expense ($MM) | $ | (55) | - | $ | (15) | $ | (190) | - | $ | (110) | |
Pricing - (Refer toBenchmark Commodity Pricingin text) | |||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||
Differentials | |||||||||||
United States - above (below) WTI | $ | 0.25 | - | $ | 1.25 | $ | (1.00) | - | $ | 1.00 | |
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (11.00) | - | $ | (9.00) | |
Other International - above (below) WTI | $ | 5.00 | - | $ | 9.00 | $ | (1.00) | - | $ | 1.00 | |
Natural Gas Liquids | |||||||||||
Realizations as % of WTI | 37% | - | 43% | 37% | - | 43% | |||||
Natural Gas ($/Mcf) | |||||||||||
Differentials | |||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.40) | - | $ | 0.00 | $ | (0.50) | - | $ | 0.10 | |
Realizations | |||||||||||
Trinidad | $ | 2.50 | - | $ | 2.90 | $ | 2.50 | - | $ | 3.20 | |
Other International | $ | 4.30 | - | $ | 4.80 | $ | 4.00 | - | $ | 5.00 | |
Definitions | |||||||||||
$/Bbl U.S. Dollars per barrel | |||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent | |||||||||||
$/Mcf U.S. Dollars per thousand cubic feet | |||||||||||
$MM U.S. Dollars in millions | |||||||||||
MBbld Thousand barrels per day | |||||||||||
MBoed Thousand barrels of oil equivalent per day | |||||||||||
MMcfd Million cubic feet per day | |||||||||||
NYMEX U.S. New York Mercantile Exchange | |||||||||||
WTI West Texas Intermediate |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2018-results-and-announces-2019-capital-program-300802665.html
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 13, 2019 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (EOG) has declared a dividend of $0.22 per share on EOG's Common Stock, payable April 30, 2019, to stockholders of record as of April 16, 2019. The indicated annual rate is $0.88.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-300795384.html
SOURCE EOG Resources, Inc.
HOUSTON, Jan. 15, 2019 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call and webcast to discuss fourth quarter and full year 2018 results on Wednesday, February 27, 2019, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Events & Presentations page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-conference-call-and-webcast-of-fourth-quarter-and-full-year-2018-results-for-february-27-2019-300778885.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 7, 2018 /PRNewswire/ -- EOG Resources, Inc. (EOG) is scheduled to present at the Bank of America Merrill Lynch Global Energy Conference at 3:00 p.m. Central time (4:00 p.m. Eastern time) on Wednesday, November 14. Lloyd W. "Billy" Helms, Jr., Chief Operating Officer, will present on behalf of EOG.
Please visit the Investors/Events & Presentations page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available for ninety days.
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conference-300746015.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 1, 2018 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported third quarter 2018 net income of $1.2 billion, or $2.05 per share. This compares to third quarter 2017 net income of $101 million, or $0.17 per share. Net cash from operating activities in the third quarter 2018 was $2.2 billion.
Adjusted non-GAAP net income for the third quarter 2018 was $1.0 billion, or $1.75 per share, compared to adjusted non-GAAP net income of $111 million, or $0.19 per share, for the same prior year period. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Third Quarter Review
EOG set a company record and exceeded the high end of its target range for crude oil volumes in the third quarter 2018 by producing 415,000 barrels of oil per day (Bopd), an increase of 27 percent compared to the same prior year period. Natural gas liquids (NGL) production increased 46 percent while natural gas volumes grew 13 percent, contributing to total company production growth of 25 percent.
Per-unit operating expenses declined during the third quarter 2018 compared to the same prior year period. General and administrative expenses fell 20 percent, transportation costs declined 15 percent and depreciation, depletion and amortization expenses fell 13 percent, all on a per-unit basis.
EOG generated $2.3 billion of discretionary cash flow in the third quarter 2018. After considering exploration and development expenditures of $1.7 billion and dividend payments of $107 million, EOG produced free cash flow during the third quarter of $503 million. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
"EOG delivered a compelling combination of production growth, high returns and free cash flow in the third quarter 2018 due to disciplined capital allocation. These results demonstrate the value of EOG's sustainable business model," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is making significant progress lowering costs and improving well performance. Our culture of innovation, experimentation and entrepreneurship combined with our ability to capture and quickly analyze real-time data and make rapid changes in the field are resulting in significant performance improvements company-wide."
Updated 2018 Outlook
EOG has raised its target for full-year 2018 crude oil production growth to 19 percent. To maintain operational continuity into 2019, the company elected to retain high performing service providers for the remainder of 2018. Approximately 65 percent of its anticipated 2019 services have been secured at competitive pricing. As a result, EOG increased its 2018 exploration and development expenditure forecast to $5.8 to $6.0 billion, excluding acquisitions and non-cash transactions. The company is on track to reduce total well costs by five percent in 2018, and targets further well cost reductions in 2019. EOG now expects to complete approximately 720 net wells in 2018, an increase of 20 net wells from its prior forecast.
"We are positioning EOG to carry the operating efficiencies gained this year into 2019. We secured a significant proportion of our service costs, which along with disciplined execution will help further reduce well costs and improve returns," Thomas continued. "With a deep inventory of premium drilling locations across multiple plays, EOG will continue to allocate capital to the highest return areas while maintaining a disciplined operating pace. EOG is well positioned to continue delivering its unique combination of high returns, disciplined growth and strong free cash flow for years to come."
Operating Highlights
EOG's South Texas Eagle Ford remained the most active area of the company in the third quarter 2018. EOG now expects to complete 290 net wells in 2018, an addition of 20 net wells from the prior forecast. EOG also continued to delineate the South Texas Austin Chalk, completing 14 wells in the third quarter.
In the Delaware Basin, EOG made significant progress on well cost reductions and optimizing targeting and development patterns. The company increased the number of wells developed in a single package and drilled longer laterals. Packages of four wells or more accounted for 87 percent of the wells brought on line in the third quarter. EOG also made additional progress towards its cost reduction goals. Drilling speeds and the pace of completion operations increased markedly during the quarter. In addition, the company now supplies nearly all of its Delaware Basin sand from local sources and has further increased its use of low-cost recycled water.
EOG continued development of its premium play in the Eastern Anadarko Basin Woodford Oil Window. EOG is testing spacing patterns and various targets across the play. The company completed 11 wells in the third quarter. EOG completed a package of four wells spaced 660 feet apart late in the second quarter. The Ted 2326 #1H-#4H were completed with an average treated lateral length of 10,000 feet per well and average 30-day initial production rates per well of 800 barrels of oil equivalent per day, or 660 Bopd, 90 barrels per day of NGLs and 0.3 million cubic feet per day of natural gas. These low-decline wells support our initial spacing assessment of 660 feet. EOG is also making significant progress reducing well costs in this new play. Recent wells have been brought to production at costs at or below the company's $7.8 million target.
EOG continued development of its premium plays across the Rocky Mountain region. The company brought 20 wells on line in the Powder River Basin during the third quarter 2018, including 13 wells from the Turner formation. In the Wyoming DJ Basin, EOG began production from 25 wells in the third quarter 2018. EOG completed 19 wells in the Williston Basin during the third quarter as part of its seasonal development program.
Financial Review
At September 30, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 26 percent. Considering cash on the balance sheet at the end of the third quarter, EOG's net debt was $5.2 billion for a net debt-to-total capitalization ratio of 22 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG reached an agreement to divest all of its U.K. operations. Closing is anticipated in the fourth quarter 2018.
During the third quarter ended September 30, 2018, EOG entered into additional crude oil derivative contracts. A comprehensive summary of EOG's crude oil and natural gas derivative contracts is provided in the attached tables.
Third Quarter 2018 Results Webcast
Friday, November 2, 2018, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG website for one year.
http://investors.eogresources.com/Investors
About EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. To learn more visit www.eogresources.com.
Investor Contacts
David Streit 713-571-4902
Neel Panchal 713-571-4884
John Wagner 713-571-4404
Media and Investor Contact
Kimberly Ehmer 713-571-4676
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows, pay down indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG's actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | $ | 4,781.6 | $ | 2,644.8 | $ | 12,700.9 | $ | 7,867.9 | |||
Net Income | $ | 1,191.0 | $ | 100.5 | $ | 2,526.3 | $ | 152.1 | |||
Net Income Per Share | |||||||||||
Basic | $ | 2.06 | $ | 0.17 | $ | 4.38 | $ | 0.26 | |||
Diluted | $ | 2.05 | $ | 0.17 | $ | 4.35 | $ | 0.26 | |||
Average Number of Common Shares | |||||||||||
Basic | 577.3 | 574.8 | 576.4 | 574.4 | |||||||
Diluted | 581.6 | 578.7 | 580.4 | 578.5 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Operating Revenues and Other | |||||||||||
Crude Oil and Condensate | $ | 2,655,278 | $ | 1,451,410 | $ | 7,134,114 | $ | 4,326,925 | |||
Natural Gas Liquids | 353,704 | 180,038 | 861,473 | 480,389 | |||||||
Natural Gas | 311,713 | 220,402 | 912,324 | 675,012 | |||||||
Gains (Losses) on Mark-to-Market Commodity | (52,081) | (6,606) | (297,735) | 64,860 | |||||||
Gathering, Processing and Marketing | 1,360,992 | 784,368 | 3,899,250 | 2,289,702 | |||||||
Gains (Losses) on Asset Dispositions, Net | 115,944 | (8,202) | 94,658 | (33,876) | |||||||
Other, Net | 36,074 | 23,434 | 96,779 | 64,869 | |||||||
Total | 4,781,624 | 2,644,844 | 12,700,863 | 7,867,881 | |||||||
Operating Expenses | |||||||||||
Lease and Well | 321,568 | 251,943 | 936,236 | 762,906 | |||||||
Transportation Costs | 196,027 | 183,565 | 550,781 | 548,635 | |||||||
Gathering and Processing Costs | 114,063 | 32,590 | 324,577 | 105,480 | |||||||
Exploration Costs | 32,823 | 30,796 | 115,137 | 122,401 | |||||||
Dry Hole Costs | 358 | 50 | 5,260 | 77 | |||||||
Impairments | 44,617 | 53,677 | 160,934 | 325,798 | |||||||
Marketing Costs | 1,326,974 | 793,536 | 3,853,827 | 2,320,671 | |||||||
Depreciation, Depletion and Amortization | 918,180 | 846,222 | 2,515,445 | 2,527,642 | |||||||
General and Administrative | 111,284 | 111,717 | 310,065 | 317,462 | |||||||
Taxes Other Than Income | 209,043 | 125,912 | 582,395 | 386,319 | |||||||
Total | 3,274,937 | 2,430,008 | 9,354,657 | 7,417,391 | |||||||
Operating Income | 1,506,687 | 214,836 | 3,346,206 | 450,490 | |||||||
Other Income (Expense), Net | 3,308 | 226 | (4,516) | 8,349 | |||||||
Income Before Interest Expense and Income Taxes | 1,509,995 | 215,062 | 3,341,690 | 458,839 | |||||||
Interest Expense, Net | 63,632 | 69,082 | 189,032 | 211,010 | |||||||
Income Before Income Taxes | 1,446,363 | 145,980 | 3,152,658 | 247,829 | |||||||
Income Tax Provision | 255,411 | 45,439 | 626,386 | 95,718 | |||||||
Net Income | $ | 1,190,952 | $ | 100,541 | $ | 2,526,272 | $ | 152,111 | |||
Dividends Declared per Common Share | $ | 0.2200 | $ | 0.1675 | $ | 0.5900 | $ | 0.5025 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Wellhead Volumes and Prices | |||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) | |||||||||||
United States | 409.2 | 327.1 | 382.9 | 324.3 | |||||||
Trinidad | 0.8 | 0.8 | 0.8 | 0.8 | |||||||
Other International (B) | 5.0 | - | 4.1 | 1.0 | |||||||
Total | 415.0 | 327.9 | 387.8 | 326.1 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) | |||||||||||
United States | $ | 69.53 | $ | 48.06 | $ | 67.35 | $ | 48.61 | |||
Trinidad | 61.71 | 39.42 | 58.91 | 40.24 | |||||||
Other International (B) | 72.81 | - | 71.83 | 51.55 | |||||||
Composite | 69.55 | 48.11 | 67.38 | 48.60 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) | |||||||||||
United States | 127.8 | 87.4 | 113.9 | 84.3 | |||||||
Other International (B) | - | - | - | - | |||||||
Total | 127.8 | 87.4 | 113.9 | 84.3 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) | |||||||||||
United States | $ | 30.09 | $ | 22.38 | $ | 27.71 | $ | 20.87 | |||
Other International (B) | - | - | - | - | |||||||
Composite | 30.09 | 22.38 | 27.71 | 20.87 | |||||||
Natural Gas Volumes (MMcfd) (A) | |||||||||||
United States | 948 | 748 | 905 | 744 | |||||||
Trinidad | 260 | 323 | 278 | 317 | |||||||
Other International (B) | 28 | 25 | 31 | 22 | |||||||
Total | 1,236 | 1,096 | 1,214 | 1,083 | |||||||
Average Natural Gas Prices ($/Mcf) (C) | |||||||||||
United States | $ | 2.67 | $ | 2.20 | $ | 2.66 | $ | 2.22 | |||
Trinidad | 2.88 | 2.04 | 2.91 | 2.33 | |||||||
Other International (B) | 3.83 | 3.74 | 4.10 | 3.72 | |||||||
Composite | 2.74 | (D) | 2.19 | 2.75 | (D) | 2.28 | |||||
Crude Oil Equivalent Volumes (MBoed) (E) | |||||||||||
United States | 695.0 | 539.2 | 647.6 | 532.6 | |||||||
Trinidad | 44.1 | 54.6 | 47.2 | 53.6 | |||||||
Other International (B) | 9.7 | 4.3 | 9.2 | 4.8 | |||||||
Total | 748.8 | 598.1 | 704.0 | 591.0 | |||||||
Total MMBoe (E) | 68.9 | 55.0 | 192.2 | 161.3 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018). | |||||||||||
(D) Includes positive revenue adjustments of $0.49 per Mcf and $0.43 per Mcf for the three and nine months ended September 30, 2018, respectively, related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09). (see Note 1 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Revenues. | |||||||||||
(E) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
September 30, | December 31, | ||||
2018 | 2017 | ||||
ASSETS | |||||
Current Assets | |||||
Cash and Cash Equivalents | $ | 1,274,132 | $ | 834,228 | |
Accounts Receivable, Net | 2,151,247 | 1,597,494 | |||
Inventories | 766,964 | 483,865 | |||
Assets from Price Risk Management Activities | 1,569 | 7,699 | |||
Income Taxes Receivable | 320,938 | 113,357 | |||
Other | 302,242 | 242,465 | |||
Total | 4,817,092 | 3,279,108 | |||
Property, Plant and Equipment | |||||
Oil and Gas Properties (Successful Efforts Method) | 56,799,237 | 52,555,741 | |||
Other Property, Plant and Equipment | 4,191,958 | 3,960,759 | |||
Total Property, Plant and Equipment | 60,991,195 | 56,516,500 | |||
Less: Accumulated Depreciation, Depletion and Amortization | (33,043,454) | (30,851,463) | |||
Total Property, Plant and Equipment, Net | 27,947,741 | 25,665,037 | |||
Deferred Income Taxes | 16,880 | 17,506 | |||
Other Assets | 856,023 | 871,427 | |||
Total Assets | $ | 33,637,736 | $ | 29,833,078 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities | |||||
Accounts Payable | $ | 2,435,773 | $ | 1,847,131 | |
Accrued Taxes Payable | 249,234 | 148,874 | |||
Dividends Payable | 126,829 | 96,410 | |||
Liabilities from Price Risk Management Activities | 132,618 | 50,429 | |||
Current Portion of Long-Term Debt | 1,262,874 | 356,235 | |||
Other | 217,819 | 226,463 | |||
Total | 4,425,147 | 2,725,542 | |||
Long-Term Debt | 5,171,949 | 6,030,836 | |||
Other Liabilities | 1,302,249 | 1,275,213 | |||
Deferred Income Taxes | 4,199,921 | 3,518,214 | |||
Commitments and Contingencies | |||||
Stockholders' Equity | |||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and | 205,803 | 205,788 | |||
Additional Paid in Capital | 5,626,259 | 5,536,547 | |||
Accumulated Other Comprehensive Loss | (19,458) | (19,297) | |||
Retained Earnings | 12,778,104 | 10,593,533 | |||
Common Stock Held in Treasury, 478,042 Shares at September 30, 2018 | (52,238) | (33,298) | |||
Total Stockholders' Equity | 18,538,470 | 16,283,273 | |||
Total Liabilities and Stockholders' Equity | $ | 33,637,736 | $ | 29,833,078 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Nine Months Ended | |||||
September 30, | |||||
2018 | 2017 | ||||
Cash Flows from Operating Activities | |||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: | |||||
Net Income | $ | 2,526,272 | $ | 152,111 | |
Items Not Requiring (Providing) Cash | |||||
Depreciation, Depletion and Amortization | 2,515,445 | 2,527,642 | |||
Impairments | 160,934 | 325,798 | |||
Stock-Based Compensation Expenses | 116,290 | 101,537 | |||
Deferred Income Taxes | 681,702 | 114,850 | |||
(Gains) Losses on Asset Dispositions, Net | (94,658) | 33,876 | |||
Other, Net | 15,314 | (4,514) | |||
Dry Hole Costs | 5,260 | 77 | |||
Mark-to-Market Commodity Derivative Contracts | |||||
Total (Gains) Losses | 297,735 | (64,860) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts | (180,228) | 4,730 | |||
Other, Net | 1,652 | 270 | |||
Changes in Components of Working Capital and Other Assets and Liabilities | |||||
Accounts Receivable | (553,529) | (25,445) | |||
Inventories | (286,817) | (17,674) | |||
Accounts Payable | 537,525 | 112,894 | |||
Accrued Taxes Payable | (36,891) | (49,967) | |||
Other Assets | (103,334) | (83,940) | |||
Other Liabilities | (14,776) | (69,224) | |||
Changes in Components of Working Capital Associated with Investing and Financing | 95,484 | (120,373) | |||
Net Cash Provided by Operating Activities | 5,683,380 | 2,937,788 | |||
Investing Cash Flows | |||||
Additions to Oil and Gas Properties | (4,571,932) | (2,927,988) | |||
Additions to Other Property, Plant and Equipment | (202,384) | (139,558) | |||
Proceeds from Sales of Assets | 11,582 | 191,593 | |||
Other Investing Activities | (19,993) | - | |||
Changes in Components of Working Capital Associated with Investing Activities | (95,541) | 120,469 | |||
Net Cash Used in Investing Activities | (4,878,268) | (2,755,484) | |||
Financing Cash Flows | |||||
Long-Term Debt Repayments | - | (600,000) | |||
Dividends Paid | (311,075) | (289,261) | |||
Treasury Stock Purchased | (58,558) | (50,374) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan | 12,098 | 11,174 | |||
Repayment of Capital Lease Obligation | (5,052) | (4,897) | |||
Changes in Components of Working Capital Associated with Financing Activities | 57 | (96) | |||
Net Cash Used in Financing Activities | (362,530) | (933,454) | |||
Effect of Exchange Rate Changes on Cash | (2,678) | (2,607) | |||
Increase (Decrease) in Cash and Cash Equivalents | 439,904 | (753,757) | |||
Cash and Cash Equivalents at Beginning of Period | 834,228 | 1,599,895 | |||
Cash and Cash Equivalents at End of Period | $ | 1,274,132 | $ | 846,138 |
EOG RESOURCES, INC. | ||||||||||||||
Third Quarter 2018 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells Online | Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross | Net | Lateral | Crude Oil and | Natural Gas | Natural Gas | Crude Oil | ||||||||
Delaware Basin | ||||||||||||||
Wolfcamp | 61 | 58 | 7,100 | 1,655 | 505 | 2.9 | 2,640 | |||||||
Bone Spring | 4 | 4 | 5,200 | 1,135 | 270 | 1.6 | 1,675 | |||||||
Leonard | 6 | 5 | 4,500 | 995 | 325 | 1.9 | 1,645 | |||||||
South Texas Eagle Ford | 90 | 83 | 7,300 | 1,235 | 155 | 0.9 | 1,540 | |||||||
South Texas Austin Chalk | 14 | 10 | 5,000 | 1,815 | 340 | 2.0 | 2,485 | |||||||
Powder River Basin Turner | 13 | 11 | 7,500 | 795 | 320 | 3.7 | 1,730 | |||||||
DJ Basin Codell | 25 | 19 | 10,100 | 915 | 105 | 0.4 | 1,090 | |||||||
Williston Basin Bakken/Three Forks | 19 | 12 | 9,400 | 1,135 | 130 | 0.6 | 1,370 | |||||||
Anadarko Basin Woodford Oil Window | 11 | 9 | 8,500 | 720 | 120 | 0.4 | 915 |
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) | |||||||||||||||
To Net Income (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended | Three Months Ended | ||||||||||||||
September 30, 2018 | September 30, 2017 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $1,446,363 | $(255,411) | $1,190,952 | $ 2.05 | $145,980 | $ (45,439) | $100,541 | $ 0.17 | |||||||
Adjustments: | |||||||||||||||
Losses on Mark-to-Market Commodity | 52,081 | (11,472) | 40,609 | 0.07 | 6,606 | (2,368) | 4,238 | 0.01 | |||||||
Net Cash Received from (Payments for) | (91,894) | 20,241 | (71,653) | (0.12) | 2,139 | (767) | 1,372 | - | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (115,944) | 28,934 | (87,010) | (0.15) | 8,202 | (3,068) | 5,134 | 0.01 | |||||||
Less: Tax Reform Impact | - | (57,127) | (57,127) | (0.10) | - | - | - | - | |||||||
Adjustments to Net Income | (155,757) | (19,424) | (175,181) | (0.30) | 16,947 | (6,203) | 10,744 | 0.02 | |||||||
Adjusted Net Income (Non-GAAP) | $1,290,606 | $(274,835) | $1,015,771 | $ 1.75 | $162,927 | $ (51,642) | $111,285 | $ 0.19 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 577,254 | 574,783 | |||||||||||||
Diluted | 581,559 | 578,736 | |||||||||||||
Nine Months Ended | Nine Months Ended | ||||||||||||||
September 30, 2018 | September 30, 2017 | ||||||||||||||
Income | Diluted | Income | Diluted | ||||||||||||
Before | Tax | After | Earnings | Before | Tax | After | Earnings | ||||||||
Tax | Impact | Tax | per Share | Tax | Impact | Tax | per Share | ||||||||
Reported Net Income (GAAP) | $3,152,658 | $(626,386) | $2,526,272 | $ 4.35 | $247,829 | $ (95,718) | $152,111 | $ 0.26 | |||||||
Adjustments: | |||||||||||||||
(Gains) Losses on Mark-to-Market Commodity | 297,735 | (65,582) | 232,153 | 0.40 | (64,860) | 23,249 | (41,611) | (0.07) | |||||||
Net Cash Received from (Payments for) | (180,228) | 39,699 | (140,529) | (0.24) | 4,730 | (1,695) | 3,035 | 0.01 | |||||||
Add: Net (Gains) Losses on Asset Dispositions | (94,658) | 24,235 | (70,423) | (0.12) | 33,876 | (11,955) | 21,921 | 0.04 | |||||||
Add: Impairments | 20,876 | (4,598) | 16,278 | 0.03 | 161,148 | (57,764) | 103,384 | 0.18 | |||||||
Add: Legal Settlement - Early Lease Termination | - | - | - | - | 10,202 | (3,657) | 6,545 | 0.01 | |||||||
Add: Joint Venture Transaction Costs | - | - | - | - | 3,056 | (1,095) | 1,961 | - | |||||||
Less: Tax Reform Impact | - | (63,651) | (63,651) | (0.11) | - | - | - | - | |||||||
Adjustments to Net Income | 43,725 | (69,897) | (26,172) | (0.04) | 148,152 | (52,917) | 95,235 | 0.17 | |||||||
Adjusted Net Income (Non-GAAP) | $3,196,383 | $(696,283) | $2,500,100 | $ 4.31 | $395,981 | $(148,635) | $247,346 | $ 0.43 | |||||||
Average Number of Common Shares (GAAP) | |||||||||||||||
Basic | 576,431 | 574,370 | |||||||||||||
Diluted | 580,442 | 578,453 | |||||||||||||
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
Calculation of Free Cash Flow (Non-GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and nine-month periods ended September 30, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable (Payable), Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months and nine months ended September 30, 2018. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||
Net Cash Provided by Operating Activities (GAAP) | $ | 2,189,597 | $ | 961,363 | $ | 5,683,380 | $ | 2,937,788 | ||||
Adjustments: | ||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) | 27,032 | 26,132 | 96,716 | 106,268 | ||||||||
Other Non-Current Income Taxes - Net Receivable (Payable) | (129,941) | - | 62,421 | - | ||||||||
Changes in Components of Working Capital and Other Assets | ||||||||||||
and Liabilities | ||||||||||||
Accounts Receivable | 243,778 | 129,231 | 553,529 | 25,445 | ||||||||
Inventories | 94,598 | 11,545 | 286,817 | 17,674 | ||||||||
Accounts Payable | (81,548) | (36,190) | (537,525) | (112,894) | ||||||||
Accrued Taxes Payable | 59,426 | 10,843 | 36,891 | 49,967 | ||||||||
Other Assets | 40,491 | 22,851 | 103,334 | 83,940 | ||||||||
Other Liabilities | (38,392) | 2,355 | 14,776 | 69,224 | ||||||||
Changes in Components of Working Capital Associated with | ||||||||||||
Investing and Financing Activities | (122,763) | 41,235 | (95,484) | 120,373 | ||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,282,278 | $ | 1,169,365 | $ | 6,204,855 | $ | 3,297,785 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase | 95% | 88% | ||||||||||
Discretionary Cash Flow (Non-GAAP) | $ | 2,282,278 | $ | 6,204,855 | ||||||||
Less: | ||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) | (1,671,922) | (4,869,951) | ||||||||||
Dividends Paid (GAAP) | (107,465) | (311,075) | ||||||||||
Free Cash Flow (Non-GAAP) | $ | 502,891 | $ | 1,023,829 | ||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months and nine months ended September 30, 2018: | ||||||||||||
Total Expenditures (GAAP) | $ | 1,828,348 | $ | 5,201,921 | ||||||||
Less: | ||||||||||||
Asset Retirement Costs | (10,834) | (41,789) | ||||||||||
Non-Cash Expenditures of Other Property, Plant and Equipment | (1,257) | (48,937) | ||||||||||
Non-Cash Acquisition Costs of Unproved Properties | (101,821) | (161,823) | ||||||||||
Acquisition Costs of Proved Properties | (42,514) | (79,421) | ||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) | $ | 1,671,922 | $ | 4,869,951 |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Income (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended | Nine Months Ended | ||||||||||
September 30, | September 30, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Net Income (GAAP) | $ | 1,190,952 | $ | 100,541 | $ | 2,526,272 | $ | 152,111 | |||
Adjustments: | |||||||||||
Interest Expense, Net | 63,632 | 69,082 | 189,032 | 211,010 | |||||||
Income Tax Provision | 255,411 | 45,439 | 626,386 | 95,718 | |||||||
Depreciation, Depletion and Amortization | 918,180 | 846,222 | 2,515,445 | 2,527,642 | |||||||
Exploration Costs | 32,823 | 30,796 | 115,137 | 122,401 | |||||||
Dry Hole Costs | 358 | 50 | 5,260 | 77 | |||||||
Impairments | 44,617 | 53,677 | 160,934 | 325,798 | |||||||
EBITDAX (Non-GAAP) | 2,505,973 | 1,145,807 | 6,138,466 | 3,434,757 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts | 52,081 | 6,606 | 297,735 | (64,860) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity | (91,894) | 2,139 | (180,228) | 4,730 | |||||||
(Gains) Losses on Asset Dispositions, Net | (115,944) | 8,202 | (94,658) | 33,876 | |||||||
Adjusted EBITDAX (Non-GAAP) | $ | 2,350,216 | $ | 1,162,754 | $ | 6,161,315 | $ | 3,408,503 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase | 102% | 81% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At | At | ||||
September 30, | December 31, | ||||
2018 | 2017 | ||||
Total Stockholders' Equity - (a) | $ | 18,538 | $ | 16,283 | |
Current and Long-Term Debt (GAAP) - (b) | 6,435 | 6,387 | |||
Less: Cash | (1,274) | (834) | |||
Net Debt (Non-GAAP) - (c) | 5,161 | 5,553 | |||
Total Capitalization (GAAP) - (a) + (b) | $ | 24,973 | $ | 22,670 | |
Total Capitalization (Non-GAAP) - (a) + (c) | $ | 23,699 | $ | 21,836 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] | 26% | 28% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] | 22% | 25% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through October 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2018 | |||||||||||
January 1, 2018 through November 30, 2018 (closed) | 15,000 | $ 1.063 | |||||||||
December 2018 | 15,000 | 1.063 | |||||||||
2019 | |||||||||||
January 1, 2019 through December 31, 2019 | 20,000 | $ 1.075 | |||||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through October 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume | Differential | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2018 | |||||||||||
January 1, 2018 through September 30, 2018 (closed) | 37,000 | $ 3.818 | |||||||||
October 1, 2018 through November 30, 2018 (closed) | 52,000 | 3.911 | |||||||||
December 2018 | 52,000 | 3.911 | |||||||||
2019 | |||||||||||
January 1, 2019 through December 31, 2019 | 13,000 | $ 5.572 | |||||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through October 26, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume | Average Price | ||||||||||
(Bbld) | ($/Bbl) | ||||||||||
2018 | |||||||||||
January 1, 2018 through September 30, 2018 (closed) | 134,000 | $ 60.04 | |||||||||
October 1, 2018 through December 31, 2018 | 134,000 | 60.04 | |||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through October 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume | Average Price | ||||||||||
(MMBtud) | ($/MMBtu) | ||||||||||
2018 | |||||||||||
March 1, 2018 through October 31, 2018 (closed) | 35,000 | $ 3.00 | |||||||||
November 2018 | 35,000 | 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. | |||||||||||
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through October 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold | Put Options Purchased | ||||||||||
Weighted | Weighted | ||||||||||
Volume | Average Price | Volume | Average Price | ||||||||
(MMBtud) | ($/MMBtu) | (MMBtud) | ($/MMBtu) | ||||||||
2018 | |||||||||||
March 1, 2018 through October 31, 2018 (closed) | 120,000 | $ 3.38 | 96,000 | $ 2.94 | |||||||
November 2018 | 120,000 | 3.38 | 96,000 | 2.94 | |||||||
Definitions | |||||||||||
Bbld | Barrels per day | ||||||||||
$/Bbl | Dollars per barrel | ||||||||||
MMBtud | Million British thermal units per day | ||||||||||
$/MMBtu | Dollars per million British thermal units | ||||||||||
NYMEX | U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | ||||||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | ||||||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | ||||||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | ||||||||||||||
Net Interest Expense (GAAP) | $ | 274 | $ | 282 | $ | 237 | $ | 201 | ||||||
Tax Benefit Imputed (based on 35%) | (96) | (99) | (83) | (70) | ||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 178 | $ | 183 | $ | 154 | $ | 131 | ||||||
Net Income (Loss) (GAAP) - (b) | $ | 2,583 | $ | (1,097) | $ | (4,525) | $ | 2,915 | ||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) | (1,934) | (a) | 204 | (b) | 4,559 | (c) | (199) | (d) | ||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) | $ | 649 | $ | (893) | $ | 34 | $ | 2,716 | ||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) | $ | 16,283 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | ||||
Less: Tax Reform Impact | (2,169) | - | - | - | - | |||||||||
Total Stockholders' Equity (Non-GAAP) - (e) | $ | 14,114 | $ | 13,982 | $ | 12,943 | $ | 17,713 | $ | 15,418 | ||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 15,133 | $ | 13,463 | $ | 15,328 | $ | 16,566 | ||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) | $ | 14,048 | $ | 13,463 | $ | 15,328 | $ | 16,566 | ||||||
Current and Long-Term Debt (GAAP) - (h) | $ | 6,387 | $ | 6,986 | $ | 6,655 | $ | 5,906 | $ | 5,909 | ||||
Less: Cash | (834) | (1,600) | (719) | (2,087) | (1,318) | |||||||||
Net Debt (Non-GAAP) - (i) | $ | 5,553 | $ | 5,386 | $ | 5,936 | $ | 3,819 | $ | 4,591 | ||||
Total Capitalization (GAAP) - (d) + (h) | $ | 22,670 | $ | 20,968 | $ | 19,598 | $ | 23,619 | $ | 21,327 | ||||
Total Capitalization (Non-GAAP) - (e) + (i) | $ | 19,667 | $ | 19,368 | $ | 18,879 | $ | 21,532 | $ | 20,009 | ||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 19,518 | $ | 19,124 | $ | 20,206 | $ | 20,771 | ||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 14.1% | -4.8% | -21.6% | 14.7% | ||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) | 4.2% | -3.7% | 0.9% | 13.7% | ||||||||||
Return on Equity (ROE) | ||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) | 17.1% | -8.1% | -29.5% | 17.6% | ||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) | 4.6% | -6.6% | 0.2% | 16.4% | ||||||||||
* Average for the current and immediately preceding year | ||||||||||||||
Adjustments to Net Income (Loss) (GAAP) | ||||||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017: | ||||||||||||||
Year Ended December 31, 2017 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | (12) | $ | 4 | $ | (8) | ||||||||
Add: Impairments of Certain Assets | 261 | (93) | 168 | |||||||||||
Add: Net Losses on Asset Dispositions | 99 | (35) | 64 | |||||||||||
Add: Legal Settlement - Early Lease Termination | 10 | (4) | 6 | |||||||||||
Add: Joint Venture Transaction Costs | 3 | (1) | 2 | |||||||||||
Add: Joint Interest Billings Deemed Uncollectible | 5 | (2) | 3 | |||||||||||
Less: Tax Reform Impact | - | (2,169) | (2,169) | |||||||||||
Total | $ | 366 | $ | (2,300) | $ | (1,934) | ||||||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: | ||||||||||||||
Year Ended December 31, 2016 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | 77 | $ | (28) | $ | 49 | ||||||||
Add: Impairments of Certain Assets | 321 | (113) | 208 | |||||||||||
Less: Net Gains on Asset Dispositions | (206) | 62 | (144) | |||||||||||
Add: Trinidad Tax Settlement | - | 43 | 43 | |||||||||||
Add: Voluntary Retirement Expense | 42 | (15) | 27 | |||||||||||
Add: Acquisition - State Apportionment Change | - | 16 | 16 | |||||||||||
Add: Acquisition Costs | 5 | - | 5 | |||||||||||
Total | $ | 239 | $ | (35) | $ | 204 | ||||||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: | ||||||||||||||
Year Ended December 31, 2015 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact | $ | 668 | $ | (238) | $ | 430 | ||||||||
Add: Impairments of Certain Assets | 6,308 | (2,183) | 4,125 | |||||||||||
Less: Texas Margin Tax Rate Reduction | - | (20) | (20) | |||||||||||
Add: Legal Settlement - Early Leasehold Termination | 19 | (6) | 13 | |||||||||||
Add: Severance Costs | 9 | (3) | 6 | |||||||||||
Add: Net Losses on Asset Dispositions | 9 | (4) | 5 | |||||||||||
Total | $ | 7,013 | $ | (2,454) | $ | 4,559 | ||||||||
(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: | ||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||
Before | Income Tax | After | ||||||||||||
Tax | Impact | Tax | ||||||||||||
Adjustments: | ||||||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact | $ | (800) | $ | 285 | $ | (515) | ||||||||
Add: Impairments of Certain Assets | 824 | (271) | 553 | |||||||||||
Less: Net Gains on Asset Dispositions | (508) | 21 | (487) | |||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated | - | 250 | 250 | |||||||||||
Total | $ | (484) | $ | 285 | $ | (199) |
EOG RESOURCES, INC. | |||||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | |||||||||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | |||||||||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 235 | $ | 214 | $ | 210 | $ | 130 | $ | 101 | $ | 52 | |||||
Tax Benefit Imputed (based on 35%) | (82) | (75) | (74) | (46) | (35) | (18) | |||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 153 | $ | 139 | $ | 136 | $ | 84 | $ | 66 | $ | 34 | |||||
Net Income (Loss) (GAAP) - (b) | $ | 2,197 | $ | 570 | $ | 1,091 | $ | 161 | $ | 547 | $ | 2,437 | |||||
Total Stockholders' Equity (GAAP) - (d) | $ | 15,418 | $ | 13,285 | $ | 12,641 | $ | 10,232 | $ | 9,998 | $ | 9,015 | |||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 14,352 | $ | 12,963 | $ | 11,437 | $ | 10,115 | $ | 9,507 | $ | 8,003 | |||||
Current and Long-Term Debt (GAAP) - (h) | $ | 5,909 | $ | 6,312 | $ | 5,009 | $ | 5,223 | $ | 2,797 | $ | 1,897 | |||||
Less: Cash | (1,318) | (876) | (616) | (789) | (686) | (331) | |||||||||||
Net Debt (Non-GAAP) - (i) | $ | 4,591 | $ | 5,436 | $ | 4,393 | $ | 4,434 | $ | 2,111 | $ | 1,566 | |||||
Total Capitalization (GAAP) - (d) + (h) | $ | 21,327 | $ | 19,597 | $ | 17,650 | $ | 15,455 | $ | 12,795 | $ | 10,912 | |||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 20,009 | $ | 18,721 | $ | 17,034 | $ | 14,666 | $ | 12,109 | $ | 10,581 | |||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 19,365 | $ | 17,878 | $ | 15,850 | $ | 13,388 | $ | 11,345 | $ | 9,351 | |||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 12.1% | 4.0% | 7.7% | 1.8% | 5.4% | 26.4% | |||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 15.3% | 4.4% | 9.5% | 1.6% | 5.8% | 30.5% | |||||||||||
* Average for the current and immediately preceding year | |||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | |||||||||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | |||||||||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 47 | $ | 43 | $ | 63 | $ | 63 | $ | 59 | $ | 60 | |||||
Tax Benefit Imputed (based on 35%) | (16) | (15) | (22) | (22) | (21) | (21) | |||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 31 | $ | 28 | $ | 41 | $ | 41 | $ | 38 | $ | 39 | |||||
Net Income (Loss) (GAAP) - (b) | $ | 1,090 | $ | 1,300 | $ | 1,260 | $ | 625 | $ | 430 | $ | 87 | |||||
Total Stockholders' Equity (GAAP)- (d) | $ | 6,990 | $ | 5,600 | $ | 4,316 | $ | 2,945 | $ | 2,223 | $ | 1,672 | |||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 6,295 | $ | 4,958 | $ | 3,631 | $ | 2,584 | $ | 1,948 | $ | 1,658 | |||||
Current and Long-Term Debt (GAAP) - (h) | $ | 1,185 | $ | 733 | $ | 985 | $ | 1,078 | $ | 1,109 | $ | 1,145 | |||||
Less: Cash | (54) | (218) | (644) | (21) | (4) | (10) | |||||||||||
Net Debt (Non-GAAP) - (i) | $ | 1,131 | $ | 515 | $ | 341 | $ | 1,057 | $ | 1,105 | $ | 1,135 | |||||
Total Capitalization (GAAP) - (d) + (h) | $ | 8,175 | $ | 6,333 | $ | 5,301 | $ | 4,023 | $ | 3,332 | $ | 2,817 | |||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 8,121 | $ | 6,115 | $ | 4,657 | $ | 4,002 | $ | 3,328 | $ | 2,807 | |||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 7,118 | $ | 5,386 | $ | 4,330 | $ | 3,665 | $ | 3,068 | $ | 2,652 | |||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 15.7% | 24.7% | 30.0% | 18.2% | 15.3% | 4.8% | |||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 17.3% | 26.2% | 34.7% | 24.2% | 22.1% | 5.2% | |||||||||||
* Average for the current and immediately preceding year | |||||||||||||||||
EOG RESOURCES, INC. | |||||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total | |||||||||||||||||
Capitalization (Non-GAAP) as used in the Calculation of Return on Capital Employed (Non-GAAP) to Net Interest | |||||||||||||||||
Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) (Non-GAAP) calculation. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Net Debt and Total Capitalization (Non-GAAP) in their ROCE calculation. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||||
2001 | 2000 | 1999 | 1998 | 1997 | |||||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) | |||||||||||||||||
(Calculated Using GAAP Net Income) | |||||||||||||||||
Net Interest Expense (GAAP) | $ | 45 | $ | 61 | $ | 62 | $ | 49 | |||||||||
Tax Benefit Imputed (based on 35%) | (16) | (21) | (22) | (17) | |||||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) | $ | 29 | $ | 40 | $ | 40 | $ | 32 | |||||||||
Net Income (Loss) (GAAP) - (b) | $ | 399 | $ | 397 | $ | 569 | $ | 56 | |||||||||
Total Stockholders' Equity (GAAP)- (d) | $ | 1,643 | $ | 1,381 | $ | 1,130 | $ | 1,280 | $ | 1,281 | |||||||
Average Total Stockholders' Equity (GAAP) * - (f) | $ | 1,512 | $ | 1,256 | $ | 1,205 | $ | 1,281 | |||||||||
Current and Long-Term Debt (GAAP) - (h) | $ | 856 | $ | 859 | $ | 990 | $ | 1,143 | $ | 745 | |||||||
Less: Cash | (3) | (20) | (25) | (6) | (9) | ||||||||||||
Net Debt (Non-GAAP) - (i) | $ | 853 | $ | 839 | $ | 965 | $ | 1,137 | $ | 736 | |||||||
Total Capitalization (GAAP) - (d) + (h) | $ | 2,499 | $ | 2,240 | $ | 2,120 | $ | 2,423 | $ | 2,026 | |||||||
Total Capitalization (Non-GAAP) - (d) + (i) | $ | 2,496 | $ | 2,220 | $ | 2,095 | $ | 2,417 | $ | 2,017 | |||||||
Average Total Capitalization (Non-GAAP) * - (j) | $ | 2,358 | $ | 2,158 | $ | 2,256 | $ | 2,217 | |||||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) | 18.2% | 20.2% | 27.0% | 4.0% | |||||||||||||
Return on Equity (ROE) (GAAP) | |||||||||||||||||
ROE (GAAP Net Income) - (b) / (f) | 26.4% | 31.6% | 47.2% | 4.4% | |||||||||||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
Cash Operating Expenses per Barrel of Oil Equivalent (Boe) | |||||||||||
(Unaudited; in thousands, except per Boe amounts) | |||||||||||
Year-To-Date (YTD) | Year Ended | ||||||||||
September 30, | December 31, | ||||||||||
2018 | 2017 | 2016 | 2015 | 2014 | |||||||
Cash Operating Expenses (GAAP)* | |||||||||||
Lease and Well | $ 936,236 | $ 1,044,847 | $ 927,452 | $ 1,182,282 | $ 1,416,413 | ||||||
Transportation Costs | 550,781 | 740,352 | 764,106 | 849,319 | 972,176 | ||||||
General and Administrative | 310,065 | 434,467 | 394,815 | 366,594 | 402,010 | ||||||
Cash Operating Expenses | 1,797,082 | 2,219,666 | 2,086,373 | 2,398,195 | 2,790,599 | ||||||
Less: Legal Settlement - Early Leasehold Termination | - | (10,202) | - | (19,355) | - | ||||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | - | ||||||
Less: Acquisition Costs - Yates Transaction | - | - | (5,100) | - | - | ||||||
Less: Joint Venture Transaction Costs | - | (3,056) | - | - | - | ||||||
Less: Joint Interest Billings Deemed Uncollectible | - | (4,528) | - | - | - | ||||||
Adjusted Cash Operating Expenses (Non-GAAP) - (a) | $ 1,797,082 | $ 2,201,880 | $ 2,039,219 | $ 2,378,840 | $ 2,790,599 | ||||||
Volume - Thousand Barrels of Oil Equivalent - (b) | 192,182 | 222,251 | 204,929 | 208,862 | 217,073 | ||||||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - (a) / (b) | $ 9.35 | $ 9.91 | (c) | $ 9.95 | (d) | $ 11.39 | (e) | $ 12.86 | (f) | ||
Adjusted Cash Operating Expenses Per Boe (Non-GAAP) - | |||||||||||
YTD 2017 compared to YTD 2016 - [(c) - (d)] / (d) | 0% | ||||||||||
YTD 2017 compared to YTD 2015 - [(c) - (e)] / (e) | -13% | ||||||||||
YTD 2017 compared to YTD 2014 - [(c) - (f)] / (f) | -23% | ||||||||||
* Includes stock compensation expense and other non-cash items. |
EOG RESOURCES, INC. | ||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||
Year Ended | ||||||||
December 31, | ||||||||
2014 | 2015 | 2016 | 2017 | |||||
Volume - Thousand Barrels of Oil Equivalent | 217,073 | 208,862 | 204,929 | 222,251 | ||||
Total Wellhead Revenues | $ 12,592,917 | $ 6,403,258 | $ 5,496,743 | $ 7,907,891 | ||||
Composite Average Wellhead Revenue per Boe | $ 58.01 | $ 30.66 | $ 26.82 | $ 35.58 | ||||
Operating Costs | ||||||||
Lease and Well | $ 1,416,413 | $ 1,182,282 | $ 927,452 | $ 1,044,847 | ||||
Transportation Costs | 972,176 | 849,319 | 764,106 | 740,352 | ||||
Gathering and Processing Costs | 145,800 | 146,156 | 122,901 | 148,775 | ||||
General and Administrative | 402,010 | 366,594 | 394,815 | 434,467 | ||||
Less: Voluntary Retirement Expense | - | - | (42,054) | - | ||||
Less: Acquisition Costs | - | - | (5,100) | - | ||||
Less: Legal Settlement - Early Leasehold Termination | - | (19,355) | - | (10,202) | ||||
Less: Joint Venture Transaction Costs | - | - | - | (3,056) | ||||
Less: Joint Interest Billings Deemed Uncollectible | - | - | - | (4,528) | ||||
General and Administrative (Non-GAAP) | 402,010 | 347,239 | 347,661 | 416,681 | ||||
Taxes Other Than Income | 757,564 | 421,744 | 349,710 | 544,662 | ||||
Interest Expense, Net | 201,458 | 237,393 | 281,681 | 274,372 | ||||
Total Cash Operating Cost (Non-GAAP) (excluding | $ 3,895,421 | $ 3,184,133 | $ 2,793,511 | $ 3,169,689 | ||||
Total Cash Operating Cost per Boe (Non-GAAP) | $ 17.95 | $ 15.25 | $ 13.64 | $ 14.25 | ||||
Composite Average Margin per Boe (Non- | $ 40.06 | $ 15.41 | $ 13.18 | $ 21.33 | ||||
Depreciation, Depletion and Amortization (DD&A) | 3,997,041 | 3,313,644 | 3,553,417 | 3,409,387 | ||||
Total Operating Cost (Non-GAAP) (excluding Exploration | $ 7,892,462 | $ 6,497,777 | $ 6,346,928 | $ 6,579,076 | ||||
Total Operating Cost per Boe (Non-GAAP) (excluding | $ 36.38 | $ 31.11 | $ 30.98 | $ 29.59 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 21.63 | $ (0.45) | $ (4.16) | $ 5.99 | ||||
Total Exploration Costs | 976,453 | 6,777,786 | 755,877 | 629,191 | ||||
Less: Impairments | (824,312) | (6,307,593) | (320,617) | (261,452) | ||||
Total Exploration Costs (Non-GAAP) | 152,141 | 470,193 | 435,260 | 367,739 | ||||
Total Operating Cost (Non-GAAP) (including Exploration | $ 8,044,603 | $ 6,967,970 | $ 6,782,188 | $ 6,946,815 | ||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 37.08 | $ 33.36 | $ 33.10 | $ 31.24 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 20.93 | $ (2.70) | $ (6.28) | $ 4.34 | ||||
EOG RESOURCES, INC. | ||||||||
Cost per Barrel of Oil Equivalent (Boe) | ||||||||
(Unaudited; in thousands, except per Boe amounts) | ||||||||
Three Months Ended | Year-To-Date | |||||||
March 31, | June 30, | September 30, | September 30, | |||||
2018 | 2018 | 2018 | 2018 | |||||
Volume - Thousand Barrels of Oil Equivalent | 59,394 | 63,898 | 68,890 | 192,182 | ||||
Total Wellhead Revenues | $ 2,622,489 | $ 2,964,727 | $ 3,320,695 | $ 8,907,911 | ||||
Composite Average Wellhead Revenue per Boe | $ 44.15 | $ 46.40 | $ 48.20 | $ 46.35 | ||||
Operating Costs | ||||||||
Lease and Well | $ 300,064 | $ 314,604 | $ 321,568 | $ 936,236 | ||||
Transportation Costs | 176,957 | 177,797 | 196,027 | 550,781 | ||||
Gathering and Processing Costs | 101,345 | 109,169 | 114,063 | 324,577 | ||||
General and Administrative | 94,698 | 104,083 | 111,284 | 310,065 | ||||
Taxes Other Than Income | 179,084 | 194,268 | 209,043 | 582,395 | ||||
Interest Expense, Net | 61,956 | 63,444 | 63,632 | 189,032 | ||||
Total Cash Operating Cost (excluding | $ 914,104 | $ 963,365 | $ 1,015,617 | $ 2,893,086 | ||||
Total Cash Operating Cost per Boe | $ 15.39 | $ 15.07 | $ 14.75 | $ 15.05 | ||||
Composite Average Margin per Boe | $ 28.76 | $ 31.33 | $ 33.45 | $ 31.30 | ||||
Depreciation, Depletion and Amortization (DD&A) | 748,591 | 848,674 | 918,180 | 2,515,445 | ||||
Total Operating Cost (excluding Exploration | $ 1,662,695 | $ 1,812,039 | $ 1,933,797 | $ 5,408,531 | ||||
Total Operating Cost per Boe (excluding | $ 27.99 | $ 28.35 | $ 28.08 | $ 28.14 | ||||
Composite Average Margin per Boe | $ 16.16 | $ 18.05 | $ 20.12 | $ 18.21 | ||||
Total Exploration Costs | 99,445 | 104,088 | 77,798 | 281,331 | ||||
Less: Impairments | (20,876) | - | - | (20,876) | ||||
Total Exploration Costs (Non-GAAP) | 78,569 | 104,088 | 77,798 | 260,455 | ||||
Total Operating Cost (Non-GAAP) (including Exploration | $ 1,741,264 | $ 1,916,127 | $ 2,011,595 | $ 5,668,986 | ||||
Total Operating Cost per Boe (Non-GAAP) (including | $ 29.31 | $ 29.98 | $ 29.21 | $ 29.50 | ||||
Composite Average Margin per Boe (Non-GAAP) | $ 14.84 | $ 16.42 | $ 18.99 | $ 16.85 |
EOG RESOURCES, INC. | |||||||||||
Fourth Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Fourth Quarter and Full Year 2018 Forecast | |||||||||||
The forecast items for the fourth quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2018 | Full Year 2018 | ||||||||||
Daily Sales Volumes | |||||||||||
Crude Oil and Condensate Volumes (MBbld) | |||||||||||
United States | 425.0 | - | 430.0 | 393.5 | - | 394.8 | |||||
Trinidad | 0.5 | - | 0.7 | 0.7 | - | 0.9 | |||||
Other International | 3.0 | - | 5.0 | 3.8 | - | 4.3 | |||||
Total | 428.5 | - | 435.7 | 398.0 | - | 400.0 | |||||
Natural Gas Liquids Volumes (MBbld) | |||||||||||
Total | 115.0 | - | 125.0 | 114.1 | - | 116.7 | |||||
Natural Gas Volumes (MMcfd) | |||||||||||
United States | 975 | - | 1,025 | 923 | - | 935 | |||||
Trinidad | 220 | - | 250 | 264 | - | 271 | |||||
Other International | 30 | - | 40 | 30 | - | 33 | |||||
Total | 1,225 | - | 1,315 | 1,217 | - | 1,239 | |||||
Crude Oil Equivalent Volumes (MBoed) | |||||||||||
United States | 702.5 | - | 725.8 | 661.5 | - | 667.3 | |||||
Trinidad | 37.2 | - | 42.4 | 44.6 | - | 46.1 | |||||
Other International | 8.0 | - | 11.7 | 8.8 | - | 9.8 | |||||
Total | 747.7 | - | 779.9 | 714.9 | - | 723.2 | |||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
4Q 2018 | Full Year 2018 | ||||||||||
Operating Costs | |||||||||||
Unit Costs ($/Boe) | |||||||||||
Lease and Well | $ | 4.45 | - | $ | 4.85 | $ | 4.80 | - | $ | 4.90 | |
Transportation Costs | $ | 2.45 | - | $ | 2.85 | $ | 2.75 | - | $ | 2.85 | |
Depreciation, Depletion and Amortization | $ | 13.60 | - | $ | 13.95 | $ | 13.23 | - | $ | 13.32 | |
Expenses ($MM) | |||||||||||
Exploration, Dry Hole and Impairment | $ | 105 | - | $ | 125 | $ | 365 | - | $ | 385 | |
General and Administrative | $ | 105 | - | $ | 115 | $ | 415 | - | $ | 425 | |
Gathering and Processing | $ | 110 | - | $ | 130 | $ | 435 | - | $ | 455 | |
Capitalized Interest | $ | 5 | - | $ | 7 | $ | 23 | - | $ | 25 | |
Net Interest | $ | 55 | - | $ | 58 | $ | 244 | - | $ | 247 | |
Taxes Other Than Income (% of Wellhead Revenue) | 6.5% | - | 6.8% | 6.5% | - | 6.7% | |||||
Income Taxes | |||||||||||
Effective Rate | 20% | - | 25% | 19% | - | 24% | |||||
Current Tax (Benefit) / Expense ($MM) | $ | (70) | - | $ | (30) | $ | (190) | - | $ | (150) | |
Capital Expenditures (Excluding Acquisitions, $MM) | |||||||||||
Exploration and Development, Excluding Facilities | $ | 4,900 | - | $ | 5,000 | ||||||
Exploration and Development Facilities | $ | 600 | - | $ | 650 | ||||||
Gathering, Processing and Other | $ | 300 | - | $ | 350 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) | |||||||||||
Crude Oil and Condensate ($/Bbl) | |||||||||||
Differentials | |||||||||||
United States - above (below) WTI | $ | 0.00 | - | $ | 2.00 | $ | 0.50 | - | $ | 1.05 | |
Trinidad - above (below) WTI | $ | (11.00) | - | $ | (9.00) | $ | (9.00) | - | $ | (8.00) | |
Other International - above (below) WTI | $ | 0.00 | - | $ | 7.00 | $ | 3.80 | - | $ | 5.60 | |
Natural Gas Liquids | |||||||||||
Realizations as % of WTI | 38% | - | 46% | 41% | - | 43% | |||||
Natural Gas ($/Mcf) | |||||||||||
Differentials | |||||||||||
United States - above (below) NYMEX Henry Hub | $ | (0.40) | - | $ | 0.00 | $ | (0.25) | - | $ | (0.15) | |
Realizations | |||||||||||
Trinidad | $ | 2.40 | - | $ | 2.80 | $ | 2.80 | - | $ | 2.90 | |
Other International | $ | 4.15 | - | $ | 4.65 | $ | 4.10 | - | $ | 4.25 | |
Definitions | |||||||||||
$/Bbl U.S. Dollars per barrel | |||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent | |||||||||||
$/Mcf U.S. Dollars per thousand cubic feet | |||||||||||
$MM U.S. Dollars in millions | |||||||||||
MBbld Thousand barrels per day | |||||||||||
MBoed Thousand barrels of oil equivalent per day | |||||||||||
MMcfd Million cubic feet per day | |||||||||||
NYMEX U.S. New York Mercantile Exchange | |||||||||||
WTI West Texas Intermediate |
View original content:http://www.prnewswire.com/news-releases/eog-resources-announces-outstanding-third-quarter-2018-results-300742708.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 20, 2018 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss third quarter 2018 results on Friday, November 2, 2018, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Events & Presentations page for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: | Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-webcast-of-third-quarter-2018-results-conference-call-for-november-2-2018-300716470.html
SOURCE EOG Resources, Inc.
DENVER, Aug. 1, 2018 /PRNewswire/ -- Regardless of whether your area of interest in the U.S. energy sector is the shale plays and companies drilling the U.S. basins, offshore drilling in the Gulf of Mexico, oil pipelines, LNG exports, Texas-sourced frac sand, oilfield services or new oilfield technologies, the 23rd annual EnerCom conference will deliver the best of the industry to the Denver Downtown Westin Hotel Denver Aug. 19-22, 2018.
The combined market value of the presenting public companies is more than $220 billion and the publicly-traded energy companies represent a combined enterprise value of more than $275 billion—55% higher than last year.
Several privately held E&Ps and related energy service companies will be at the conference in force as well this year, participating in a variety of panels at the conference. Conference attendees have a rare opportunity to hear from several large private operators who—unlike their publicly traded counterparts—often say nothing in public about their operations.
Among the private oil companies participating in the conference is Anschutz Exploration, a large operator with assets in the Powder River and Washakie Basins of Wyoming, the Piceance and DJ Basins of Colorado and the Unita Basin of Utah. Other private drillers include Permian producer Felix Energy, DJ Basin producer Great Western Oil & Gas, conventional Piceance gas producer Caerus Oil and Gas, and Powder River and Green River Basin operator Samson Resources II.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests. Buyside investors may request meetings on the conference website or contact EnerCom for more information at 303-296-8834.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
2018 Presenting Companies: The Oil & Gas Conference® 2018 presenting companies consist of the following:
Looking at basin and sector, the 2018 EnerCom conference presenting companies and companies participating in panels break out as follows (list is subject to change prior to the conference– please refer to The Oil & Gas Conference website for an updated schedule of presenting companies):
Exploration & Production and Other Energy Companies by Focus Area and Sector
Bakken/Three Forks
Eagle Ford
Permian Basin
Woodford & Other Mid-Continent – SCOOP/STACK
Marcellus/Utica
Niobrara
Gulf of Mexico/Offshore
Haynesville
Pinedale – Jonah Field – Uinta Basin
Enhanced Oil Recovery
Canadian E&Ps
International E&Ps
LNG Export Projects
Oilfield Service Companies
Midstream
Mineral, Royalty, Infrastructure Holders, Acquisition Companies
Private Companies – E&Ps, Midstream, Energy Data and Technology, Energy Capital, Government Energy Agencies
A work-in-progress schedule of the 2018 presenting companies is posted on the conference website and is regularly updated.
Sponsors of The Oil & Gas Conference®
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest independent energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates.
Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; SMBC; Opportune LLP; Petrie Partners; EnergyNet; McGriff, Seibels & Williams, Inc.; Energy Intelligence; and TGS.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
About Opportune LLP
Founded in 2005, Opportune is a leading global energy consulting firm specializing in adding value to clients across the energy industry, including upstream, midstream, downstream, power and gas, commodities trading and oilfield services.
Since we are not an audit firm, we are advocates of our clients and are not subject to the restrictions placed on other firms by regulatory bodies. Using our extensive knowledge of all sectors of the energy industry, we work with clients to provide comprehensive solutions to their operational and financial challenges.
Our practice areas include complex financial reporting, dispute resolution, enterprise risk, outsourcing, process and technology, reserve engineering and geosciences, restructuring, strategy and organization, tax, transactional due diligence and valuation. Opportune LLP is not a CPA firm.
Opportune's corporate headquarters are in Houston, Texas. The firm also has offices in Dallas, Denver, New York City, Tulsa, and the UK. For more information please call Ashley Hunt, Marketing Coordinator,
713.490.5050 and visit the web site https://opportune.com/.
About Petrie Partners, LLC
Petrie Partners, LLC is a boutique investment banking firm offering financial advisory services to the oil and gas industry. We provide specialized advice on mergers, divestitures and acquisitions and private placements.
The firm was formed in 2011 (as Strategic Energy Advisors) by senior bankers formerly with Bank of America Merrill Lynch and Petrie Parkman & Co., an investment bank that built a reputation as a most trusted advisor to energy clients during the nearly two decades leading up to its merger into Merrill Lynch in 2006.
Through tenure with Petrie Parkman, Merrill Lynch and Bank of America Merrill Lynch, the senior members of the Petrie team bring to bear an average of more than 25 years of energy investment banking experience, including over 300 energy M&A and capital raising transactions representing over $350 billion of aggregate consideration.
For information about the firm, please visit www.petrie.com or call the firm's Denver office (303.953.6768) or the Houston office (713.659.0760).
About EnergyNet
EnergyNet is the only continuous oil and gas auction and sealed bid transaction service that facilitates the sale of producing working interests (operated and non-operated), overrides, royalties, mineral interests, and non-producing leasehold. EnergyNet is a continuous oil and gas property marketplace with due diligence and bidding available 24/7/365, where auctions and sealed bid packages close weekly. Most of the properties EnergyNet sells are located in the lower 48 United States and typically range in value from $1,000 to $100,000,000.
Details about how to buy and sell oil and gas properties using the EnergyNet online auction service are available on the website at https://www.energynet.com/.
About McGriff, Seibels & Williams, Inc.
McGriff, Seibels & Williams is one of the most progressive insurance brokerage firms in the United States, leading the way with innovative programs to protect clients' financial interests. Services include construction risk, energy and marine, surety, employee benefits and financial services. McGriff's Energy & Marine Division offers specialty services for clients with worldwide operations and potentially catastrophic exposures. Our expertise in this niche industry has made us one of the largest independent energy brokers in the U.S. and one of the top five energy brokers worldwide.
Our client base includes more than 50 electric/gas utility and merchant energy companies, several coal mining companies, and more than 70 E&P companies. It also includes the Strategic Petroleum Reserve and numerous oilfield service companies, including vessel operators, offshore drilling companies, and international marine construction companies.
We will structure and implement a domestic or foreign program for virtually any type of energy-related risk. We have more than 125 professionals in our energy division. Using alternative risk transfer and traditional insurance solutions, we determine the appropriate combination of coverage and risk assumption.
Please contact the company through the website or by calling 800 476 - 2211.
About Energy Intelligence
Energy Intelligence has been a leading independent provider of objective insight, unbiased analysis and reliable data for over 60 years. With offices in New York, London, Houston, Dubai, Moscow, Washington, Singapore and Brussels, we provide decision-makers with critically important information on issues and events affecting the global energy complex.
Our benchmark Information Services, Petroleum Intelligence Weekly, Oil Daily, Natural Gas Week, World Gas Intelligence and Energy Compass, are produced by highly experienced journalists, and our research reports and advisory services are provided by highly regarded analysts and economists.
Information on Energy Intelligence is available at the company website: https://www.energyintel.com/pages/non-subscriber.aspx
About TGS
TGS was founded in Houston in 1981 and over time built the dominant 2D multi-client data library in the Gulf of Mexico. The company expanded further into North America and West Africa and added a substantial 3D portfolio in the Gulf of Mexico.
Also in 1981, NOPEC was founded in Oslo and began building an industry-leading multi-client 2D database in the North Sea, with additional operations in Australia and the Far East. In 1997, NOPEC went public on the Oslo Stock Exchange. In 1998, the companies merged to form TGS-NOPEC Geophysical Company (TGS), creating a winning combination for investors, customers and employees. Since then, TGS has set the standard for geoscientific data around the world.
Additional information is available at the company website: http://www.tgs.com/about-tgs/company-history/ .
View original content:http://www.prnewswire.com/news-releases/90-public-and-private-oil-and-gas-company-leaders-and-experts-to-speak-at-the-23rd-annual-enercom---the-oil--gas-conference-300689920.html
SOURCE EnerCom, Inc.
The Oil & Gas Conference® 2018 presenting companies:
- 40 North American shale E&Ps
- 7 international E&Ps
- 10 other producers
- 9 oilfield service providers
- 9 private E&Ps, midstream and data providers
- $202 billion in market value
- 3.2 million barrels of oil equivalent production per day
- $251 billion in enterprise value
DENVER, July 12, 2018 /PRNewswire/ -- An impressive roster of publicly traded oil and gas company senior leadership teams will be telling their companies' stories and presenting operational and financial updates to investors at the 2018 edition of EnerCom's The Oil & Gas Conference®.
CEOs across the upstream and oilfield service spectrum will be at the Denver Downtown Westin Hotel Aug. 20-23, 2018 to make financial presentations and meet with buyside investors and analysts for the 2018 EnerCom conference.
Market Cap: The presenting North American shale E&Ps, other explorers and producers, international E&Ps, and global oilfield service companies represent a combined market value of $202 billion, 71% higher than last year.
Enterprise Value: The 2018 presenting companies represent a combined enterprise value of $251 billion—53% higher than last year.
Production: EnerCom conference E&Ps are producing more than 3.2 million barrels of oil per day, slightly more than last year.
As to basin and sector, the 2018 EnerCom conference presenting companies break out as follows (list is subject to change prior to conference– please refer to The Oil & Gas Conference website for an updated schedule of presenting companies):
Exploration & Production Companies by Focus Area
Bakken/Three Forks
Eagle Ford
Permian Basin
Woodford & Other Mid-Continent – SCOOP/STACK
Marcellus/Utica
Niobrara
Gulf of Mexico/Offshore
Haynesville
Pinedale – Jonah Field – Uinta Basin
Enhanced Oil Recovery
Canadian E&Ps
International E&Ps
Oilfield Service Companies
Mineral, Royalty, Infrastructure Holders
Private Companies – E&Ps, Midstream, Energy Data and Technology Providers
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America, Europe, and Australasia.
A work-in-progress schedule of the 2018 presenting companies is posted on the conference website and will be regularly updated.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests. Buyside investors may request meetings on the conference website or contact EnerCom for more information at 303-296-8834.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; SMBC; and Opportune LLP.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
About Opportune LLP
Founded in 2005, Opportune is a leading global energy consulting firm specializing in adding value to clients across the energy industry, including upstream, midstream, downstream, power and gas, commodities trading and oilfield services.
Since we are not an audit firm, we are advocates of our clients and are not subject to the restrictions placed on other firms by regulatory bodies. Using our extensive knowledge of all sectors of the energy industry, we work with clients to provide comprehensive solutions to their operational and financial challenges.
Our practice areas include complex financial reporting, dispute resolution, enterprise risk, outsourcing, process and technology, reserve engineering and geosciences, restructuring, strategy and organization, tax, transactional due diligence and valuation. Opportune LLP is not a CPA firm.
Opportune's corporate headquarters are in Houston, Texas. The firm also has offices in Dallas, Denver, New York City, Tulsa, and the UK. For more information please call Ashley Hunt, Marketing Coordinator, 713.490.5050, and visit the web site https://opportune.com/.
View original content:http://www.prnewswire.com/news-releases/251-billion-in-public-oil--gas-companies-will-be-in-denver-for-the-23rd-annual-enercom-conference-300680266.html
SOURCE EnerCom, Inc.
DENVER, June 20, 2018 /PRNewswire/ -- EnerCom, Inc. is pleased to update the list of oil and gas companies and energy sector experts who will be presenters at the 23rd annual edition of The Oil & Gas Conference®, coming August 19-22, 2018, to the Westin Denver Downtown.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa. A work-in-progress list of the 2018 presenting companies will be posted and updated on the conference website.
The EnerCom Denver 2018 presenting companies include but are not limited to:
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; and SMBC.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE. We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
CONTACT: 303-296-8834
View original content:http://www.prnewswire.com/news-releases/enercom-announces-presenting-companies-for-the-oil--gas-conference-23-300669633.html
SOURCE EnerCom, Inc.
DENVER, June 13, 2018 /PRNewswire/ -- EnerCom, Inc. is pleased to update the list of oil and gas companies and energy sector experts who will be presenters at the 23rd annual edition of The Oil & Gas Conference®, coming August 19-22, 2018, to the Westin Denver Downtown.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa. A work-in-progress list of the 2018 presenting companies will be posted and updated on the conference website.
The EnerCom Denver 2018 presenting companies include but are not limited to:
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; and SMBC.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Feb. 27-28, 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
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SOURCE EnerCom, Inc.
DENVER, June 5, 2018 /PRNewswire/ -- EnerCom, Inc. is pleased to update the list of presenting oil and gas companies for the 23rd annual edition of The Oil & Gas Conference®, coming August 19-22, 2018, at the Westin Denver Downtown. Investment and oil and gas professionals may register for the event now through the conference website.
Conference Details: The Oil & Gas Conference® 23 offers investment professionals the opportunity to listen to senior management teams in the oil and gas industry present operational and financial strategies and learn about important energy topics affecting the global oil and gas industry. The forum fosters healthy dialogue and informal networking opportunities for attendees.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa. A work-in-progress list of the 2018 presenting companies will be posted and updated on the conference website.
The EnerCom Denver 2018 presenting companies include but are not limited to:
Additional Speakers: Global energy industry leaders, economists, market strategists, government officials and other energy experts will provide their insights on topics such as global commodities markets, the U.S. becoming a net energy exporter, and capital sources for energy development.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; and SMBC.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Q1 - 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group ( NYSE : SMFG ) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
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SOURCE EnerCom, Inc.
DENVER, May 23, 2018 /PRNewswire/ -- EnerCom, Inc. is pleased to update the list of presenting oil and gas companies for the 23rd annual edition of its popular The Oil & Gas Conference®, coming this August to Denver, Colo.
This year's oil and gas investment conference will be held August 19-22, 2018, at the Westin Denver Downtown. Investment and oil and gas professionals may register for the event through the conference website.
Conference Details: The Oil & Gas Conference® 23 offers investment professionals the opportunity to listen to senior management teams in the oil and gas industry present operational and financial strategies and learn about important energy topics affecting the global oil and gas industry. The forum fosters healthy dialogue and informal networking opportunities for attendees.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa. A work-in-progress list of the 2018 presenting companies will be posted and updated on the conference website.
The EnerCom Denver 2018 presenting companies include but are not limited to:
Additional Speakers: Global energy industry leaders, economists, market strategists, government officials and other energy experts will provide their insights on topics such as global commodities markets, the U.S. becoming a net energy exporter, and capital sources for energy development.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; AssuredPartners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; Credit Agricole CIB; Natixis; PJ SOLOMON; PNC Financial Services Group; Wells Fargo; MUFG; and SMBC.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized oil and gas-focused investor relations consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor communications, media relations and providing visual communications design.
EnerCom offers services and produces and publishes numerous data products and external communications tools for public and private energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Q1 - 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA
joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home.
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on Assured Partners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
About Natixis
Natixis is the international corporate and investment banking, asset management, insurance and financial services arm of Groupe BPCE, the second-largest banking group in France.
Natixis Corporate & Investment Banking advises and assists corporations, financial institutions, institutional investors, financial sponsors, public-sector organizations and the networks of Groupe BPCE.
We furnish a diversified array of financing solutions, provide access to capital markets and transaction banking services.
Areas of expertise include Advisory: M&A, primary equity, capital & rating advisory; Financing: vanilla and structured; Capital Markets: equities, fixed income, credit, forex and commodities; Global Transaction Banking: trade finance, cash management, liquidity management and correspondent banking; Research: economic, credit, equity and quantitative.
The Bank leverages the expertise and highly technical skills of its teams, and provides industry-recognized research to build innovative and mix-and-matchable solutions. Corporate and Investment Banking is present on the main financial markets via three international platforms: Americas, Asia-Pacific, and EMEA (Europe, Middle East, Africa).
About PJ SOLOMON
PJ SOLOMON is an investment banking advisory firm that provides strategic advisory services to chief executive officers and senior management, owners of public and private companies, boards of directors, and special committees.
Our full suite of advisory services includes Mergers and Acquisitions, Restructuring and Capital Markets across a range of industry verticals.
The PJ SOLOMON Energy Advisory Group provides strategic investment banking advisory services to public and private clients across the energy chain. Drawing upon our extensive sector relationships and deep strategic and operational expertise, we can offer a unique and valued advisory platform for the upstream, upstream A&D, midstream and the utility sectors.
Based in our Houston office, the PJ SOLOMON Energy team holds more than 100 years of experience on a broad range of domestic and cross-border transactions including mergers and acquisitions, A&D, restructurings, bankruptcies, and public and private capital raisings.
Industry sectors/sub-sectors include: Upstream, Upstream A&D, Midstream, Energy related and Utilities.
About PNC Financial Services Group
PNC is one of the largest, best-regarded and best-capitalized financial services companies in the country, with approximately $325 billion in assets and offices in 33 states, Canada and the United Kingdom.
PNC's Energy Group, headed by Tom Byargeon, is a significant capital and service provider to energy companies, with approximately $6.5 billion in commitments to the industry. The Energy office in Houston houses a team with extensive experience and deep relationships across the entire energy supply chain. This group also offers strategic corporate finance advice and delivers PNC's comprehensive set of solutions and capabilities, including commodity and interest rate hedging, debt capital markets, loan syndications, treasury management, asset securitization, equipment finance and institutional investments.
For more information, please contact Tom Byargeon at 713-353-8782 or tom.byargeon@pnc.com. You can also visit www.pnc.com.
About MUFG
Mitsubishi UFJ Financial Group (MUFG) has been a leading provider of banking services to the oil and gas industry in the Americas for more than 30 years, consistently ranking in the Top 10 Lead Arrangers and Top 10 Bond Arrangers in the Thomson Reuters Oil and Gas League Tables.
We support clients across the industry—from regional exploration and production to global diversified services companies—that benefit from our focused approach, strong execution, and customized services. Whether you are looking to expand existing reserves, make an acquisition, or streamline operations, we can support your growth with services, including: underwriting and syndications; U.S./Canadian cross-border funding; securities underwriting and placements; leasing and tax equity financing; and commodities, interest rate, and foreign exchange risk management.
For more information, visit: www.mufgamericas.com/oil-gas.
About Wells Fargo & Company
Wells Fargo & Company is a nationwide, diversified, community-based financial services company providing banking, insurance, investments, mortgage, and consumer and commercial finance through more than 8,700 locations, 12,500 ATMs, and the internet (wellsfargo.com) and mobile banking, and has offices in 36 countries to support customers who conduct business in the global economy.
The Energy Banking Group, headed by Bart Schouest, provides corporate banking products and services to the energy sector, including upstream, midstream, oilfield services, and diversified industries. With offices in Houston, Dallas, Denver, Calgary, and Aberdeen the group's success is driven by in-depth industry expertise and longstanding relationships with key industry participants. The group has over $45 billion of credit commitments to public and private companies across the upstream, midstream, downstream, services, and power and utilities sectors.
The Energy & Power Investment Banking Group, headed by James Kipp, provides strategic advisory and corporate finance expertise to energy and power clients, including upstream, midstream, oilfield services, downstream, coal and the power & utilities sectors. Areas of focus include equity, equity-linked and debt underwritings, private placements, syndications, and mergers and acquisitions. The Energy & Power Investment Banking Group has offices in Houston and Charlotte.
These teams work together to offer clients industry and product expertise, in addition to sharing their understanding of internal and external forces that drive both industry trends and financial markets. For additional information, contact us at 713-319-1350 or Energy@wellsfargo.com.
To learn more about Wells Fargo & Company, please visit the company's web site at www.wellsfargo.com.
About SMBC
Sumitomo Mitsui Banking Corporation (SMBC) is a core member of Sumitomo Mitsui Financial Group (SMFG), a Tokyo-based bank holding company that is ranked among the largest 25 banks globally by assets under management.
SMBC Americas Division, with more than 2,500 employees, oversees operations in the U.S., Canada, Mexico, and South America. We work across SMFG to offer corporate and institutional clients sophisticated and comprehensive financial services around the globe.
SMBC's roots in Japan trace back more than 400 years to 1590. The Americas Division of SMBC has more than a century of experience in the United States, beginning when the San Francisco branch of Sumitomo Bank was established in 1919. Sumitomo Mitsui Financial Group (NYSE: SMFG) was listed on the New York Stock Exchange in 2010.
For more information please visit the corporate website: www.smbcgroup.com/americas/group-companies/
View original content:http://www.prnewswire.com/news-releases/enercom-adds-presenting-companies-to-its-23rd-annual---the-oil--gas-conference-roster-300653627.html
SOURCE EnerCom, Inc.
HOUSTON, May 8, 2018 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the UBS Global Oil and Gas Conference at 8:00 a.m. Central time on Wednesday, May 23. David W. Trice, Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the Bernstein Strategic Decisions Conference at 7:00 a.m. Central time (8:00 a.m. Eastern time) on Wednesday, May 30. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG.
Please visit the Investors/Overview page on the EOG website to access the live webcasts. If you are unable to listen live, replays will be available on the Investors/Presentations and Events page for six months.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-conferences-300644899.html
SOURCE EOG Resources, Inc.
HOUSTON, May 3, 2018 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first quarter 2018 net income of $638.6 million, or $1.10 per share. This compares to first quarter 2017 net income of $28.5 million, or $0.05 per share.
Adjusted non-GAAP net income for the first quarter 2018 was $689.5 million, or $1.19 per share, compared to adjusted non-GAAP net income of $89.4 million, or $0.15 per share, for the same prior year period. Higher commodity prices, increased production volumes and overall per-unit cost reductions resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2018 compared to the first quarter 2017. Adjusted non-GAAP net income is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude one-time items. Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.
Operational Highlights
EOG achieved record returns on new capital investments in the first quarter 2018. The company increased first quarter 2018 crude oil production by 15 percent compared to the first quarter 2017. EOG maintained its forecast for 16 to 20 percent crude oil growth for full year 2018. Strong production growth reflects the company's premium drilling strategy and technical advances across its diverse inventory of high-return plays. EOG defines premium drilling as prospective well locations that will earn a minimum 30 percent direct after-tax rate of return at $40 crude oil and $2.50 natural gas prices. EOG's prolific Delaware Basin, Eagle Ford and Powder River Basin assets all contributed to growth this quarter. The company realized an average price for U.S. crude oil sales in the first quarter 2018 of $64.24 per barrel. This is $1.35 per barrel above the average WTI NYMEX price during the same period.
Overall per-unit operating expenses decreased during the first quarter 2018. This performance was led by a 21 percent reduction in per-unit depreciation, depletion and amortization (DD&A) expenses compared to the same prior year period. Per-unit transportation and general and administrative costs also declined during the first quarter 2018.
EOG maintained its forecast for 2018 capital expenditures of $5.4 to $5.8 billion, excluding acquisitions and non-cash transactions. The company remains on track to reduce average well costs by five percent in 2018.
"EOG delivered another sterling performance in the first quarter despite a challenging operating environment," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "New capital investments produced record-level rates of return. Our innovative employees executed our game plan with high efficiency to deliver results that met or exceeded expectations while remaining on track to lower costs. EOG is well positioned to accomplish its full-year plan and generate high-return, disciplined growth in 2018."
Capital Structure and Financial Strategy
At March 31, 2018, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the first quarter, EOG's net debt was $5.6 billion for a net debt-to-total capitalization ratio of 25 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
EOG intends to repay bonds as they mature over the next four years, with a goal to reduce total debt outstanding by $3 billion. In addition, the company is targeting an increase in its historical rate of dividend growth. Sustainable dividend growth is a distinguishing attribute of EOG. The company increased its dividend at a 19 percent compound annual rate from 1999 to 2017 without any reductions. The shift to premium drilling and the recovery in oil prices have increased EOG's after-tax rate of return on new investments to record levels. With an improving financial condition, EOG now aims to grow its dividend at a higher rate than its historical average.
"EOG is uniquely positioned to generate strong organic growth, increase return on capital employed, further strengthen the balance sheet and step up cash returns to shareholders," noted Thomas. "Our objectives to reduce debt outstanding and increase the dividend growth rate reflect the strength of our business model. The company is capable of withstanding price volatility and well positioned to create significant shareholder value through commodity cycles."
Delaware Basin
In the first quarter 2018, EOG shifted to larger-scale development activity in the Delaware Basin utilizing 19 rigs compared to 13 rigs in 2017. Seventy new wells began production across multiple targets, although only 14 of these were brought on-line in January. Activity was focused on further delineating additional targets and testing development patterns in different areas of the basin.
In the Delaware Basin Wolfcamp, EOG completed several notable wells, including the State Magellan 7 22H-28H. This seven-well package, drilled on 500-foot spacing, was completed with an average treated lateral length of 4,700 feet per well and average 30-day initial production rates per well of 2,200 barrels of oil equivalent per day (Boed), or 1,455 barrels of oil per day (Bopd), 310 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.6 million cubic feet per day (MMcfd) of natural gas.
In the Delaware Basin First Bone Spring, EOG completed the Beowulf 33 State Com 301H in Lea County, NM with a treated lateral length of 6,900 feet and a 30-day initial production rate of 1,735 Boed, or 1,275 Bopd, 200 Bpd of NGLs and 1.6 MMcfd of natural gas.
In the Delaware Basin Leonard, EOG completed the Gem 36 State Com 05H and 06H with an average treated lateral length per well of 4,200 feet and average 30-day initial production rates per well of 2,555 Boed, or 1,605 Bopd, 395 Bpd of NGLs and 3.3 MMcfd of natural gas.
South Texas Eagle Ford and Austin Chalk
EOG's South Texas Eagle Ford continued to generate strong results across the entire extent of its 520,000 net acre position in the crude oil window of the play. EOG continues to optimize its wells with staggered patterns and enhanced targeting, which is producing premium-level returns even in heavily developed parts of the field. Wells completed in the first quarter were drilled with an average distance between wells of approximately 300 feet per well. Lateral lengths are also being extended, primarily in the western half of the field, where lateral lengths averaged 9,200 feet per well in the first quarter.
Notable wells in the first quarter included the Presley Unit 12H-14H, a three-well package in Karnes County, TX with an average treated lateral length of 6,800 feet per well and average 30-day initial production rates per well of 3,360 Boed, or 2,670 Bopd, 350 Bpd of NGLs and 2.0 MMcfd of natural gas. On the western side of the Eagle Ford in Atascosa County, TX, EOG completed the Watermelon Unit 2H and 3H with an average treated lateral length of 12,400 feet per well and average 30-day initial production rates per well of 1,680 Boed, or 1,490 Bopd, 100 Bpd of NGLs and 0.6 MMcfd of natural gas.
Development continued in the Austin Chalk, with the first quarter drilling program highlighted by the Elbrus 101H and 102H, with an average treated lateral length of 4,600 feet per well and average 30-day initial production rates per well of 4,305 Boed, or 2,980 Bopd, 670 Bpd of NGLs and 3.9 MMcfd of natural gas.
Rockies and the Bakken
During the first quarter, EOG continued to develop its premium Powder River Basin and DJ Basin positions and began its 2018 drilling program in the Bakken. The company continued to lower well costs in its Rockies plays by improving drilling and completion times along with other efficiency improvements.
EOG brought 12 wells on line in the Powder River Basin during the first quarter 2018, including nine targeting the Turner formation. Notably, the Flatbow 16-36H–18-36H, a three-well package in the Powder River Turner, was completed with an average treated lateral length of 3,900 feet per well and average 30-day initial production rates per well of 1,325 Boed, or 775 Bopd, 190 Bpd of NGLs and 2.2 MMcfd of natural gas. These short-lateral wells had an average cost of $2.9 million per well.
In the DJ Basin, EOG began production in the first quarter from 12 wells. In particular, a four-well package of DJ Basin Codell wells, the Big Sandy 529, 552, 553 and 554-1423H, was completed with an average treated lateral length of 9,500 feet per well and average 30-day initial production rates per well of 1,340 Boed, or 1,120 Bopd, 135 Bpd of NGLs and 0.5 MMcfd of natural gas. These wells were drilled in an average of 4.2 days per well with an average cost of $3.5 million per well.
In the North Dakota Bakken, EOG drilled 4 wells in the first quarter and deferred completions until later in 2018.
Woodford Oil Window
EOG continued development of its new oil play in the Woodford formation of the Eastern Anadarko Basin. In the first quarter, EOG increased drilling operations to three rigs and added a fourth rig in April. Production began from one well during the quarter. The Terri 1621 #1H was completed with a treated lateral length of 10,200 feet and a 30-day initial production rate of 1,395 Boed, or 1,140 Bopd, 165 Bpd of NGLs and 0.5 MMcfd of natural gas.
Hedging Activity
During the first quarter ended March 31, 2018, EOG entered into crude oil financial price swap contracts. A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Conference Call May 4, 2018
EOG's first quarter 2018 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, May 4, 2018. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website for one year.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows, pay down indebtedness or pay and/or increase dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG's actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | |||||
Financial Report | |||||
(Unaudited; in millions, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2018 |
2017 | ||||
Operating Revenues and Other |
$ |
3,681.2 |
$ |
2,610.6 | |
Net Income |
$ |
638.6 |
$ |
28.5 | |
Net Income Per Share |
|||||
Basic |
$ |
1.11 |
$ |
0.05 | |
Diluted |
$ |
1.10 |
$ |
0.05 | |
Average Number of Common Shares |
|||||
Basic |
575.8 |
573.9 | |||
Diluted |
579.7 |
578.6 | |||
Summary Income Statements | |||||
(Unaudited; in thousands, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2018 |
2017 | ||||
Operating Revenues and Other |
|||||
Crude Oil and Condensate |
$ |
2,101,308 |
$ |
1,430,061 | |
Natural Gas Liquids |
221,415 |
153,444 | |||
Natural Gas |
299,766 |
230,602 | |||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts |
(59,771) |
62,020 | |||
Gathering, Processing and Marketing |
1,101,822 |
726,537 | |||
Losses on Asset Dispositions, Net |
(14,969) |
(16,758) | |||
Other, Net |
31,591 |
24,659 | |||
Total |
3,681,162 |
2,610,565 | |||
Operating Expenses |
|||||
Lease and Well |
300,064 |
255,777 | |||
Transportation Costs |
176,957 |
178,714 | |||
Gathering and Processing Costs |
101,345 |
38,144 | |||
Exploration Costs |
34,836 |
56,894 | |||
Impairments |
64,609 |
193,187 | |||
Marketing Costs |
1,106,390 |
736,536 | |||
Depreciation, Depletion and Amortization |
748,591 |
816,036 | |||
General and Administrative |
94,698 |
97,238 | |||
Taxes Other Than Income |
179,084 |
130,293 | |||
Total |
2,806,574 |
2,502,819 | |||
Operating Income |
874,588 |
107,746 | |||
Other Income, Net |
727 |
3,151 | |||
Income Before Interest Expense and Income Taxes |
875,315 |
110,897 | |||
Interest Expense, Net |
61,956 |
71,515 | |||
Income Before Income Taxes |
813,359 |
39,382 | |||
Income Tax Provision |
174,770 |
10,865 | |||
Net Income |
$ |
638,589 |
$ |
28,517 | |
Dividends Declared per Common Share |
$ |
0.1850 |
$ |
0.1675 |
EOG RESOURCES, INC. | |||||
Operating Highlights | |||||
(Unaudited) | |||||
Three Months Ended | |||||
March 31, | |||||
2018 |
2017 | ||||
Wellhead Volumes and Prices |
|||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||
United States |
359.7 |
312.5 | |||
Trinidad |
0.9 |
0.8 | |||
Other International (B) |
2.7 |
2.4 | |||
Total |
363.3 |
315.7 | |||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||
United States |
$ |
64.24 |
$ |
50.38 | |
Trinidad |
54.86 |
41.56 | |||
Other International (B) |
71.61 |
47.77 | |||
Composite |
64.27 |
50.34 | |||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||
United States |
100.6 |
78.8 | |||
Other International (B) |
- |
- | |||
Total |
100.6 |
78.8 | |||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||
United States |
$ |
24.46 |
$ |
21.63 | |
Other International (B) |
- |
- | |||
Composite |
24.46 |
21.63 | |||
Natural Gas Volumes (MMcfd) (A) |
|||||
United States |
853 |
728 | |||
Trinidad |
293 |
308 | |||
Other International (B) |
30 |
22 | |||
Total |
1,176 |
1,058 | |||
Average Natural Gas Prices ($/Mcf) (C) |
|||||
United States |
$ |
2.76 |
$ |
2.32 | |
Trinidad |
2.88 |
2.57 | |||
Other International (B) |
4.36 |
3.76 | |||
Composite |
2.83 |
(D) |
2.42 | ||
Crude Oil Equivalent Volumes (MBoed) (E) |
|||||
United States |
602.5 |
512.6 | |||
Trinidad |
49.8 |
52.2 | |||
Other International (B) |
7.6 |
5.9 | |||
Total |
659.9 |
570.7 | |||
Total MMBoe (E) |
59.4 |
51.4 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | ||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. | ||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to the Condensed Consolidated Financial Statements on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2018). | ||||||
(D) Includes a positive revenue adjustment of $0.41 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Condensed Consolidated Financial Statements on EOG's Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2018). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees for certain processing and marketing agreements as Gathering and Processing Costs, instead of a deduction to Natural Gas Revenues. | ||||||
(E) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
March 31, |
December 31, | ||||
2018 |
2017 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
816,094 |
$ |
834,228 | |
Accounts Receivable, Net |
1,702,100 |
1,597,494 | |||
Inventories |
584,729 |
483,865 | |||
Assets from Price Risk Management Activities |
761 |
7,699 | |||
Income Taxes Receivable |
262,789 |
113,357 | |||
Other |
218,624 |
242,465 | |||
Total |
3,585,097 |
3,279,108 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
53,854,438 |
52,555,741 | |||
Other Property, Plant and Equipment |
4,082,781 |
3,960,759 | |||
Total Property, Plant and Equipment |
57,937,219 |
56,516,500 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(31,561,571) |
(30,851,463) | |||
Total Property, Plant and Equipment, Net |
26,375,648 |
25,665,037 | |||
Deferred Income Taxes |
18,182 |
17,506 | |||
Other Assets |
761,590 |
871,427 | |||
Total Assets |
$ |
30,740,517 |
$ |
29,833,078 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,915,651 |
$ |
1,847,131 | |
Accrued Taxes Payable |
179,646 |
148,874 | |||
Dividends Payable |
106,521 |
96,410 | |||
Liabilities from Price Risk Management Activities |
84,128 |
50,429 | |||
Current Portion of Long-Term Debt |
363,155 |
356,235 | |||
Other |
187,657 |
226,463 | |||
Total |
2,836,758 |
2,725,542 | |||
Long-Term Debt |
6,071,604 |
6,030,836 | |||
Other Liabilities |
1,301,938 |
1,275,213 | |||
Deferred Income Taxes |
3,689,578 |
3,518,214 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and |
205,793 |
205,788 | |||
Additional Paid in Capital |
5,569,194 |
5,536,547 | |||
Accumulated Other Comprehensive Loss |
(14,289) |
(19,297) | |||
Retained Earnings |
11,125,051 |
10,593,533 | |||
Common Stock Held in Treasury, 459,990 Shares at March 31, 2018 and 350,961 Shares at December 31, 2017 |
(45,110) |
(33,298) | |||
Total Stockholders' Equity |
16,840,639 |
16,283,273 | |||
Total Liabilities and Stockholders' Equity |
$ |
30,740,517 |
$ |
29,833,078 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Three Months Ended | |||||
March 31, | |||||
2018 |
2017 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income to Net Cash Provided by Operating Activities: |
|||||
Net Income |
$ |
638,589 |
$ |
28,517 | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
748,591 |
816,036 | |||
Impairments |
64,609 |
193,187 | |||
Stock-Based Compensation Expenses |
35,486 |
30,460 | |||
Deferred Income Taxes |
171,362 |
694 | |||
Losses on Asset Dispositions, Net |
14,969 |
16,758 | |||
Other, Net |
2,013 |
(3,052) | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
59,771 |
(62,020) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
(21,965) |
1,912 | |||
Other, Net |
(478) |
(428) | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(109,654) |
28,688 | |||
Inventories |
(106,799) |
24,736 | |||
Accounts Payable |
53,652 |
20,426 | |||
Accrued Taxes Payable |
21,950 |
(38,613) | |||
Other Assets |
(8,863) |
(44,677) | |||
Other Liabilities |
(29,055) |
(51,251) | |||
Changes in Components of Working Capital Associated with Investing and Financing |
17,988 |
(63,324) | |||
Net Cash Provided by Operating Activities |
1,552,166 |
898,049 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(1,365,111) |
(912,227) | |||
Additions to Other Property, Plant and Equipment |
(76,100) |
(34,336) | |||
Proceeds from Sales of Assets |
2,829 |
46,812 | |||
Changes in Components of Working Capital Associated with Investing Activities |
(18,045) |
63,324 | |||
Net Cash Used in Investing Activities |
(1,456,427) |
(836,427) | |||
Financing Cash Flows |
|||||
Dividends Paid |
(97,026) |
(96,707) | |||
Treasury Stock Purchased |
(16,776) |
(18,628) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
1,453 |
2,356 | |||
Repayment of Capital Lease Obligation |
(1,671) |
(1,619) | |||
Changes in Working Capital Associated with Financing Activities |
57 |
- | |||
Net Cash Used in Financing Activities |
(113,963) |
(114,598) | |||
Effect of Exchange Rate Changes on Cash |
90 |
(353) | |||
Decrease in Cash and Cash Equivalents |
(18,134) |
(53,329) | |||
Cash and Cash Equivalents at Beginning of Period |
834,228 |
1,599,895 | |||
Cash and Cash Equivalents at End of Period |
$ |
816,094 |
$ |
1,546,566 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Non-GAAP) | |||||||||||||||
To Net Income (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month periods ended March 31, 2018 and 2017 reported Net Income (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2018 and 2017, to add back impairment charges related to certain of EOG's assets in 2018 and 2017 and to eliminate certain adjustments in 2018 related to the 2017 U.S. tax reform. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
March 31, 2018 |
March 31, 2017 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (GAAP) |
$813,359 |
$(174,770) |
$638,589 |
$ 1.10 |
$ 39,382 |
$(10,865) |
$28,517 |
$ 0.05 | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
59,771 |
(13,166) |
46,605 |
0.08 |
(62,020) |
22,191 |
(39,829) |
(0.07) | |||||||
Net Cash Received from (Payments for) |
(21,965) |
4,838 |
(17,127) |
(0.03) |
1,912 |
(684) |
1,228 |
- | |||||||
Add: Net Losses on Asset Dispositions |
14,969 |
(3,324) |
11,645 |
0.02 |
16,758 |
(5,736) |
11,022 |
0.02 | |||||||
Add: Impairments |
20,876 |
(4,598) |
16,278 |
0.03 |
137,751 |
(49,287) |
88,464 |
0.15 | |||||||
Less: Tax Reform Impact |
- |
(6,524) |
(6,524) |
(0.01) |
- |
- |
- |
- | |||||||
Adjustments to Net Income |
73,651 |
(22,774) |
50,877 |
0.09 |
94,401 |
(33,516) |
60,885 |
0.10 | |||||||
Adjusted Net Income (Non-GAAP) |
$887,010 |
$(197,544) |
$689,466 |
$ 1.19 |
$133,783 |
$(44,381) |
$89,402 |
$ 0.15 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
575,775 |
573,935 | |||||||||||||
Diluted |
579,726 |
578,593 |
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||
(Unaudited; in thousands) | ||||||
Calculation of Free Cash Flow (Non-GAAP) | ||||||
(Unaudited; in thousands) | ||||||
The following chart reconciles the three-month periods ended March 31, 2018 and 2017 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Other Non-Current Income Taxes - Net Receivable,Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the three months ended March 31, 2018. EOG management uses this information for comparative purposes within the industry. | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2018 |
2017 | |||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,552,166 |
$ |
898,049 | ||
Adjustments: |
||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
27,936 |
50,734 | ||||
Other Non-Current Income Taxes - Net Receivable |
118,921 |
- | ||||
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||
Accounts Receivable |
109,654 |
(28,688) | ||||
Inventories |
106,799 |
(24,736) | ||||
Accounts Payable |
(53,652) |
(20,426) | ||||
Accrued Taxes Payable |
(21,950) |
38,613 | ||||
Other Assets |
8,863 |
44,677 | ||||
Other Liabilities |
29,055 |
51,251 | ||||
Changes in Components of Working Capital Associated with |
||||||
Investing and Financing Activities |
(17,988) |
63,324 | ||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,859,804 |
$ |
1,072,798 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
73% |
|||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,859,804 |
||||
Less: |
||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) |
(1,477,830) |
|||||
Dividends Paid (GAAP) |
(97,026) |
|||||
Free Cash Flow (Non-GAAP) |
$ |
284,948 |
||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the three months ended March 31, 2018: | ||||||
Total Expenditures (GAAP) |
$ |
1,546,641 |
||||
Less: |
||||||
Asset Retirement Costs |
(12,100) |
|||||
Non-Cash Acquisition Costs of Other Property, Plant and Equipment |
(47,635) |
|||||
Non-Cash Acquisition Costs of Unproved Properties |
(8,809) |
|||||
Acquisition Costs of Proved Properties |
(267) |
|||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) |
$ |
1,477,830 |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | |||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||
(Non-GAAP) to Net Income (GAAP) | |||||
(Unaudited; in thousands) | |||||
The following chart adjusts the three-month periods ended March 31, 2018 and 2017 reported Net Income (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||
Three Months Ended | |||||
March 31, | |||||
2018 |
2017 | ||||
Net Income (GAAP) |
$ |
638,589 |
$ |
28,517 | |
Adjustments: |
|||||
Interest Expense, Net |
61,956 |
71,515 | |||
Income Tax Provision |
174,770 |
10,865 | |||
Depreciation, Depletion and Amortization |
748,591 |
816,036 | |||
Exploration Costs |
34,836 |
56,894 | |||
Impairments |
64,609 |
193,187 | |||
EBITDAX (Non-GAAP) |
1,723,351 |
1,177,014 | |||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
59,771 |
(62,020) | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
(21,965) |
1,912 | |||
Losses on Asset Dispositions, Net |
14,969 |
16,758 | |||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,776,126 |
$ |
1,133,664 | |
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
57% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
March 31, |
December 31, | ||||
2018 |
2017 | ||||
Total Stockholders' Equity - (a) |
$ |
16,841 |
$ |
16,283 | |
Current and Long-Term Debt (GAAP) - (b) |
6,435 |
6,387 | |||
Less: Cash |
(816) |
(834) | |||
Net Debt (Non-GAAP) - (c) |
5,619 |
5,553 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
23,276 |
$ |
22,670 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
22,460 |
$ |
21,836 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
28% |
28% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25% |
25% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through April 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through May 31, 2018 (closed) |
15,000 |
$ 1.063 | |||||||||
June 1, 2018 through December 31, 2018 |
15,000 |
1.063 | |||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 |
20,000 |
$ 1.075 | |||||||||
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through April 26, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through May 31, 2018 (closed) |
37,000 |
$ 3.818 | |||||||||
June 1, 2018 through December 31, 2018 |
37,000 |
3.818 | |||||||||
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through April 26, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through March 31, 2018 (closed) |
134,000 |
$ 60.04 | |||||||||
April 1, 2018 through December 31, 2018 |
134,000 |
60.04 | |||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through April 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2018 |
|||||||||||
March 1, 2018 through May 31, 2018 (closed) |
35,000 |
$ 3.00 | |||||||||
June 1, 2018 through November 30, 2018 |
35,000 |
3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. | |||||||||||
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through April 26, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2018 |
|||||||||||
March 1, 2018 through May 31, 2018 (closed) |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
June 1, 2018 through November 30, 2018 |
120,000 |
3.38 |
96,000 |
2.94 | |||||||
Definitions |
|||||||||||
Bbld |
Barrels per day | ||||||||||
$/Bbl |
Dollars per barrel | ||||||||||
MMBtud |
Million British thermal units per day | ||||||||||
$/MMBtu |
Dollars per million British thermal units | ||||||||||
NYMEX |
U.S. New York Mercantile Exchange | ||||||||||
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | ||||||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | ||||||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | ||||||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||||
2017 |
2016 |
2015 |
2014 |
2013 | ||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
||||||
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
||||||
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
(1,934) |
(a) |
204 |
(b) |
4,559 |
(c) |
(199) |
(d) |
||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
649 |
$ |
(893) |
$ |
34 |
$ |
2,716 |
||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | ||||
Less: Tax Reform Impact |
(2,169) |
- |
- |
- |
- | |||||||||
Total Stockholders' Equity (Non-GAAP) - (e) |
$ |
14,114 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | ||||
Average Total Stockholders' Equity (GAAP) * - (f) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) |
$ |
14,048 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Current and Long-Term Debt (GAAP) - (h) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | ||||
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||||||
Net Debt (Non-GAAP) - (i) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | ||||
Total Capitalization (GAAP) - (d) + (h) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | ||||
Total Capitalization (Non-GAAP) - (e) + (i) |
$ |
19,667 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | ||||
Average Total Capitalization (Non-GAAP) * - (j) |
$ |
19,518 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) |
14.1% |
-4.8% |
-21.6% |
14.7% |
||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) |
4.2% |
-3.7% |
0.9% |
13.7% |
||||||||||
Return on Equity (ROE) |
||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) |
17.1% |
-8.1% |
-29.5% |
17.6% |
||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) |
4.6% |
-6.6% |
0.2% |
16.4% |
||||||||||
* Average for the current and immediately preceding year |
||||||||||||||
Adjustments to Net Income (Loss) (GAAP) | ||||||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017: | ||||||||||||||
Year Ended December 31, 2017 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(12) |
$ |
4 |
$ |
(8) |
||||||||
Add: Impairments of Certain Assets |
261 |
(93) |
168 |
|||||||||||
Add: Net Losses on Asset Dispositions |
99 |
(35) |
64 |
|||||||||||
Add: Legal Settlement - Early Lease Termination |
10 |
(4) |
6 |
|||||||||||
Add: Joint Venture Transaction Costs |
3 |
(1) |
2 |
|||||||||||
Add: Joint Interest Billings Deemed Uncollectible |
5 |
(2) |
3 |
|||||||||||
Less: Tax Reform Impact |
- |
(2,169) |
(2,169) |
|||||||||||
Total |
$ |
366 |
$ |
(2,300) |
$ |
(1,934) |
||||||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: | ||||||||||||||
Year Ended December 31, 2016 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 |
||||||||
Add: Impairments of Certain Assets |
321 |
(113) |
208 |
|||||||||||
Less: Net Gains on Asset Dispositions |
(206) |
62 |
(144) |
|||||||||||
Add: Trinidad Tax Settlement |
- |
43 |
43 |
|||||||||||
Add: Voluntary Retirement Expense |
42 |
(15) |
27 |
|||||||||||
Add: Acquisition - State Apportionment Change |
- |
16 |
16 |
|||||||||||
Add: Acquisition Costs |
5 |
- |
5 |
|||||||||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 |
||||||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: | ||||||||||||||
Year Ended December 31, 2015 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
||||||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
|||||||||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
|||||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
|||||||||||
Add: Severance Costs |
9 |
(3) |
6 |
|||||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
|||||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
||||||||
(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: | ||||||||||||||
Year Ended December 31, 2014 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
||||||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
|||||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
|||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
- |
250 |
250 |
|||||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
Second Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Second Quarter and Full Year 2018 Forecast | |||||||||||
The forecast items for the second quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2018 |
Full Year 2018 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
374.0 |
- |
382.0 |
387.0 |
- |
401.0 | |||||
Trinidad |
0.4 |
- |
0.6 |
0.4 |
- |
0.6 | |||||
Other International |
0.0 |
- |
6.0 |
2.0 |
- |
4.0 | |||||
Total |
374.4 |
- |
388.6 |
389.4 |
- |
405.6 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
100.0 |
- |
110.0 |
100.0 |
- |
110.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
870 |
- |
910 |
900 |
- |
950 | |||||
Trinidad |
280 |
- |
300 |
250 |
- |
290 | |||||
Other International |
25 |
- |
35 |
28 |
- |
38 | |||||
Total |
1,175 |
- |
1,245 |
1,178 |
- |
1,278 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
619.0 |
- |
643.7 |
637.0 |
- |
669.3 | |||||
Trinidad |
47.1 |
- |
50.6 |
42.1 |
- |
48.9 | |||||
Other International |
4.2 |
- |
11.9 |
6.7 |
- |
10.3 | |||||
Total |
670.3 |
- |
706.2 |
685.8 |
- |
728.5 | |||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2018 |
Full Year 2018 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.50 |
- |
$ |
4.90 |
$ |
4.20 |
- |
$ |
4.80 | |
Transportation Costs |
$ |
2.90 |
- |
$ |
3.40 |
$ |
2.75 |
- |
$ |
3.25 | |
Depreciation, Depletion and Amortization |
$ |
13.15 |
- |
$ |
13.55 |
$ |
13.00 |
- |
$ |
13.40 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
100 |
- |
$ |
120 |
$ |
375 |
- |
$ |
425 | |
General and Administrative |
$ |
100 |
- |
$ |
110 |
$ |
415 |
- |
$ |
445 | |
Gathering and Processing |
$ |
110 |
- |
$ |
120 |
$ |
430 |
- |
$ |
470 | |
Capitalized Interest |
$ |
5 |
- |
$ |
6 |
$ |
19 |
- |
$ |
23 | |
Net Interest |
$ |
62 |
- |
$ |
65 |
$ |
244 |
- |
$ |
248 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.5% |
- |
6.9% |
6.5% |
- |
6.9% | |||||
Income Taxes |
|||||||||||
Effective Rate |
20% |
- |
25% |
20% |
- |
25% | |||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(90) |
- |
$ |
(55) |
$ |
(350) |
- |
$ |
(310) | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
4,500 |
- |
$ |
4,800 | ||||||
Exploration and Development Facilities |
$ |
600 |
- |
$ |
650 | ||||||
Gathering, Processing and Other |
$ |
300 |
- |
$ |
350 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(1.50) |
- |
$ |
0.50 |
$ |
(1.25) |
- |
$ |
0.75 | |
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) | |
Other International - above (below) WTI |
$ |
2.00 |
- |
$ |
4.00 |
$ |
0.00 |
- |
$ |
6.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
32% |
- |
38% |
32% |
- |
38% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.70) |
- |
$ |
(0.30) |
$ |
(0.60) |
- |
$ |
0.00 | |
Realizations |
|||||||||||
Trinidad |
$ |
2.30 |
- |
$ |
2.70 |
$ |
2.15 |
- |
$ |
2.75 | |
Other International |
$ |
4.15 |
- |
$ |
4.65 |
$ |
4.00 |
- |
$ |
5.00 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel | |||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent | |||||||||||
$/Mcf U.S. Dollars per thousand cubic feet | |||||||||||
$MM U.S. Dollars in millions | |||||||||||
MBbld Thousand barrels per day | |||||||||||
MBoed Thousand barrels of oil equivalent per day | |||||||||||
MMcfd Million cubic feet per day | |||||||||||
NYMEX U.S. New York Mercantile Exchange | |||||||||||
WTI West Texas Intermediate |
EOG RESOURCES, INC. | ||||||||||||||
First Quarter 2018 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells Online |
Initial Gross 30-Day Average Production Rate | |||||||||||||
Gross |
Net |
Lateral |
Crude Oil and |
Natural Gas |
Natural Gas |
Crude Oil | ||||||||
Delaware Basin |
||||||||||||||
Wolfcamp |
58 |
53 |
5,900 |
1,335 |
250 |
2.1 |
1,925 | |||||||
Bone Spring |
9 |
8 |
5,900 |
1,195 |
190 |
1.6 |
1,645 | |||||||
Leonard |
3 |
3 |
4,300 |
1,640 |
335 |
2.8 |
2,430 | |||||||
Powder River Basin Turner |
9 |
8 |
6,100 |
675 |
180 |
2.1 |
1,210 | |||||||
DJ Basin Codell |
12 |
9 |
9,200 |
895 |
95 |
0.4 |
1,055 | |||||||
South Texas Eagle Ford |
72 |
65 |
6,900 |
1,325 |
150 |
0.9 |
1,620 | |||||||
South Texas Austin Chalk |
10 |
8 |
4,600 |
1,960 |
400 |
2.3 |
2,750 |
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
View original content:http://www.prnewswire.com/news-releases/eog-resources-announces-first-quarter-2018-results-300642509.html
SOURCE EOG Resources, Inc.
HOUSTON, April 25, 2018 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.185 per share on EOG's Common Stock, payable July 31, 2018, to stockholders of record as of July 17, 2018. The indicated annual rate is $0.74.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-300636695.html
SOURCE EOG Resources, Inc.
DENVER, April 25, 2018 /PRNewswire/ -- EnerCom, Inc. is pleased to announce it will host the 23rd annual edition of its popular The Oil & Gas Conference® this summer in Denver, Colo.
This year's oil and gas investment conference will be held August 19-22, 2018, at the Westin Denver Downtown. Investment and oil and gas professionals may register for the event through the conference website.
Conference Details: The Oil & Gas Conference® 23 offers investment professionals the opportunity to listen to senior management teams in the oil and gas industry present operational and financial strategies and learn about important energy topics affecting the global oil and gas industry. The forum fosters healthy dialogue and informal networking opportunities for attendees.
Public and Private Company Presenters: The 2018 edition of EnerCom's The Oil & Gas Conference® will feature public and private oil and gas companies with operations spanning 40 countries and six continents, including all of the U.S. shale basins, the Gulf of Mexico, Canada, Latin America and Africa. A work-in-progress list of the 2018 presenting companies will be posted and updated on the conference website.
The 2018 presenting companies include but are not limited to:
Additional Speakers: Global energy industry leaders, economists, market strategists, government officials and other energy experts will provide their insights on topics such as global commodities markets, the U.S. becoming a net energy exporter, and capital sources for energy development.
Who Attends the Conference: More than 2,000 institutional, private equity and hedge fund investors, energy research analysts, retail brokers, trust officers, high net worth investors, investment bankers and energy industry professionals gather in Denver for the conference.
One-on-One Meetings: EnerCom works in advance with presenting company management teams to arrange one-on-one meetings with the attending institutional investors and research analysts at the conference venue. In 2017, EnerCom managed more than 2,100 one-on-one meeting requests.
How to Register: Investment professionals and oil and gas companies can register for the event through the conference website.
EnerCom History and Sponsors: EnerCom, Inc. founded The Oil & Gas Conference® in 1996. It is the oldest and largest energy investment conference in Denver.
Global sponsors of EnerCom's conferences are Netherland, Sewell & Associates; RS Energy Group; Moss Adams; and Preng & Associates. Sponsors of The Oil & Gas Conference® 23 are Bank of America Merrill Lynch; Assured Partners; DNB Bank ASA; Fifth Third Bank; CIBC; Haynes and Boone; and Credit Agricole CIB.
About EnerCom, Inc.
Since 1994 EnerCom, Inc. has developed into a nationally recognized management consultancy advising oil and gas industry clients on corporate strategy, asset valuations, investor relations, media relations, external communications and visual communications design.
EnerCom produces and publishes numerous data products and external communications tools for public energy companies including:
EnerCom's professionals have more than 170 years of industry and business experience and a proven track record of success.
Headquartered in Denver, with senior consultants in Dallas and Houston, EnerCom uses the team approach for delivering its wide range of services to public and private companies, large and small, operating in the global exploration and production, OilService, capital markets, and associated advanced-technology industries.
EnerCom's upcoming oil and gas investment conferences include:
EnerCom Denver (The Oil & Gas Conference®) – August 19-22, 2018
EnerCom Dallas – Q1 - 2019
For more information about EnerCom and its services, please visit http://www.enercominc.com/ or call +1 303-296-8834 to speak with the management team or one of our consultants.
About Netherland, Sewell & Associates, Inc.
Netherland, Sewell & Associates, Inc. (NSAI) was founded in 1961 to provide the highest quality engineering and geological consulting to the petroleum industry. Today they are recognized as the worldwide leader of petroleum property analysis to industry and financial organizations and government agencies. With offices in Dallas and Houston, NSAI provides a complete range of geological, geophysical, petrophysical, and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. They provide reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. For a complete list of services or to learn more about Netherland, Sewell & Associates, Inc. please visit www.netherlandsewell.com.
For more information about NSAI, call C.H. (Scott) Rees, Chief Executive Officer, at 214-969-5401 or send an email to info@nsai-petro.com.
About RS Energy Group
RS Energy Group (RSEG) provides data-driven intelligence: evaluate assets, weigh valuable M&A opportunities and benchmark your business for more precise decision-making.
RSEG officially released its data solution in April 2017. RS Data™ provides clients with corrected, multi-sourced permit, completion and production data of unparalleled completeness and quality.
Today, RSEG's intelligence covers more than 150 companies operating in every key North American and many international energy plays with a powerful combination of practical insights at the asset level and a long-standing participation in capital markets. RSEG's independent, unbiased and accurate analysis forms a foundation of trust with its clients. Its collaborative approach, both internally and as an extension of its clients' research efforts, promotes innovation and fosters intimate, long term partnerships.
RS Energy Group (RSEG) is headquartered in Calgary, Alberta, with strategic locations in Houston, New York City, Philadelphia, San Francisco and Los Angeles. Contact RS Energy Group by phone at (403) 294-9111, or email info@rseg.com.
About Moss Adams LLP
For more than 30 years, Hein & Associates has been recognized throughout the industry as a leading oil and gas accounting and advisory firm. In late 2017, Hein combined with Moss Adams LLP, one of the largest accounting, consulting and wealth management firms in the nation, creating a $600 million middle-market accounting/tax/audit leader in the western U.S. with a strong oil & gas practice group.
With more than 2,900 professionals and staff across more than 25 locations in the West and beyond, Moss Adams works with many of the world's most innovative companies and leaders. Our strength in the middle market enables us to advise clients at all intervals of development—from start-up, to rapid growth and expansion, to transition. Today, we help over 2,300 companies doing business in more than 100 countries and territories.
For more information, please contact Joe Blice, Partner, National Practice Leader, Oil & Gas, CPA joe.blice@mossadams.com, (972) 687-7818.
Moss Adams LLP provides details at https://www.mossadams.com/home .
About Preng & Associates
Preng & Associates, founded in 1980, is the only retainer-based, international executive search firm specializing solely in the energy industry. Its number one priority is to assist clients with their executive selection, organization development, and human resource needs by providing the highest quality service. Preng's record of accomplishment is directly attributable to their experienced staff, worldwide network of industry contacts, proven search methodology, and high standards of professionalism. Preng has conducted over 3000 searches for board, executive, management, and professional positions in its 35-year history and has the highest success and repeat client track record.
Preng's practice is based on the premise that the search process is most effective when conducted by professionals with significant search industry experience. The company has earned a reputation for combining professional search disciplines with an in-depth industry and market understanding and has succeeded in some of the industry's most challenging and high-profile searches. Preng's international reach allows it to effectively conduct global engagements; and as a member of the Association of Executive Search Consultants, Preng practices and promotes its high standards of conduct and professionalism.
For more information about Preng & Associates, contact Charles Carpenter, Partner at 713-243-2610 or ccarpenter@preng.com.
About Bank of America Merrill Lynch
Bank of America Merrill Lynch Oil and Gas Group
The Bank of America Merrill Lynch (BofAML) Oil and Gas practice is comprised of a global team of bankers dedicated to covering the energy industry, dating back to the 1920s when Texas predecessor banks pioneered reserve-based lending. The practice includes an experienced in-house Petroleum Engineering team with over 150 years of combined experience. With one of the only full-service financial energy platforms in the industry, the BofAML oil and gas team manages significant capital commitments in the energy sector with dedicated bankers based in Calgary, Denver, Dallas, Houston, London and New York.
The BofA Merrill Lynch Global Research platform offers clients access to information and actionable ideas on stocks, bonds, economics and investment strategies. With approximately 700 analysts in more than 20 countries, we offer our clients knowledge about economic and business developments that are having an impact on the markets, so that they can work with their financial advisors to make the most of opportunities. BofA Merrill Lynch Global Research was ranked No. 1 for the fourth consecutive year on the 2014 list of Top Global Research Firms, Institutional Investor.
About AssuredPartners
AssuredPartners Colorado (AP CO) combines 30+ years of experience with leading-edge products to provide exceptional service and value to our customers. We provide a full range of brokerage services including employee benefits, property and casualty, and retirement. Headquartered in Colorado, we think globally but act locally, with personal services designed specifically for each individual client. AP CO utilizes resources with national networks of brokers to ensure we can meet your every need and find answers to your questions quickly and efficiently.
Our goal is to achieve a long-term relationship focused on bringing value to your employee benefits management and insurance programs. We are committed to utilizing our collective talent to support your insurance goals. We work to identify activities that drive claim frequency, and implement an action plan to control health care costs and promote a healthy work environment for your employees.
Securing the best insurance package for your business begins with planning. Analyzing all your risks is critical to successful implementation of your insurance plan. AP CO will partner with you by providing ongoing assistance, consultation and service that will help you control your insurance expenses, choose the best plan to fit your company's needs and promote health care consumerism.
For more information on AssuredPartners, please visit the website, call (800) 322-9773 or email info@assuredptrco.com.
About DNB ASA
DNB is Norway's largest financial services provider, with total assets approaching $400 billion. The bank has for years been a major provider of capital to the oil & gas industry, growing up literally side by side with the highly prolific fields developed in the Norwegian Sector of the North Sea. The Oslo Energy Office maintains a global financing strategy, and serves this market through multiple offices around the world including Houston, London and Singapore.
Energy Americas, based in Houston, comprises approximately 20 seasoned energy finance professionals. Aside from facilitating the bank's global business strategies, the office concentrates primarily on serving middle market and larger customers in the four principal oil & gas sectors — upstream, midstream, downstream and service — as well as in Power and Renewables. The bank offers a variety of financial products, from traditional oil & gas reserve financing, to longer-term capital markets transactions and merger/acquisition advisory services through its broker-dealer arm, DNB Markets, Inc. Ancillary service capabilities include cash management/depository services, as well as commodity and interest rate hedging.
For information on DNB's energy services, please visit the DNB energy website.
About Fifth Third Bancorp
Fifth Third Bank is a diversified financial services company with over $120 billion in assets. The Bank's energy group is comprised of experienced and knowledgeable individuals that can assist in providing and structuring financial solutions to meet their clients' needs across the upstream, midstream, downstream and services sectors. Solutions and capabilities include commodity hedging, interest rate management, foreign exchange, debt capital markets, treasury management, and depository/investment products.
For more information, please contact Richard Butler at 713-401-6101 or richard.butler@53.com.
About CIBC
CIBC is a leading North American bank headquartered in Canada and with offices around the world. CIBC was originally founded nearly 150 years ago, and has supported and financed the energy industry for many decades. CIBC was recently ranked as the strongest publicly traded bank in North America by Bloomberg, and is rated A+/Aa3 by S&P and Moody's, respectively.
Our energy specialists draw on the breadth of CIBC's capabilities to provide market insights and creative solutions for our clients. Services include corporate banking, commodity and interest rate hedging and strategy, A&D advisory, and capital markets.
CIBC is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "CM" and has a market cap of $36 billion and nearly $400 billion in total assets. For more information, please visit the CIBC energy website.
About Haynes and Boone
Haynes and Boone, LLP is an energy-focused corporate law firm, providing a full spectrum of legal services to our clients across the oil and gas industry, including the upstream, midstream, and downstream sectors. We serve energy clients from our offices in Texas, Colorado, New York, California, Washington, D.C., London, Mexico City and Shanghai. We work as a team representing U.S. and foreign public and private companies engaged in the dynamic day-to-day work of finding and extracting oil and gas, and the banks, investment funds and other investors that support them.
Our team of more than 100 energy lawyers and landmen understands the U.S. and international physical and financial energy markets, and the firm has been helping operators and lenders complete some of the largest financings and M&A transactions in recent years. With more than 600 attorneys, Haynes and Boone is ranked among the largest law firms in the nation by The National Law Journal, and our energy lawyers have been ranked by publications such as Best Lawyers in America, Chambers and Partners and Who's Who in Energy.
For more info, please visit www.haynesboone.com.
About Crédit Agricole Corporate and Investment Bank
Crédit Agricole Corporate and Investment Bank is the corporate and investment banking arm of the Crédit Agricole Group, the world's eighth largest bank by total assets (The Banker, July 2014). Crédit Agricole CIB offers its clients a comprehensive range of products and services in capital markets, brokerage, investment banking, structured finance, corporate banking, and international private banking.
The Bank provides support to clients in large international markets through its network, with a presence in major countries in Europe, the Americas, Asia and the Middle East.
With headquarters in New York City, and U.S. offices in Houston and Chicago, Credit Agricole CIB Americas offers its corporate and institutional clients financial products and services and made-to-order structuring, origination and distribution, through both its banking unit Credit Agricole CIB, and the full-service broker-dealer Credit Agricole Securities (USA) Inc., which is a member of the NYSE and NASD. Credit Agricole CIB is also present in Montreal, Canada, and in Latin America with offices in Argentina, Brazil, and Mexico.
The Energy Industry represents the single largest concentration of industry exposure at Credit Agricole Corporate and Investment Bank, whose specialty focus dates back over 100 years. Our Energy practice for North America, located in Houston, focuses on all segments of the business and covers it on a truly global basis.
For more information, visit www.ca-cib.com.
View original content:http://www.prnewswire.com/news-releases/enercoms-the-oil--gas-conference-coming-to-denver-aug-19-22-2018-300636057.html
SOURCE EnerCom, Inc.
HOUSTON, March 22, 2018 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss first quarter 2018 results on Friday, May 4, 2018, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-webcast-of-first-quarter-2018-results-conference-call-for-may-4-2018-300618466.html
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 27, 2018 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported fourth quarter 2017 net income of $2,430 million, or $4.20 per share. This compares to a fourth quarter 2016 net loss of $142 million, or $0.25 per share. For the full year 2017, EOG reported net income of $2,583 million, or $4.46 per share, compared to a net loss of $1,097 million, or $1.98 per share, for the full year 2016.
Adjusted non-GAAP net income for the fourth quarter 2017 was $401 million, or $0.69 per share, compared to an adjusted non-GAAP net loss of $7 million, or $0.01 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2017 was $648 million, or $1.12 per share, compared to an adjusted non-GAAP net loss of $893 million, or $1.61 per share, for the full year 2016. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. One of the adjusting items in the fourth quarter and full year 2017 was a non-cash reduction in income tax expense of $2.2 billion, or $3.75 per share, related to the revaluation of EOG's deferred tax liability and certain other items resulting from the Tax Cuts and Jobs Act. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Higher commodity prices, increased production volumes, well productivity improvements and per-unit cost reductions resulted in significant increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2017 compared to the fourth quarter 2016. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Operational Highlights
Crude oil and condensate volumes in the U.S. increased 20 percent in 2017 to 335,000 barrels of oil per day (Bopd). Increased development activity and well productivity improvements supported the volume increase. Total company natural gas liquids (NGLs) volumes grew 8 percent while natural gas volumes decreased 6 percent primarily due to the sale of the company's Barnett and Haynesville Shale dry gas assets in late 2016. Transportation expenses decreased 11 percent and depreciation, depletion and amortization expenses decreased 12 percent, on a per-unit basis.
Increased development activity drove substantial volume increases in the Eagle Ford and Delaware Basin during the fourth quarter. Total company crude oil and condensate volumes increased 40,200 Bopd compared to the third quarter 2017. Natural gas liquids volumes grew 15 percent while natural gas volumes increased 6 percent, compared to the third quarter 2017.
"EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG's integrated teams demonstrated superb operational performance, overcoming a major hurricane and other challenges to deliver record production volumes and cost savings which surpassed original targets set at the beginning of the year."
2018 Capital Plan
EOG's disciplined capital plan is designed to achieve strong returns on capital employed and healthy growth while spending within cash flow. The company expects to grow total company crude oil volumes by 18 percent, generate double-digit ROCE and cover capital investment and dividend payments within discretionary cash flow. EOG can deliver on its 2018 plan at oil prices below $50 and generates significant free cash flow at a $60 oil price.
EOG's return-based culture continues to drive cost reductions. The company targets lower well costs and per-unit operating expenses in 2018 despite a potentially inflationary operating environment. EOG is also focused on driving continued improvements in well productivity and pursuing exploration efforts in new plays.
Capital expenditures for 2018 are expected to range from $5.4 to $5.8 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. EOG expects to complete approximately 690 net wells in 2018, compared to 536 net wells in 2017. Capital will be allocated primarily to EOG's highest rate-of-return oil assets in the Delaware Basin, Eagle Ford, Rockies, Woodford and the Bakken.
At least 90 percent of the wells completed in 2018 are expected to be premium. EOG has an inventory of approximately 8,000 such wells, which have a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices and $2.50 flat natural gas prices.
"EOG enters 2018 better positioned than ever to generate significant shareholder value through the development of its large and diverse inventory of high rate-of-return premium wells," Thomas said. "We are determined to maintain the discipline, record-level operational efficiency and performance gained through the downturn. Our deep inventory of premium wells across the U.S. offers flexibility to adjust to changing conditions. We also see significant opportunities to increase our premium well inventory through organic exploration and development technology to further extend EOG's return on capital advantage."
Dividend Increase
The board of directors increased the cash dividend on the common stock by 10.4 percent. Effective with the dividend payable April 30, 2018, to stockholders of record as of April 16, 2018, the board declared a quarterly dividend of $0.185 per share on the common stock. The indicated annual rate is $0.74 per share.
Delaware Basin
2017 was a watershed year for EOG in the Delaware Basin, where it successfully integrated the Yates acquisition, identified 1,240 additional net premium well locations, added the First Bone Spring as its fourth premium play and reduced completed well costs by $800,000 per well. Delaware Basin crude oil and condensate volumes increased over 80 percent in 2017 and exceeded 100,000 Bopd in the fourth quarter 2017.
EOG continued active development of its 416,000 net acre position in the Delaware Basin in the fourth quarter 2017, completing 65 wells.
In the Delaware Basin Wolfcamp, in Lea County, NM, EOG completed a four-well package, the Calm Breeze 2 Fed Com #701-704H, with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 2,605 Bopd, 440 barrels per day (Bpd) of NGLs and 3.7 million cubic feet per day (MMcfd) of natural gas.
In the Delaware Basin First Bone Spring, in Lea County, NM, EOG completed the Righteous 6 State Com #301H with a treated lateral length of 7,100 feet and 30-day initial production rate of 1,305 Bopd, 170 Bpd of NGLs and 1.4 MMcfd of natural gas.
In the Delaware Basin Leonard, in Loving County, TX, EOG completed a four-well package, the State Atlas A#3H – D#6H, with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 1,215 Bopd, 270 Bpd of NGLs and 2.3 MMcfd of natural gas.
South Texas Eagle Ford and Austin Chalk
EOG continues to enhance the productivity of its bellwether asset in the South Texas Eagle Ford. Eight years after initiating development, EOG further reduced well costs and improved well performance during 2017 in its 520,000 net acre position in the crude oil window of this world class play. EOG also expanded its enhanced oil recovery program, adding 56 wells last year. For the full year 2017, crude oil production in the Eagle Ford and Austin Chalk increased one percent year-over-year despite interruption to producing volumes as a result of Hurricane Harvey.
In the fourth quarter, EOG completed 74 wells in the Eagle Ford. These included 13 wells with lateral lengths of more than 10,000 feet. In LaSalle County, EOG completed a four-well package, the White 5H-8H, with an average treated lateral length of 12,900 feet per well and average 30-day initial production rates per well of 1,545 Bopd, 80 Bpd of NGLs and 0.5 MMcfd of natural gas. In DeWitt County, EOG completed a four-well package, the Hendrix 8H-10H and the Hendrix 12H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 2,545 Bopd, 420 Bpd of NGLs and 2.4 MMcfd of natural gas.
EOG continued to test its position in the South Texas Austin Chalk, a geologically complex formation which lies above the South Texas Eagle Ford, completing four net wells in the fourth quarter.
Rockies
EOG's Wyoming Powder River Basin and DJ Basin activity both contributed to the company's 2017 crude oil production growth. In the Powder River Basin, EOG continued exploration activity on its 400,000 net acre position in the core of the play. The company tested the prospectivity of multiple target zones and also tested the aerial extent of various targets in the Powder River Basin during the year. In the DJ Basin, EOG achieved significant well cost reductions during 2017 through a focus on efficiency improvements in drilling and completion operations.
In the fourth quarter, EOG completed nine wells in the Powder River Basin. In Converse County, EOG completed the Mary's Draw 453-0310H and 455-0310H wells with an average treated lateral length of 7,300 feet per well and average 30-day initial production rates per well of 1,280 Bopd, 610 Bpd of NGLs and 7.6 MMcfd of natural gas. In the DJ Basin, EOG completed three wells in the fourth quarter. This included the Big Sandy 522-2536H with a treated lateral length of 8,800 feet and 30-day initial production rate of 1,100 Bopd, 110 Bpd of NGLs and 0.2 MMcfd of natural gas.
Reserves
At year-end 2017, total company net proved reserves were 2,527 million barrels of oil equivalent (MMBoe), an increase of 18 percent compared to year-end 2016. Net proved reserve additions from all sources, excluding revisions due to price, replaced 201 percent of EOG's 2017 production at a finding and development cost of $8.71 per barrel of oil equivalent. Revisions due to price increased net proved reserves by 154 MMBoe and asset divestitures decreased net proved reserves by 21 MMBoe. (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)
For the 30th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.
Hedging Activity
During the fourth quarter ended December 31, 2017, EOG entered into crude oil financial price swap contracts and differential basis swap contracts. A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At December 31, 2017, EOG's total debt outstanding was $6.4 billion with a debt-to-total capitalization ratio of 28 percent. Considering cash on the balance sheet at the end of the fourth quarter, EOG's net debt was $5.6 billion with a net debt-to-total capitalization ratio of 25 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales for the full year 2017 totaled $227 million.
Conference Call February 28, 2018
EOG's fourth quarter and full year 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, February 28, 2018. To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Furthermore, EOG has presented or referenced herein or in its accompanying disclosures certain forward-looking, non-GAAP financial measures, such as free cash flow and discretionary cash flow, and certain related estimates regarding future performance, results and financial position. These forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented. EOG's actual results may differ materially from the measure and estimates presented or referenced herein. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2017, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
Neel Panchal | |
(713) 571-4884 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Net Operating Revenues and Other |
$ |
3,340.4 |
$ |
2,402.0 |
$ |
11,208.3 |
$ |
7,650.6 | |||
Net Income (Loss) |
$ |
2,430.5 |
$ |
(142.4) |
$ |
2,582.6 |
$ |
(1,096.7) | |||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
4.22 |
$ |
(0.25) |
$ |
4.49 |
$ |
(1.98) | |||
Diluted |
$ |
4.20 |
$ |
(0.25) |
$ |
4.46 |
$ |
(1.98) | |||
Average Number of Common Shares |
|||||||||||
Basic |
575.4 |
567.3 |
574.6 |
553.4 | |||||||
Diluted |
579.2 |
567.3 |
578.7 |
553.4 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Net Operating Revenues and Other |
|||||||||||
Crude Oil and Condensate |
$ |
1,929,471 |
$ |
1,366,223 |
$ |
6,256,396 |
$ |
4,317,341 | |||
Natural Gas Liquids |
249,172 |
137,849 |
729,561 |
437,250 | |||||||
Natural Gas |
246,922 |
215,373 |
921,934 |
742,152 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts |
(45,032) |
(65,787) |
19,828 |
(99,608) | |||||||
Gathering, Processing and Marketing |
1,008,385 |
614,594 |
3,298,087 |
1,966,259 | |||||||
Gains (Losses) on Asset Dispositions, Net |
(65,220) |
104,034 |
(99,096) |
205,835 | |||||||
Other, Net |
16,741 |
29,753 |
81,610 |
81,403 | |||||||
Total |
3,340,439 |
2,402,039 |
11,208,320 |
7,650,632 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
281,941 |
241,846 |
1,044,847 |
927,452 | |||||||
Transportation Costs |
191,717 |
193,319 |
740,352 |
764,106 | |||||||
Gathering and Processing Costs |
43,295 |
32,516 |
148,775 |
122,901 | |||||||
Exploration Costs |
22,941 |
39,110 |
145,342 |
124,953 | |||||||
Dry Hole Costs |
4,532 |
193 |
4,609 |
10,657 | |||||||
Impairments |
153,442 |
297,946 |
479,240 |
620,267 | |||||||
Marketing Costs |
1,009,566 |
634,248 |
3,330,237 |
2,007,635 | |||||||
Depreciation, Depletion and Amortization |
881,745 |
862,524 |
3,409,387 |
3,553,417 | |||||||
General and Administrative |
117,005 |
102,182 |
434,467 |
394,815 | |||||||
Taxes Other Than Income |
158,343 |
103,642 |
544,662 |
349,710 | |||||||
Total |
2,864,527 |
2,507,526 |
10,281,918 |
8,875,913 | |||||||
Operating Income (Loss) |
475,912 |
(105,487) |
926,402 |
(1,225,281) | |||||||
Other Income (Expense), Net |
803 |
(17,198) |
9,152 |
(50,543) | |||||||
Income (Loss) Before Interest Expense and Income Taxes |
476,715 |
(122,685) |
935,554 |
(1,275,824) | |||||||
Interest Expense, Net |
63,362 |
71,325 |
274,372 |
281,681 | |||||||
Income (Loss) Before Income Taxes |
413,353 |
(194,010) |
661,182 |
(1,557,505) | |||||||
Income Tax Benefit |
(2,017,115) |
(51,658) |
(1,921,397) |
(460,819) | |||||||
Net Income (Loss) |
$ |
2,430,468 |
$ |
(142,352) |
$ |
2,582,579 |
$ |
(1,096,686) | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.6700 |
$ |
0.6700 |
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
366.9 |
306.0 |
335.0 |
278.3 | |||||||
Trinidad |
1.1 |
0.9 |
0.9 |
0.8 | |||||||
Other International (B) |
0.1 |
4.8 |
0.8 |
3.4 | |||||||
Total |
368.1 |
311.7 |
336.7 |
282.5 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
56.95 |
$ |
47.93 |
$ |
50.91 |
$ |
41.84 | |||
Trinidad |
46.56 |
40.04 |
42.30 |
33.76 | |||||||
Other International (B) |
45.72 |
38.96 |
57.20 |
36.72 | |||||||
Composite |
56.97 |
47.76 |
50.91 |
41.76 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
100.6 |
80.9 |
88.4 |
81.6 | |||||||
Other International (B) |
- |
- |
- |
- | |||||||
Total |
100.6 |
80.9 |
88.4 |
81.6 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
26.92 |
$ |
18.51 |
$ |
22.61 |
$ |
14.63 | |||
Other International (B) |
- |
- |
- |
- | |||||||
Composite |
26.92 |
18.51 |
22.61 |
14.63 | |||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
829 |
800 |
765 |
810 | |||||||
Trinidad |
299 |
323 |
313 |
340 | |||||||
Other International (B) |
32 |
22 |
25 |
25 | |||||||
Total |
1,160 |
1,145 |
1,103 |
1,175 | |||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
2.17 |
$ |
2.05 |
$ |
2.20 |
$ |
1.60 | |||
Trinidad |
2.52 |
1.89 |
2.38 |
1.88 | |||||||
Other International (B) |
4.23 |
3.85 |
3.89 |
3.64 | |||||||
Composite |
2.31 |
2.04 |
2.29 |
1.73 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
605.6 |
520.3 |
551.0 |
494.9 | |||||||
Trinidad |
51.0 |
54.6 |
53.0 |
57.5 | |||||||
Other International (B) |
5.4 |
8.6 |
4.9 |
7.6 | |||||||
Total |
662.0 |
583.5 |
608.9 |
560.0 | |||||||
Total MMBoe (D) |
60.9 |
53.7 |
222.3 |
205.0 | |||||||
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
December 31, |
December 31, | ||||
2017 |
2016 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
834,228 |
$ |
1,599,895 | |
Accounts Receivable, Net |
1,597,494 |
1,216,320 | |||
Inventories |
483,865 |
350,017 | |||
Assets from Price Risk Management Activities |
7,699 |
- | |||
Income Taxes Receivable |
113,357 |
12,305 | |||
Other |
242,465 |
206,679 | |||
Total |
3,279,108 |
3,385,216 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
52,555,741 |
49,592,091 | |||
Other Property, Plant and Equipment |
3,960,759 |
4,008,564 | |||
Total Property, Plant and Equipment |
56,516,500 |
53,600,655 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(30,851,463) |
(27,893,577) | |||
Total Property, Plant and Equipment, Net |
25,665,037 |
25,707,078 | |||
Deferred Income Taxes |
17,506 |
16,140 | |||
Other Assets |
871,427 |
190,767 | |||
Total Assets |
$ |
29,833,078 |
$ |
29,299,201 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,847,131 |
$ |
1,511,826 | |
Accrued Taxes Payable |
148,874 |
118,411 | |||
Dividends Payable |
96,410 |
96,120 | |||
Liabilities from Price Risk Management Activities |
50,429 |
61,817 | |||
Current Portion of Long-Term Debt |
356,235 |
6,579 | |||
Other |
226,463 |
232,538 | |||
Total |
2,725,542 |
2,027,291 | |||
Long-Term Debt |
6,030,836 |
6,979,779 | |||
Other Liabilities |
1,275,213 |
1,282,142 | |||
Deferred Income Taxes |
3,518,214 |
5,028,408 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares and 640,000,000 |
205,788 |
205,770 | |||
Additional Paid in Capital |
5,536,547 |
5,420,385 | |||
Accumulated Other Comprehensive Loss |
(19,297) |
(19,010) | |||
Retained Earnings |
10,593,533 |
8,398,118 | |||
Common Stock Held in Treasury, 350,961 Shares and 250,155 Shares at December 31, 2017 and 2016, respectively |
(33,298) |
(23,682) | |||
Total Stockholders' Equity |
16,283,273 |
13,981,581 | |||
Total Liabilities and Stockholders' Equity |
$ |
29,833,078 |
$ |
29,299,201 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Twelve Months Ended | |||||
December 31, | |||||
2017 |
2016 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
2,582,579 |
(1,096,686) | ||
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
3,409,387 |
3,553,417 | |||
Impairments |
479,240 |
620,267 | |||
Stock-Based Compensation Expenses |
133,849 |
128,090 | |||
Deferred Income Taxes |
(1,473,872) |
(515,206) | |||
(Gains) Losses on Asset Dispositions, Net |
99,096 |
(205,835) | |||
Other, Net |
6,546 |
61,690 | |||
Dry Hole Costs |
4,609 |
10,657 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(19,828) |
99,608 | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
7,438 |
(22,219) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
(29,357) | |||
Other, Net |
1,204 |
10,971 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(392,131) |
(232,799) | |||
Inventories |
(174,548) |
170,694 | |||
Accounts Payable |
324,192 |
(74,048) | |||
Accrued Taxes Payable |
(63,937) |
92,782 | |||
Other Assets |
(658,609) |
(40,636) | |||
Other Liabilities |
(89,871) |
(16,225) | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
89,992 |
(156,102) | |||
Net Cash Provided by Operating Activities |
4,265,336 |
2,359,063 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(3,950,918) |
(2,489,756) | |||
Additions to Other Property, Plant and Equipment |
(173,324) |
(93,039) | |||
Proceeds from Sales of Assets |
226,768 |
1,119,215 | |||
Net Cash Received from Yates Transaction |
- |
54,534 | |||
Changes in Components of Working Capital Associated with Investing Activities |
(89,935) |
156,102 | |||
Net Cash Used in Investing Activities |
(3,987,409) |
(1,252,944) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
- |
(259,718) | |||
Long-Term Debt Borrowings |
- |
991,097 | |||
Long-Term Debt Repayments |
(600,000) |
(563,829) | |||
Dividends Paid |
(386,531) |
(372,845) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
29,357 | |||
Treasury Stock Purchased |
(63,408) |
(82,125) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
20,840 |
23,296 | |||
Debt Issuance Costs |
- |
(1,602) | |||
Repayment of Capital Lease Obligation |
(6,555) |
(6,353) | |||
Other, Net |
(57) |
- | |||
Net Cash Used in Financing Activities |
(1,035,711) |
(242,722) | |||
Effect of Exchange Rate Changes on Cash |
(7,883) |
17,992 | |||
Increase (Decrease) in Cash and Cash Equivalents |
(765,667) |
881,389 | |||
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 | |||
Cash and Cash Equivalents at End of Period |
$ |
834,228 |
$ |
1,599,895 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
To Net Income (Loss) (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and 2016, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back acquisition costs and state apportionment change related to the Yates transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017, to add back the transaction costs for the formation of a joint venture in 2017, to add back joint interest billings deemed uncollectible in 2017, and to eliminate the impact of tax reform in 2017. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
December 31, 2017 |
December 31, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ 413,353 |
$2,017,115 |
$ 2,430,468 |
$ 4.20 |
$ (194,010) |
$ 51,658 |
$ (142,352) |
$ (0.25) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
45,032 |
(16,142) |
28,890 |
0.05 |
65,787 |
(23,583) |
42,204 |
0.07 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative |
2,708 |
(971) |
1,737 |
- |
- |
29 |
29 |
- | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
65,220 |
(23,315) |
41,905 |
0.07 |
(104,034) |
36,856 |
(67,178) |
(0.12) | |||||||
Add: Impairments |
100,304 |
(35,954) |
64,350 |
0.11 |
217,839 |
(76,728) |
141,111 |
0.25 | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
- |
(57) |
(57) |
- | |||||||
Add: Acquisition - State Apportionment Change |
- |
- |
- |
- |
- |
16,424 |
16,424 |
0.03 | |||||||
Add: Acquisition Costs |
- |
- |
- |
- |
2,173 |
955 |
3,128 |
0.01 | |||||||
Add: Joint Interest Billings Deemed Uncollectible |
4,528 |
(1,623) |
2,905 |
0.01 |
- |
- |
- |
- | |||||||
Less: Tax Reform Impact |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
217,792 |
(2,247,381) |
(2,029,589) |
(3.51) |
181,765 |
(46,104) |
135,661 |
0.24 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ 631,145 |
$ (230,266) |
$ 400,879 |
$ 0.69 |
$ (12,245) |
$ 5,554 |
$ (6,691) |
$ (0.01) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
575,394 |
567,337 | |||||||||||||
Diluted |
579,203 |
567,337 | |||||||||||||
Twelve Months Ended |
Twelve Months Ended | ||||||||||||||
December 31, 2017 |
December 31, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ 661,182 |
$1,921,397 |
$ 2,582,579 |
$ 4.46 |
$(1,557,505) |
$ 460,819 |
$(1,096,686) |
$ (1.98) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
(19,828) |
7,107 |
(12,721) |
(0.02) |
99,608 |
(35,640) |
63,968 |
0.12 | |||||||
Net Cash Received from (Payments for) |
7,438 |
(2,666) |
4,772 |
0.01 |
(22,219) |
7,950 |
(14,269) |
(0.03) | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
99,096 |
(35,270) |
63,826 |
0.11 |
(205,835) |
61,491 |
(144,344) |
(0.26) | |||||||
Add: Impairments |
261,452 |
(93,718) |
167,734 |
0.29 |
320,617 |
(113,368) |
207,249 |
0.37 | |||||||
Add: Trinidad Tax Settlement |
- |
- |
- |
- |
- |
43,000 |
43,000 |
0.08 | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
42,054 |
(15,047) |
27,007 |
0.05 | |||||||
Add: Acquisition - State Apportionment Change |
- |
- |
- |
- |
- |
16,424 |
16,424 |
0.03 | |||||||
Add: Acquisition Costs |
- |
- |
- |
- |
5,100 |
(88) |
5,012 |
0.01 | |||||||
Add: Legal Settlement - Early Lease Termination |
10,202 |
(3,657) |
6,545 |
0.01 |
- |
- |
- |
- | |||||||
Add: Joint Venture Transaction Costs |
3,056 |
(1,095) |
1,961 |
- |
- |
- |
- |
- | |||||||
Add: Joint Interest Billings Deemed Uncollectible |
4,528 |
(1,623) |
2,905 |
0.01 |
- |
- |
- |
- | |||||||
Less: Tax Reform Impact |
- |
(2,169,376) |
(2,169,376) |
(3.75) |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
365,944 |
(2,300,298) |
(1,934,354) |
(3.34) |
239,325 |
(35,278) |
204,047 |
0.37 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ 1,027,126 |
$ (378,901) |
$ 648,225 |
$ 1.12 |
$(1,318,180) |
$ 425,541 |
$ (892,639) |
$ (1.61) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,620 |
553,384 | |||||||||||||
Diluted |
578,693 |
553,384 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
Calculation of Free Cash Flow (Non-GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Other Non-Current Taxes,Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG defines Free Cash Flow (Non-GAAP) for a given period as Discretionary Cash Flow (Non-GAAP) (see below reconciliation) for such period less the total cash capital expenditures excluding acquisitions incurred (Non-GAAP) during such period and dividends paid (GAAP) during such period, as is illustrated below for the twelve months ended December 31, 2017. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||||
December 31, |
December 31, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,327,548 |
$ |
804,745 |
$ |
4,265,336 |
$ |
2,359,063 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
16,420 |
33,931 |
122,688 |
104,199 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
- |
7,286 |
- |
29,357 | ||||||||
Other Non-Current Taxes (Non-Current Impact of the Tax Cut Jobs Act) |
(513,404) |
- |
(513,404) |
- | ||||||||
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||
Accounts Receivable |
366,686 |
220,939 |
392,131 |
232,799 | ||||||||
Inventories |
156,874 |
(33,131) |
174,548 |
(170,694) | ||||||||
Accounts Payable |
(211,298) |
(127,165) |
(324,192) |
74,048 | ||||||||
Accrued Taxes Payable |
13,970 |
21,214 |
63,937 |
(92,782) | ||||||||
Other Assets |
574,669 |
28,110 |
658,609 |
40,636 | ||||||||
Other Liabilities |
20,647 |
53,024 |
89,871 |
16,225 | ||||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
(210,365) |
36,342 |
(89,992) |
156,102 | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,541,747 |
$ |
1,045,295 |
$ |
4,839,532 |
$ |
2,748,953 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
47% |
76% |
||||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
4,839,532 |
||||||||||
Less: |
||||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP)(a) |
(4,228,859) |
|||||||||||
Dividends Paid (GAAP) |
(386,531) |
|||||||||||
Free Cash Flow (Non-GAAP) |
$ |
224,142 |
||||||||||
(a) See below reconciliation of Total Expenditures (GAAP) to Total Cash Expenditures Excluding Acquisitions (Non-GAAP) for the twelve months ended December 31, 2017: | ||||||||||||
Total Expenditures (GAAP) |
$ |
4,612,746 |
||||||||||
Less: |
||||||||||||
Asset Retirement Costs |
(55,592) |
|||||||||||
Non-Cash Acquisition Costs of Unproved Properties |
(255,711) |
|||||||||||
Acquisition Costs of Proved Properties |
(72,584) |
|||||||||||
Total Cash Expenditures Excluding Acquisitions (Non-GAAP) |
$ |
4,228,859 |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Income (Loss) (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Net Income (Loss) (GAAP) |
$ |
2,430,468 |
$ |
(142,352) |
$ |
2,582,579 |
$ |
(1,096,686) | |||
Adjustments: |
|||||||||||
Interest Expense, Net |
63,362 |
71,325 |
274,372 |
281,681 | |||||||
Income Tax Provision (Benefit) |
(2,017,115) |
(51,658) |
(1,921,397) |
(460,819) | |||||||
Depreciation, Depletion and Amortization |
881,745 |
862,524 |
3,409,387 |
3,553,417 | |||||||
Exploration Costs |
22,941 |
39,110 |
145,342 |
124,953 | |||||||
Dry Hole Costs |
4,532 |
193 |
4,609 |
10,657 | |||||||
Impairments |
153,442 |
297,946 |
479,240 |
620,267 | |||||||
EBITDAX (Non-GAAP) |
1,539,375 |
1,077,088 |
4,974,132 |
3,033,470 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
45,032 |
65,787 |
(19,828) |
99,608 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
2,708 |
- |
7,438 |
(22,219) | |||||||
(Gains) Losses on Asset Dispositions, Net |
65,220 |
(104,034) |
99,096 |
(205,835) | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,652,335 |
$ |
1,038,841 |
$ |
5,060,838 |
$ |
2,905,024 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
59% |
74% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
December 31, |
December 31, | ||||
2017 |
2016 | ||||
Total Stockholders' Equity - (a) |
$ |
16,283 |
$ |
13,982 | |
Current and Long-Term Debt (GAAP) - (b) |
6,387 |
6,986 | |||
Less: Cash |
(834) |
(1,600) | |||
Net Debt (Non-GAAP) - (c) |
5,553 |
5,386 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
22,670 |
$ |
20,968 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
21,836 |
$ |
19,368 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
28% |
33% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
25% |
28% |
EOG RESOURCES, INC. | ||||||||
Reserves Supplemental Data | ||||||||
(Unaudited) | ||||||||
2017 NET PROVED RESERVES RECONCILIATION SUMMARY |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
CRUDE OIL & CONDENSATE (MMBbl) |
||||||||
Beginning Reserves |
1,168.5 |
0.8 |
8.3 |
1,177.6 |
||||
Revisions |
58.0 |
0.1 |
(0.2) |
57.9 |
||||
Purchases in place |
1.1 |
- |
- |
1.1 |
||||
Extensions, discoveries and other additions |
207.1 |
0.3 |
0.1 |
207.5 |
||||
Sales in place |
(8.4) |
- |
- |
(8.4) |
||||
Production |
(122.2) |
(0.3) |
(0.2) |
(122.7) |
||||
Ending Reserves |
1,304.1 |
0.9 |
8.0 |
1,313.0 |
||||
NATURAL GAS LIQUIDS (MMBbl) |
||||||||
Beginning Reserves |
416.4 |
- |
- |
416.4 |
||||
Revisions |
46.9 |
- |
- |
46.9 |
||||
Purchases in place |
0.4 |
- |
- |
0.4 |
||||
Extensions, discoveries and other additions |
75.0 |
- |
- |
75.0 |
||||
Sales in place |
(2.9) |
- |
- |
(2.9) |
||||
Production |
(32.3) |
- |
- |
(32.3) |
||||
Ending Reserves |
503.5 |
- |
- |
503.5 |
||||
NATURAL GAS (Bcf) |
||||||||
Beginning Reserves |
3,021.2 |
280.9 |
15.8 |
3,317.9 |
||||
Revisions |
602.8 |
(27.4) |
8.6 |
584.0 |
||||
Purchases in place |
4.8 |
- |
- |
4.8 |
||||
Extensions, discoveries and other additions |
619.3 |
174.2 |
35.9 |
829.4 |
||||
Sales in place |
(56.4) |
- |
- |
(56.4) |
||||
Production |
(293.2) |
(114.3) |
(9.1) |
(416.6) |
||||
Ending Reserves |
3,898.5 |
313.4 |
51.2 |
4,263.1 |
||||
OIL EQUIVALENTS (MMBoe) |
||||||||
Beginning Reserves |
2,088.4 |
47.7 |
10.9 |
2,147.0 |
||||
Revisions |
205.3 |
(4.5) |
1.2 |
202.0 |
||||
Purchases in place |
2.3 |
- |
- |
2.3 |
||||
Extensions, discoveries and other additions |
385.4 |
29.3 |
6.1 |
420.8 |
||||
Sales in place |
(20.7) |
- |
- |
(20.7) |
||||
Production |
(203.4) |
(19.4) |
(1.6) |
(224.4) |
||||
Ending Reserves |
2,457.3 |
53.1 |
16.6 |
2,527.0 |
||||
Net Proved Developed Reserves (MMBoe) |
||||||||
At December 31, 2016 |
1,038.5 |
44.5 |
10.9 |
1,093.9 |
||||
At December 31, 2017 |
1,300.7 |
50.8 |
12.8 |
1,364.3 |
||||
2017 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Acquisition Cost of Unproved Properties |
$ 424.1 |
$ 2.4 |
$ - |
$ 426.5 |
||||
Exploration Costs |
144.5 |
62.6 |
16.5 |
223.6 |
||||
Development Costs |
3,540.7 |
107.2 |
13.2 |
3,661.1 |
||||
Total Drilling |
4,109.3 |
172.2 |
29.7 |
4,311.2 |
||||
Acquisition Cost of Proved Properties |
72.6 |
- |
- |
72.6 |
||||
Asset Retirement Costs |
50.2 |
2.3 |
3.1 |
55.6 |
||||
Total Exploration & Development Expenditures |
4,232.1 |
174.5 |
32.8 |
4,439.4 |
||||
Gathering, Processing and Other |
173.0 |
0.1 |
0.2 |
173.3 |
||||
Total Expenditures |
4,405.1 |
174.6 |
33.0 |
4,612.7 |
||||
Proceeds from Sales in Place |
(226.6) |
- |
- |
(226.6) |
||||
Net Expenditures |
$ 4,178.5 |
$ 174.6 |
$ 33.0 |
$ 4,386.1 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe ) * |
||||||||
All-in Total, Net of Revisions |
$ 6.58 |
$ 6.94 |
$ 4.07 |
$ 6.56 |
||||
All-in Total, Excluding Revisions Due to Price |
$ 8.88 |
$ 6.94 |
$ 4.07 |
$ 8.71 |
||||
RESERVE REPLACEMENT * |
||||||||
Drilling Only |
190% |
151% |
381% |
188% |
||||
All-in Total, Net of Revisions & Dispositions |
281% |
128% |
456% |
269% |
||||
All-in Total, Excluding Revisions Due to Price |
206% |
128% |
456% |
201% |
||||
All-in Total, Liquids |
244% |
133% |
-50% |
244% |
||||
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) | ||||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | ||||||||
(Unaudited; in millions, except ratio information) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including an "All-In" calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||
For the Twelve Months Ended December 31, 2017 |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 4,232.1 |
$ 174.5 |
$ 32.8 |
$ 4,439.4 |
||||
Less: Asset Retirement Costs |
(50.2) |
(2.3) |
(3.1) |
(55.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(255.7) |
- |
- |
(255.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(26.2) |
- |
- |
(26.2) |
||||
Total Exploration & Development Expenditures (Non-GAAP) (a) |
$ 3,900.0 |
$ 172.2 |
$ 29.7 |
$ 4,101.9 |
||||
Total Expenditures (GAAP) |
$ 4,405.1 |
$ 174.6 |
$ 33.0 |
$ 4,612.7 |
||||
Less: Asset Retirement Costs |
(50.2) |
(2.3) |
(3.1) |
(55.6) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(255.7) |
- |
- |
(255.7) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(26.2) |
- |
- |
(26.2) |
||||
Total Cash Expenditures (Non-GAAP) |
$ 4,073.0 |
$ 172.3 |
$ 29.9 |
$ 4,275.2 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||
Revisions due to price (b) |
154.0 |
- |
- |
154.0 |
||||
Revisions other than price |
51.3 |
(4.5) |
1.2 |
48.0 |
||||
Purchases in place |
2.3 |
- |
- |
2.3 |
||||
Extensions, discoveries and other additions (c) |
385.4 |
29.3 |
6.1 |
420.8 |
||||
Total Proved Reserve Additions (d) |
593.0 |
24.8 |
7.3 |
625.1 |
||||
Sales in place |
(20.7) |
- |
- |
(20.7) |
||||
Net Proved Reserve Additions From All Sources (e) |
572.3 |
24.8 |
7.3 |
604.4 |
||||
Production (f) |
203.4 |
19.4 |
1.6 |
224.4 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
All-in Total, Net of Revisions (a / d) |
$ 6.58 |
$ 6.94 |
$ 4.07 |
$ 6.56 |
||||
All-in Total, Excluding Revisions Due to Price (a / (d - b)) |
$ 8.88 |
$ 6.94 |
$ 4.07 |
$ 8.71 |
||||
RESERVE REPLACEMENT |
||||||||
Drilling Only (c / f) |
190% |
151% |
381% |
188% |
||||
All-in Total, Net of Revisions & Dispositions (e / f) |
281% |
128% |
456% |
269% |
||||
All-in Total, Excluding Revisions Due to Price ((e - b ) / f) |
206% |
128% |
456% |
201% |
||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
||||||||
Revisions |
104.9 |
0.1 |
(0.2) |
104.8 |
||||
Purchases in place |
1.5 |
- |
- |
1.5 |
||||
Extensions, discoveries and other additions (g) |
282.1 |
0.3 |
0.1 |
282.5 |
||||
Total Proved Reserve Additions |
388.5 |
0.4 |
(0.1) |
388.8 |
||||
Sales in place |
(11.3) |
- |
- |
(11.3) |
||||
Net Proved Reserve Additions From All Sources (h) |
377.2 |
0.4 |
(0.1) |
377.5 |
||||
Production (i) |
154.5 |
0.3 |
0.2 |
155.0 |
||||
RESERVE REPLACEMENT - LIQUIDS |
||||||||
Drilling Only (g / i) |
183% |
100% |
50% |
182% |
||||
All-in Total, Net of Revisions & Dispositions (h / i) |
244% |
133% |
-50% |
244% |
||||
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) | ||||||||
As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) | ||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | ||||||||
(Unaudited; in millions, except ratio information) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. |
||||||||
For the Twelve Months Ended December 31, 2017 |
||||||||
Total |
||||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 4,439.4 |
|||||||
Less: Asset Retirement Costs |
(55.6) |
|||||||
Acquisition Costs of Unproved Properties |
(426.5) |
|||||||
Acquisition Cost of Proved Properties |
(72.6) |
|||||||
Drillbit Exploration & Development Expenditures (Non-GAAP) (j) |
$ 3,884.7 |
|||||||
Total Proved Reserves - Extensions, discoveries and other additions (MMBoe) |
420.8 |
|||||||
Add: Conversion of proved undeveloped reserves to proved developed |
152.6 |
|||||||
Less: Proved undeveloped extensions and discoveries |
(237.4) |
|||||||
Proved Developed Reserves - Extensions and discoveries (MMBoe) |
336.0 |
|||||||
Total Proved Reserves - Revisions (MMBoe) |
202.0 |
|||||||
Less: Proved Undeveloped Reserves - Revisions |
(33.1) |
|||||||
Proved Developed - Revisions due to price |
(143.0) |
|||||||
Proved Developed Reserves - Revisions other than price (MMBoe) |
25.9 |
|||||||
Proved Developed Reserves - Extensions and discoveries plus revisions other than price (MMBoe) (k) |
361.9 |
|||||||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) |
$ 10.73 |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Midland Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through February 28, 2018 (closed) |
15,000 |
$ 1.063 | |||||||||
March 1, 2018 through December 31, 2018 |
15,000 |
1.063 | |||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 |
20,000 |
$ 1.075 | |||||||||
EOG has entered into additional crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 20, 2018. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Gulf Coast Differential Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through February 28, 2018 (closed) |
37,000 |
$ 3.818 | |||||||||
March 1, 2018 through December 31, 2018 |
37,000 |
3.818 | |||||||||
On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain 2017 crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the table below. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 20, 2018, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2017 |
|||||||||||
January 1, 2017 through February 28, 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
March 1, 2017 through June 30, 2017 (closed) |
30,000 |
50.05 | |||||||||
2018 |
|||||||||||
January 2018 (closed) |
134,000 |
$ 60.04 | |||||||||
February 1, 2018 through December 31, 2018 |
134,000 |
60.04 | |||||||||
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offset the remaining 2017 crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
30,000 |
$ 3.10 | |||||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
35,000 |
$ 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. | |||||||||||
In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 20, 2018, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume |
|||||||||||
(MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | ||||||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | ||||||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | ||||||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||||
2017 |
2016 |
2015 |
2014 |
2013 | ||||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||||||
Net Interest Expense (GAAP) |
$ |
274 |
$ |
282 |
$ |
237 |
$ |
201 |
||||||
Tax Benefit Imputed (based on 35%) |
(96) |
(99) |
(83) |
(70) |
||||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
178 |
$ |
183 |
$ |
154 |
$ |
131 |
||||||
Net Income (Loss) (GAAP) - (b) |
$ |
2,583 |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
(1,934) |
(a) |
204 |
(b) |
4,559 |
(c) |
(199) |
(d) |
||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
649 |
$ |
(893) |
$ |
34 |
$ |
2,716 |
||||||
Total Stockholders' Equity Before Retained Earnings Adjustment (GAAP) - (d) |
$ |
16,283 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | ||||
Less: Tax Reform Impact |
(2,169) |
- |
- |
- |
- | |||||||||
Total Stockholders' Equity (Non-GAAP) - (e) |
$ |
14,114 |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | ||||
Average Total Stockholders' Equity (GAAP) * - (f) |
$ |
15,133 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Average Total Stockholders' Equity (Non-GAAP) * - (g) |
$ |
14,048 |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Current and Long-Term Debt (GAAP) - (h) |
$ |
6,387 |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | ||||
Less: Cash |
(834) |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||||||
Net Debt (Non-GAAP) - (i) |
$ |
5,553 |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | ||||
Total Capitalization (GAAP) - (d) + (h) |
$ |
22,670 |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | ||||
Total Capitalization (Non-GAAP) - (e) + (i) |
$ |
19,667 |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | ||||
Average Total Capitalization (Non-GAAP) * - (j) |
$ |
19,518 |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (j) |
14.1% |
-4.8% |
-21.6% |
14.7% |
||||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (j) |
4.2% |
-3.7% |
0.9% |
13.7% |
||||||||||
Return on Equity (ROE) |
||||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (f) |
17.1% |
-8.1% |
-29.5% |
17.6% |
||||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (g) |
4.6% |
-6.6% |
0.2% |
16.4% |
||||||||||
* Average for the current and immediately preceding year |
||||||||||||||
Adjustments to Net Income (Loss) (GAAP) |
||||||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2017: |
||||||||||||||
Year Ended December 31, 2017 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(12) |
$ |
4 |
$ |
(8) |
||||||||
Add: Impairments of Certain Assets |
261 |
(93) |
168 |
|||||||||||
Add: Net Losses on Asset Dispositions |
99 |
(35) |
64 |
|||||||||||
Add: Legal Settlement - Early Lease Termination |
10 |
(4) |
6 |
|||||||||||
Add: Joint Venture Transaction Costs |
3 |
(1) |
2 |
|||||||||||
Add: Joint Interest Billings Deemed Uncollectible |
5 |
(2) |
3 |
|||||||||||
Less: Tax Reform Impact |
- |
(2,169) |
(2,169) |
|||||||||||
Total |
$ |
366 |
$ |
(2,300) |
$ |
(1,934) |
||||||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: |
||||||||||||||
Year Ended December 31, 2016 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 |
||||||||
Add: Impairments of Certain Assets |
321 |
(113) |
208 |
|||||||||||
Less: Net Gains on Asset Dispositions |
(206) |
62 |
(144) |
|||||||||||
Add: Trinidad Tax Settlement |
- |
43 |
43 |
|||||||||||
Add: Voluntary Retirement Expense |
42 |
(15) |
27 |
|||||||||||
Add: Acquisition - State Apportionment Change |
- |
16 |
16 |
|||||||||||
Add: Acquisition Costs |
5 |
- |
5 |
|||||||||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 |
||||||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
||||||||||||||
Year Ended December 31, 2015 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
||||||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
|||||||||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
|||||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
|||||||||||
Add: Severance Costs |
9 |
(3) |
6 |
|||||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
|||||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
||||||||
(d) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
||||||||||||||
Year Ended December 31, 2014 |
||||||||||||||
Before |
Income Tax |
After |
||||||||||||
Tax |
Impact |
Tax |
||||||||||||
Adjustments: |
||||||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
||||||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
|||||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
|||||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years |
- |
250 |
250 |
|||||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
First Quarter and Full Year 2018 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) First Quarter and Full Year 2018 Forecast |
|||||||||||
The forecast items for the first quarter and full year 2018 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
1Q 2018 |
Full Year 2018 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
350.0 |
- |
360.0 |
387.0 |
- |
401.0 | |||||
Trinidad |
0.5 |
- |
0.7 |
0.4 |
- |
0.6 | |||||
Other International |
0.0 |
- |
5.0 |
2.0 |
- |
4.0 | |||||
Total |
350.5 |
- |
365.7 |
389.4 |
- |
405.6 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
93.0 |
- |
103.0 |
100.0 |
- |
110.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
825 |
- |
865 |
900 |
- |
950 | |||||
Trinidad |
280 |
- |
310 |
250 |
- |
290 | |||||
Other International |
25 |
- |
35 |
28 |
- |
38 | |||||
Total |
1,130 |
- |
1,210 |
1,178 |
- |
1,278 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
580.5 |
- |
607.2 |
637.0 |
- |
669.3 | |||||
Trinidad |
47.2 |
- |
52.4 |
42.1 |
- |
48.9 | |||||
Other International |
4.2 |
- |
10.8 |
6.7 |
- |
10.3 | |||||
Total |
631.9 |
- |
670.4 |
685.8 |
- |
728.5 | |||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
1Q 2018 |
Full Year 2018 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.70 |
- |
$ |
5.10 |
$ |
4.20 |
- |
$ |
4.80 | |
Transportation Costs |
$ |
3.00 |
- |
$ |
3.50 |
$ |
2.75 |
- |
$ |
3.25 | |
Depreciation, Depletion and Amortization |
$ |
13.00 |
- |
$ |
13.40 |
$ |
13.10 |
- |
$ |
13.50 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
90 |
- |
$ |
120 |
$ |
375 |
- |
$ |
425 | |
General and Administrative |
$ |
100 |
- |
$ |
110 |
$ |
415 |
- |
$ |
445 | |
Gathering and Processing |
$ |
95 |
- |
$ |
105 |
$ |
430 |
- |
$ |
470 | |
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
27 |
- |
$ |
32 | |
Net Interest |
$ |
60 |
- |
$ |
62 |
$ |
234 |
- |
$ |
242 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.6% |
- |
7.0% |
6.5% |
- |
6.9% | |||||
Income Taxes |
|||||||||||
Effective Rate |
20% |
- |
25% |
20% |
- |
25% | |||||
Current Tax (Benefit) / Expense ($MM) |
$ |
(90) |
- |
$ |
(55) |
$ |
(310) |
- |
$ |
(270) | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
4,500 |
- |
$ |
4,800 | ||||||
Exploration and Development Facilities |
$ |
600 |
- |
$ |
650 | ||||||
Gathering, Processing and Other |
$ |
300 |
- |
$ |
350 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
0.00 |
- |
$ |
1.50 |
$ |
(1.00) |
- |
$ |
1.00 | |
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) | |
Other International - above (below) WTI |
$ |
0.00 |
- |
$ |
2.00 |
$ |
0.00 |
- |
$ |
2.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
39% |
- |
45% |
40% |
- |
46% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(0.40) |
- |
$ |
0.00 |
$ |
(0.60) |
- |
$ |
0.00 | |
Realizations |
|||||||||||
Trinidad |
$ |
2.50 |
- |
$ |
2.90 |
$ |
2.15 |
- |
$ |
2.75 | |
Other International |
$ |
4.15 |
- |
$ |
4.65 |
$ |
4.00 |
- |
$ |
5.00 | |
Definitions |
|||||||||||
$/Bbl |
U.S. Dollars per barrel |
||||||||||
$/Boe |
U.S. Dollars per barrel of oil equivalent |
||||||||||
$/Mcf |
U.S. Dollars per thousand cubic feet |
||||||||||
$MM |
U.S. Dollars in millions |
||||||||||
MBbld |
Thousand barrels per day |
||||||||||
MBoed |
Thousand barrels of oil equivalent per day |
||||||||||
MMcfd |
Million cubic feet per day |
||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
||||||||||
WTI |
West Texas Intermediate |
EOG RESOURCES, INC. | ||||||||||||||
Fourth Quarter 2017 Well Results by Play | ||||||||||||||
(Unaudited) | ||||||||||||||
Wells Completed |
Initial 30-Day Average Production Rate | |||||||||||||
Gross |
Net |
Lateral |
Crude Oil and |
Natural Gas |
Natural Gas |
Crude Oil | ||||||||
Delaware Basin |
||||||||||||||
Wolfcamp |
51 |
45 |
6,000 |
1,410 |
310 |
2.5 |
2,145 | |||||||
Bone Spring |
9 |
9 |
6,700 |
1,085 |
160 |
1.3 |
1,470 | |||||||
Leonard |
5 |
5 |
8,700 |
1,230 |
265 |
2.2 |
1,865 | |||||||
Powder River Basin Turner |
9 |
7 |
7,700 |
990 |
375 |
4.7 |
2,150 | |||||||
DJ Basin Codell |
3 |
2 |
9,100 |
950 |
105 |
0.4 |
1,120 | |||||||
South Texas Eagle Ford |
74 |
70 |
7,400 |
1,525 |
195 |
1.1 |
1,915 | |||||||
South Texas Austin Chalk |
4 |
4 |
5,300 |
2,280 |
430 |
2.5 |
3,130 | |||||||
(A) Barrels per day or million cubic feet per day, as applicable. | ||||||||||||||
(B) Barrels of oil equivalent per day; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. |
View original content:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2017-results-and-announces-2018-capital-program-300605294.html
SOURCE EOG Resources, Inc.
HOUSTON, Jan.18, 2018 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss fourth quarter and full year 2017 results on Wednesday, February 28, 2018, at 8 a.m. Central time (9 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
||
David J. Streit |
|||
(713) 571-4902 |
|||
W. John Wagner |
|||
(713) 571-4404 |
|||
Investors/Media |
|||
Kimberly M. Ehmer |
|||
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-webcast-of-fourth-quarter-and-full-year-2017-results-conference-call-for-february-28-2018-300584955.html
SOURCE EOG Resources, Inc.
HOUSTON, Dec. 14, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today announced that Lloyd W. "Billy" Helms, Jr. has been promoted to Chief Operating Officer and Ezra Y. Yacob has been promoted to Executive Vice President, Exploration and Production, effective December 13, 2017. Ezra will be responsible for EOG's Midland, San Antonio and Artesia operating areas.
Gary L. Thomas, most recently President and Chief Operating Officer, will continue serving as President of EOG to allow for the gradual transition of his responsibilities prior to his retirement. He is expected to retire by year-end 2018. Gary has been an EOG employee for 39 years, having joined a predecessor company in 1978 as a drilling and production engineer. Since 1998, he has held responsibility for managing EOG's overall drilling, completions, production and engineering activities.
"The two promotions announced today highlight EOG's deep bench of high-caliber leadership," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Both Billy and Ezra are proven leaders at EOG. Each has demonstrated exceptional management and technical leadership through years of strong performance in various roles across the company. Billy and Ezra both exemplify EOG's outstanding culture and track record of success."
Billy Helms, most recently Executive Vice President, Exploration and Production, has 36 years of service with EOG. Most recently, Billy has been responsible for EOG's operations in Midland, San Antonio and Artesia, along with the company's Engineering and Acquisition and Business Development functions. Before joining the headquarters executive management team in February 2012, he managed EOG's exploration and development activities in Canada and held positions of increasing responsibility in both the Midland and Houston offices. Billy joined an EOG predecessor company in 1981 and holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University.
Most recently Vice President and General Manager of EOG's Midland office, Ezra Yacob has 12 years of service with EOG and has managed the company's Permian Basin exploration and development activities since May 2014. Ezra has held various geoscience and leadership positions in EOG's Fort Worth and Midland offices since joining EOG in 2005. Prior to EOG, he worked at the United States Geological Survey for five years. Ezra holds a Bachelor of Science degree in Geology from the University of Puget Sound, a Master of Science degree in Geology from the Colorado School of Mines and a Master of Business Administration degree from the University of Texas at Tyler.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-announces-key-officer-promotions-300571427.html
SOURCE EOG Resources, Inc.
HOUSTON, Dec. 13, 2017 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable January 31, 2018, to stockholders of record as of January 17, 2018. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors David J. Streit (713) 571-4902 W. John Wagner (713) 571-4404
Media and Investors Kimberly M. Ehmer (713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-300571067.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 8, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Bank of America Merrill Lynch Global Energy Conference at 8 a.m. Central time (9 a.m. Eastern time) on Thursday, November 16. David W. Trice, Executive Vice President, Exploration and Production, will present on behalf of EOG.
Please visit the Investors/Overview page on the EOG website to access the live webcast. If you are unable to listen live, a replay will be available on the Investors/Presentations and Events page for three months.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
Investors:
David J. Streit
(713) 571-4902
W. John Wagner
(713) 571-4404
Media and Investors
Kimberly M. Ehmer
(713) 571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-energy-conference-300552339.html
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 2, 2017 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported third quarter 2017 net income of $100.5 million, or $0.17 per share. This compares to a third quarter 2016 net loss of $190.0 million, or $0.35 per share.
Adjusted non-GAAP net income for the third quarter 2017 was $111.3 million, or $0.19 per share, compared to an adjusted non-GAAP net loss of $220.8 million, or $0.40 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching commodity derivative contract realizations to settlement months and making certain other adjustments in order to exclude non-recurring items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Increased crude oil volumes, higher crude oil, natural gas liquids (NGLs) and natural gas prices and lower transportation expense resulted in increases to discretionary cash flow and EBITDAX during the third quarter 2017 compared to the third quarter 2016. In addition to the items listed above, lower impairment and depreciation, depletion and amortization expenses resulted in increased adjusted non-GAAP net income during the quarter. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
In the third quarter 2017, EOG expanded its premium inventory to approximately 8,000 net drilling locations from 7,200. As a result, EOG's total premium net resource potential increased 12 percent to 7.3 billion barrels of oil equivalent. The additional net premium locations include 540 in the Delaware Basin First Bone Spring and 260 in the Woodford Oil Window. Premium inventory is defined by well locations that generate a minimum 30 percent direct after-tax rate of return assuming a $40 crude oil price.
EOG grew third quarter total crude oil volumes 16 percent to 327,900 barrels of oil per day (Bopd). Production curtailments and completion delays due to Hurricane Harvey reduced crude oil volumes approximately 15,000 Bopd during the quarter. Natural gas and NGL production exceeded target midpoints, contributing to 8 percent total company production growth compared to the third quarter 2016.
During the third quarter 2017, lease and well expenses on a per-unit basis increased 4 percent compared to the same prior-year period, primarily because of higher per-unit operating costs from properties acquired in the Yates transaction and increased operating and maintenance expenses in the United Kingdom. Per-unit transportation costs decreased 15 percent year-over-year, due to the expiration of legacy transportation agreements and increased infrastructure to handle higher production volumes. Per-unit depreciation, depletion and amortization expenses decreased 13 percent compared to the same prior-year period due to the addition of reserves from premium wells with lower finding and development costs.
EOG now expects to complete approximately 505 net wells in 2017, an increase from its original outlook of 480 net wells. The company achieved lower completed well costs across its operations in 2017, as continued efficiencies and legacy service contract expirations offset service price increases. EOG is targeting 20 percent U.S. crude oil growth and expects to fund capital expenditures and the dividend using discretionary cash flow.
"Since the start of the year, EOG has added 2,000 net premium locations to its inventory. This is four times the number of wells we expect to complete for all of 2017," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG is an organic, exploration-driven machine. We have amassed an enormous, high-quality portfolio of assets by capturing sweet-spot acreage in the best oil plays in the U.S. Combined with our consistent operational proficiency and innovative technology, this gives us great confidence in the long-term sustainability of our unique premium growth and high-return model."
Woodford Oil Window
EOG added to its growing roster of premium plays with the introduction of a 50,000 net acre position in the Woodford oil window of the Eastern Anadarko Basin. Located primarily in McClain County, Oklahoma, EOG is targeting the black-oil window of the Woodford formation. The contiguous acreage position was amassed through an organic leasing program conducted over the past four years at an average cost of $750 per acre. EOG has completed three horizontal exploration wells in the play since June 2016. The most recent well, the Curry 21X #1VH, was brought to sales in the third quarter with a treated lateral length of 10,500 feet and 30-day initial production rate of 1,730 barrels of oil equivalent per day (Boed), or 1,460 Bopd, 165 barrels per day (Bpd) of NGLs and 0.6 million cubic feet per day (MMcfd) of natural gas. Completed well costs are targeted at $7.8 million for a 9,500 foot lateral. Benefiting from a shallow initial decline rate, EOG estimates reserves per well are 800 thousand barrels of oil equivalent (MBoe), net after royalty, with a 70 percent oil mix. The company has identified 260 net drilling locations with estimated net resource potential of 210 million barrels of oil equivalent (MMBoe). EOG estimates all 260 of these locations are premium, and plans to ramp activity in the play in 2018.
Delaware Basin
EOG added to its inventory of prolific plays in the Delaware Basin with the introduction of the First Bone Spring. Approximately 100,000 net acres in EOG's Northern Delaware Basin footprint are prospective for this high rate-of-return oil play. The company identified an initial 555 net locations, with estimated net resource potential of 540 MMBoe. EOG completed 15 net First Bone Spring wells in the past three years, with strong results and premium returns across a large portion of its acreage position. All 540 net remaining drilling locations have premium rate of return potential. Reserves per well are estimated to be 975 MBoe, net after royalty, with a 55 percent oil mix. Targeted well cost is $7.3 million for a 7,000 foot lateral well.
EOG continues to deepen its technical knowledge of the Delaware Basin. Drilling during the third quarter was aimed at further understanding development criteria for the large stacked-pay resource in the basin. EOG conducted a number of spacing tests to optimize development, and continued to test additional zones for future premium potential. EOG now expects to complete an additional 15 net wells in the Delaware Basin during 2017 for a total of 155 net wells, including 10 net wells in the First Bone Spring.
EOG completed 22 gross (20 net) wells in the Delaware Basin Wolfcamp in the third quarter with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 2,470 Boed, or 1,620 Bopd, 380 Bpd of NGLs and 2.8 MMcfd of natural gas. In Lea County, NM, EOG completed a three-well pattern, the Antietam 9 Fed Com 701-703H, with an average treated lateral length of 7,000 feet per well and average 30-day initial production rates per well of 4,145 Boed, or 2,725 Bopd, 640 Bpd of NGLs and 4.7 MMcfd of natural gas.
In the Delaware Basin Bone Spring plays, EOG completed nine gross (six net) wells in the third quarter with an average treated lateral length of 6,800 feet per well and average 30-day initial production rates per well of 1,125 Boed, or 840 Bopd, 125 Bpd of NGLs and 0.9 MMcfd of natural gas. In Lea County, NM, EOG completed the Righteous 6 State Com 601Y, with a treated lateral length of 7,100 feet and a 30-day initial production rate of 2,160 Boed, or 1,740 Bopd, 190 Bpd of NGLs and 1.4 MMcfd of natural gas.
In the Delaware Basin Leonard, EOG completed nine gross (nine net) wells in the third quarter with an average treated lateral length of 4,800 feet per well and average 30-day initial production rates per well of 1,725 Boed, or 800 Bopd, 415 Bpd of NGLs and 3.0 MMcfd of natural gas.
Bakken and Rockies
EOG completed 20 gross (19 net) wells in the Powder River Basin Turner during the third quarter, with an average treated lateral length of 7,600 feet per well and average 30-day initial production rates per well of 1,630 Boed, or 1,040 Bopd, 185 Bpd of NGLs and 2.4 MMcfd of natural gas. Encouraging tests of new targets and ongoing delineation of its 400,000 net acre position have prompted EOG to increase its activity, with five additional wells planned during 2017 for a total of 35 net wells. The combination of low completed well costs, robust well productivity and moderate initial decline rates make the Powder River Basin competitive with the best performing assets at EOG.
In the DJ Basin, EOG completed seven gross (two net) wells targeting the Codell formation in the third quarter with an average treated lateral length of 9,400 feet per well and average 30-day initial production rates per well of 790 Boed, or 665 Bopd, 75 Bpd of NGLs and 0.3 MMcfd of natural gas.
EOG completed its planned 35 net well program in the North Dakota Bakken in the first half of 2017, and limited drilling activity is scheduled for the remainder of 2017.
South Texas Eagle Ford
EOG's South Texas Eagle Ford remained resilient during the third quarter, as robust infrastructure and comprehensive technology and communication assets enabled EOG to manage operations in a safe and efficient manner during Hurricane Harvey. Ongoing efficiency improvements have enabled EOG to add five net wells to its planned 2017 completions, for a total of 200 net wells.
In the third quarter, EOG completed 44 gross (39 net) wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 1,685 Boed, or 1,340 Bopd, 175 Bpd of NGLs and 1.0 MMcfd of natural gas. In Gonzales County, EOG completed a four-well pattern, the Angus Unit 6H-9H, with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 3,945 Boed, or 2,995 Bopd, 480 Bpd of NGLs and 2.8 MMcfd of natural gas.
South Texas Austin Chalk
In the third quarter, EOG continued to delineate the South Texas Austin Chalk. EOG completed eight gross (eight net) wells in Karnes County with an average treated lateral length of 6,000 feet per well and average 30-day initial production rates per well of 4,440 Boed, or 3,195 Bopd, 630 Bpd of NGLs and 3.7 MMcfd of natural gas. Notably, EOG completed the Elbrus Unit 103H with a lateral length of 3,700 feet and 30-day initial production rate of 7,760 Boed, or 5,425 Bopd, 1,185 Bpd of NGLs and 6.9 MMcfd of natural gas.
Hedging Activity
During the third quarter ended September 30, 2017, EOG did not enter into any additional crude oil or natural gas derivative contracts.
A comprehensive summary of EOG's crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At September 30, 2017, EOG's total debt outstanding was $6.4 billion for a debt-to-total capitalization ratio of 31 percent. Considering cash on the balance sheet at the end of the third quarter, EOG's net debt was $5.5 billion for a net debt-to-total capitalization ratio of 28 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales in the first nine months of 2017 totaled $192 million.
Conference Call November 3, 2017
EOG's third quarter 2017 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 3, 2017. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website for one year.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Net Operating Revenues and Other |
$ |
2,644.8 |
$ |
2,118.5 |
$ |
7,867.9 |
$ |
5,248.6 | |||
Net Income (Loss) |
$ |
100.5 |
$ |
(190.0) |
$ |
152.1 |
$ |
(954.3) | |||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
0.17 |
$ |
(0.35) |
$ |
0.26 |
$ |
(1.74) | |||
Diluted |
$ |
0.17 |
$ |
(0.35) |
$ |
0.26 |
$ |
(1.74) | |||
Average Number of Common Shares |
|||||||||||
Basic |
574.8 |
547.8 |
574.4 |
547.3 | |||||||
Diluted |
578.7 |
547.8 |
578.5 |
547.3 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Net Operating Revenues and Other |
|||||||||||
Crude Oil and Condensate |
$ |
1,451,410 |
$ |
1,137,717 |
$ |
4,326,925 |
$ |
2,951,118 | |||
Natural Gas Liquids |
180,038 |
112,439 |
480,389 |
299,401 | |||||||
Natural Gas |
220,402 |
205,293 |
675,012 |
526,779 | |||||||
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts |
(6,606) |
5,117 |
64,860 |
(33,821) | |||||||
Gathering, Processing and Marketing |
784,368 |
532,456 |
2,289,702 |
1,351,665 | |||||||
Gains (Losses) on Asset Dispositions, Net |
(8,202) |
108,204 |
(33,876) |
101,801 | |||||||
Other, Net |
23,434 |
17,278 |
64,869 |
51,650 | |||||||
Total |
2,644,844 |
2,118,504 |
7,867,881 |
5,248,593 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
251,943 |
226,348 |
762,906 |
685,606 | |||||||
Transportation Costs |
183,565 |
200,862 |
548,635 |
570,787 | |||||||
Gathering and Processing Costs |
32,590 |
32,635 |
105,480 |
90,385 | |||||||
Exploration Costs |
30,796 |
25,455 |
122,401 |
85,843 | |||||||
Dry Hole Costs |
50 |
10,390 |
77 |
10,464 | |||||||
Impairments |
53,677 |
177,990 |
325,798 |
322,321 | |||||||
Marketing Costs |
793,536 |
552,487 |
2,320,671 |
1,373,387 | |||||||
Depreciation, Depletion and Amortization |
846,222 |
899,511 |
2,527,642 |
2,690,893 | |||||||
General and Administrative |
111,717 |
94,397 |
317,462 |
292,633 | |||||||
Taxes Other Than Income |
125,912 |
91,909 |
386,319 |
246,068 | |||||||
Total |
2,430,008 |
2,311,984 |
7,417,391 |
6,368,387 | |||||||
Operating Income (Loss) |
214,836 |
(193,480) |
450,490 |
(1,119,794) | |||||||
Other Income (Expense), Net |
226 |
(7,912) |
8,349 |
(33,345) | |||||||
Income (Loss) Before Interest Expense and Income Taxes |
215,062 |
(201,392) |
458,839 |
(1,153,139) | |||||||
Interest Expense, Net |
69,082 |
70,858 |
211,010 |
210,356 | |||||||
Income (Loss) Before Income Taxes |
145,980 |
(272,250) |
247,829 |
(1,363,495) | |||||||
Income Tax Provision (Benefit) |
45,439 |
(82,250) |
95,718 |
(409,161) | |||||||
Net Income (Loss) |
$ |
100,541 |
$ |
(190,000) |
$ |
152,111 |
$ |
(954,334) | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.5025 |
$ |
0.5025 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2017 |
2016 |
2017 |
2016 | ||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
327.1 |
275.7 |
324.3 |
269.0 | |||||||
Trinidad |
0.8 |
0.7 |
0.8 |
0.8 | |||||||
Other International (B) |
- |
6.2 |
1.0 |
3.0 | |||||||
Total |
327.9 |
282.6 |
326.1 |
272.8 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
48.06 |
$ |
43.66 |
$ |
48.61 |
$ |
39.53 | |||
Trinidad |
39.42 |
34.81 |
40.24 |
31.36 | |||||||
Other International (B) |
- |
43.53 |
51.55 |
35.30 | |||||||
Composite |
48.11 |
43.63 |
48.60 |
39.46 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
87.4 |
81.9 |
84.3 |
81.9 | |||||||
Other International (B) |
- |
- |
- |
- | |||||||
Total |
87.4 |
81.9 |
84.3 |
81.9 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
22.38 |
$ |
14.92 |
$ |
20.87 |
$ |
13.34 | |||
Other International (B) |
- |
- |
- |
- | |||||||
Composite |
22.38 |
14.92 |
20.87 |
13.34 | |||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
748 |
791 |
744 |
813 | |||||||
Trinidad |
323 |
329 |
317 |
346 | |||||||
Other International (B) |
25 |
24 |
22 |
25 | |||||||
Total |
1,096 |
1,144 |
1,083 |
1,184 | |||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
2.20 |
$ |
1.94 |
$ |
2.22 |
$ |
1.46 | |||
Trinidad |
2.04 |
1.86 |
2.33 |
1.88 | |||||||
Other International (B) |
3.74 |
3.74 |
3.72 |
3.57 | |||||||
Composite |
2.19 |
1.95 |
2.28 |
1.62 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
539.2 |
489.4 |
532.6 |
486.4 | |||||||
Trinidad |
54.6 |
55.6 |
53.6 |
58.5 | |||||||
Other International (B) |
4.3 |
10.2 |
4.8 |
7.2 | |||||||
Total |
598.1 |
555.2 |
591.0 |
552.1 | |||||||
Total MMBoe (D) |
55.0 |
51.1 |
161.3 |
151.3 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
September 30, |
December 31, | ||||
2017 |
2016 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
846,138 |
$ |
1,599,895 | |
Accounts Receivable, Net |
1,243,535 |
1,216,320 | |||
Inventories |
344,016 |
350,017 | |||
Assets from Price Risk Management Activities |
3,297 |
- | |||
Income Taxes Receivable |
126,881 |
12,305 | |||
Other |
200,096 |
206,679 | |||
Total |
2,763,963 |
3,385,216 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
51,716,999 |
49,592,091 | |||
Other Property, Plant and Equipment |
3,934,137 |
4,008,564 | |||
Total Property, Plant and Equipment |
55,651,136 |
53,600,655 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(29,926,547) |
(27,893,577) | |||
Total Property, Plant and Equipment, Net |
25,724,589 |
25,707,078 | |||
Deferred Income Taxes |
17,406 |
16,140 | |||
Other Assets |
299,347 |
190,767 | |||
Total Assets |
$ |
28,805,305 |
$ |
29,299,201 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,635,711 |
$ |
1,511,826 | |
Accrued Taxes Payable |
180,277 |
118,411 | |||
Dividends Payable |
96,349 |
96,120 | |||
Liabilities from Price Risk Management Activities |
2,827 |
61,817 | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
258,281 |
232,538 | |||
Total |
2,180,024 |
2,027,291 | |||
Long-Term Debt |
6,380,427 |
6,979,779 | |||
Other Liabilities |
1,215,113 |
1,282,142 | |||
Deferred Income Taxes |
5,107,477 |
5,028,408 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at September 30, 2017, 640,000,000 Shares Authorized at December 31, 2016, 578,570,621 Shares Issued at September 30, 2017 and 576,950,272 Shares Issued at December 31, 2016 |
205,786 |
205,770 | |||
Additional Paid in Capital |
5,513,631 |
5,420,385 | |||
Accumulated Other Comprehensive Loss |
(17,160) |
(19,010) | |||
Retained Earnings |
8,259,971 |
8,398,118 | |||
Common Stock Held in Treasury, 429,424 Shares at September 30, 2017 and 250,155 Shares at December 31, 2016 |
(39,964) |
(23,682) | |||
Total Stockholders' Equity |
13,922,264 |
13,981,581 | |||
Total Liabilities and Stockholders' Equity |
$ |
28,805,305 |
$ |
29,299,201 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Nine Months Ended | |||||
September 30, | |||||
2017 |
2016 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
152,111 |
$ |
(954,334) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
2,527,642 |
2,690,893 | |||
Impairments |
325,798 |
322,321 | |||
Stock-Based Compensation Expenses |
101,537 |
97,072 | |||
Deferred Income Taxes |
114,850 |
(492,489) | |||
(Gains) Losses on Asset Dispositions, Net |
33,876 |
(101,801) | |||
Other, Net |
(4,514) |
42,149 | |||
Dry Hole Costs |
77 |
10,464 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(64,860) |
33,821 | |||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
4,730 |
(22,219) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
(22,071) | |||
Other, Net |
270 |
7,513 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(25,445) |
(11,860) | |||
Inventories |
(17,674) |
137,563 | |||
Accounts Payable |
112,894 |
(201,213) | |||
Accrued Taxes Payable |
(49,967) |
113,996 | |||
Other Assets |
(83,940) |
(12,526) | |||
Other Liabilities |
(69,224) |
36,799 | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
(120,373) |
(119,760) | |||
Net Cash Provided by Operating Activities |
2,937,788 |
1,554,318 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(2,927,988) |
(1,781,547) | |||
Additions to Other Property, Plant and Equipment |
(139,558) |
(60,343) | |||
Proceeds from Sales of Assets |
191,593 |
457,665 | |||
Changes in Components of Working Capital Associated with Investing Activities |
120,469 |
120,614 | |||
Net Cash Used in Investing Activities |
(2,755,484) |
(1,263,611) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
- |
(259,718) | |||
Long-Term Debt Borrowings |
- |
991,097 | |||
Long-Term Debt Repayments |
(600,000) |
(400,000) | |||
Dividends Paid |
(289,261) |
(276,726) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
22,071 | |||
Treasury Stock Purchased |
(50,374) |
(55,641) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
11,174 |
14,283 | |||
Debt Issuance Costs |
- |
(1,602) | |||
Repayment of Capital Lease Obligation |
(4,897) |
(4,746) | |||
Other, Net |
(96) |
(854) | |||
Net Cash (Used in) Provided by Financing Activities |
(933,454) |
28,164 | |||
Effect of Exchange Rate Changes on Cash |
(2,607) |
11,350 | |||
Increase (Decrease) in Cash and Cash Equivalents |
(753,757) |
330,221 | |||
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 | |||
Cash and Cash Equivalents at End of Period |
$ |
846,138 |
$ |
1,048,727 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
To Net Income (Loss) (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and 2016, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back acquisition costs related to the Yates Transaction in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017 and to add back the transaction costs for the formation of a joint venture in 2017. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
September 30, 2017 |
September 30, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$145,980 |
$ (45,439) |
$100,541 |
$ 0.17 |
$ (272,250) |
$ 82,250 |
$(190,000) |
$ (0.35) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts |
6,606 |
(2,368) |
4,238 |
0.01 |
(5,117) |
1,824 |
(3,293) |
(0.01) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
2,139 |
(767) |
1,372 |
- |
(25,071) |
8,938 |
(16,133) |
(0.03) | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
8,202 |
(3,068) |
5,134 |
0.01 |
(108,204) |
28,802 |
(79,402) |
(0.13) | |||||||
Add: Impairments |
- |
- |
- |
- |
102,778 |
(36,640) |
66,138 |
0.12 | |||||||
Add: Acquisition Costs |
- |
- |
- |
- |
2,927 |
(1,043) |
1,884 |
- | |||||||
Adjustments to Net Income (Loss) |
16,947 |
(6,203) |
10,744 |
0.02 |
(32,687) |
1,881 |
(30,806) |
(0.05) | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$162,927 |
$ (51,642) |
$111,285 |
$ 0.19 |
$ (304,937) |
$ 84,131 |
$(220,806) |
$ (0.40) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,783 |
547,838 | |||||||||||||
Diluted |
578,736 |
547,838 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
574,783 |
547,838 | |||||||||||||
Diluted |
578,736 |
547,838 | |||||||||||||
Nine Months Ended |
Nine Months Ended | ||||||||||||||
September 30, 2017 |
September 30, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$247,829 |
$ (95,718) |
$152,111 |
$ 0.26 |
$(1,363,495) |
$409,161 |
$(954,334) |
$ (1.74) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity Derivative Contracts |
(64,860) |
23,249 |
(41,611) |
(0.07) |
33,821 |
(12,057) |
21,764 |
0.04 | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
4,730 |
(1,695) |
3,035 |
0.01 |
(22,219) |
7,921 |
(14,298) |
(0.03) | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
33,876 |
(11,955) |
21,921 |
0.04 |
(101,801) |
24,635 |
(77,166) |
(0.14) | |||||||
Add: Impairments |
161,148 |
(57,764) |
103,384 |
0.18 |
102,778 |
(36,640) |
66,138 |
0.12 | |||||||
Add: Trinidad Tax Settlement |
- |
- |
- |
- |
- |
43,000 |
43,000 |
0.08 | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
42,054 |
(14,992) |
27,062 |
0.05 | |||||||
Add: Acquisition Costs |
- |
- |
- |
- |
2,927 |
(1,043) |
1,884 |
- | |||||||
Add: Legal Settlement - Early Lease Termination |
10,202 |
(3,657) |
6,545 |
0.01 |
- |
- |
- |
- | |||||||
Add: Joint Venture Transaction Costs |
3,056 |
(1,095) |
1,961 |
- |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
148,152 |
(52,917) |
95,235 |
0.17 |
57,560 |
10,824 |
68,384 |
0.12 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$395,981 |
$(148,635) |
$247,346 |
$ 0.43 |
$(1,305,935) |
$419,985 |
$(885,950) |
$ (1.62) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,370 |
547,295 | |||||||||||||
Diluted |
578,453 |
547,295 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
574,370 |
547,295 | |||||||||||||
Diluted |
578,453 |
547,295 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and nine-month periods ended September 30, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Nine Months Ended | |||||||||||
September 30, |
September 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
961,363 |
$ |
759,581 |
$ |
2,937,788 |
$ |
1,554,318 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
26,132 |
21,384 |
106,268 |
70,268 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
- |
10,260 |
- |
22,071 | ||||||||
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||
Accounts Receivable |
129,231 |
(10,712) |
25,445 |
11,860 | ||||||||
Inventories |
11,545 |
(41,750) |
17,674 |
(137,563) | ||||||||
Accounts Payable |
(36,190) |
(2,145) |
(112,894) |
201,213 | ||||||||
Accrued Taxes Payable |
10,843 |
(20,676) |
49,967 |
(113,996) | ||||||||
Other Assets |
22,851 |
(21,063) |
83,940 |
12,526 | ||||||||
Other Liabilities |
2,355 |
(35,234) |
69,224 |
(36,799) | ||||||||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
41,235 |
65,307 |
120,373 |
119,760 | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,169,365 |
$ |
724,952 |
$ |
3,297,785 |
$ |
1,703,658 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
61% |
94% |
||||||||||
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | ||||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | ||||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | ||||||||||||
(Non-GAAP) to Net Income (Loss) (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions (Net). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||
Three Months Ended |
Nine Months Ended | |||||||||||
September 30, |
September 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Income (Loss) (GAAP) |
$ |
100,541 |
$ |
(190,000) |
$ |
152,111 |
$ |
(954,334) | ||||
Adjustments: |
||||||||||||
Interest Expense, Net |
69,082 |
70,858 |
211,010 |
210,356 | ||||||||
Income Tax Provision (Benefit) |
45,439 |
(82,250) |
95,718 |
(409,161) | ||||||||
Depreciation, Depletion and Amortization |
846,222 |
899,511 |
2,527,642 |
2,690,893 | ||||||||
Exploration Costs |
30,796 |
25,455 |
122,401 |
85,843 | ||||||||
Dry Hole Costs |
50 |
10,390 |
77 |
10,464 | ||||||||
Impairments |
53,677 |
177,990 |
325,798 |
322,321 | ||||||||
EBITDAX (Non-GAAP) |
1,145,807 |
911,954 |
3,434,757 |
1,956,382 | ||||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
6,606 |
(5,117) |
(64,860) |
33,821 | ||||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
2,139 |
(25,071) |
4,730 |
(22,219) | ||||||||
(Gains) Losses on Asset Dispositions, Net |
8,202 |
(108,204) |
33,876 |
(101,801) | ||||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,162,754 |
$ |
773,562 |
$ |
3,408,503 |
$ |
1,866,183 | ||||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
50% |
83% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
September 30, |
December 31, | ||||
2017 |
2016 | ||||
Total Stockholders' Equity - (a) |
$ |
13,922 |
$ |
13,982 | |
Current and Long-Term Debt (GAAP) - (b) |
6,387 |
6,986 | |||
Less: Cash |
(846) |
(1,600) | |||
Net Debt (Non-GAAP) - (c) |
5,541 |
5,386 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
20,309 |
$ |
20,968 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,463 |
$ |
19,368 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
31% |
33% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
28% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts through November 2, 2017. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Crude Oil Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through December 31, 2018 |
15,000 |
$ 1.063 | |||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 |
20,000 |
$ 1.075 | |||||||||
On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through November 2, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2017 |
|||||||||||
January 1, 2017 through February 28, 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
March 1, 2017 through June 30, 2017 (closed) |
30,000 |
50.05 | |||||||||
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through November 2, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
30,000 |
$ 3.10 | |||||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
35,000 |
$ 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through November 2, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through November 2, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume |
|||||||||||
(MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 (closed) |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
2016 |
2015 |
2014 |
2013 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
282 |
$ |
237 |
$ |
201 |
|||||
Tax Benefit Imputed (based on 35%) |
(99) |
(83) |
(70) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
183 |
$ |
154 |
$ |
131 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
|||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
204 |
(a) |
4,559 |
(b) |
(199) |
(c) |
|||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
(893) |
$ |
34 |
$ |
2,716 |
|||||
Total Stockholders' Equity - (d) |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | |||
Average Total Stockholders' Equity * - (e) |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | |||
Less: Cash |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-4.8% |
-21.6% |
14.7% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
-3.7% |
0.9% |
13.7% |
||||||||
Return on Equity (ROE) |
|||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (e) |
-8.1% |
-29.5% |
17.6% |
||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (e) |
-6.6% |
0.2% |
16.4% |
||||||||
* Average for the current and immediately preceding year |
|||||||||||
Adjustments to Net Income (Loss) (GAAP) |
|||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: |
|||||||||||
Year Ended December 31, 2016 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 |
|||||
Add: Impairments of Certain Assets |
321 |
(113) |
208 |
||||||||
Less: Net Gains on Asset Dispositions |
(206) |
62 |
(144) |
||||||||
Add: Trinidad Tax Settlement |
- |
43 |
43 |
||||||||
Add: Voluntary Retirement Expense |
42 |
(15) |
27 |
||||||||
Add: Acquisition - State Apportionment Change |
- |
16 |
16 |
||||||||
Add: Acquisition Costs |
5 |
- |
5 |
||||||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 |
|||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
|||||||||||
Year Ended December 31, 2015 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
|||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
||||||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
||||||||
Add: Severance Costs |
9 |
(3) |
6 |
||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
|||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
|||||||||||
Year Ended December 31, 2014 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
|||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years |
- |
250 |
250 |
||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
Fourth Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Fourth Quarter and Full Year 2017 Forecast | |||||||||||
The forecast items for the fourth quarter and full year 2017 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
4Q 2017 |
Full Year 2017 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
362.0 |
- |
370.0 |
334.0 |
- |
336.0 | |||||
Trinidad |
0.5 |
- |
0.7 |
0.7 |
- |
0.8 | |||||
Other International |
0.0 |
- |
0.0 |
0.8 |
- |
0.8 | |||||
Total |
362.5 |
- |
370.7 |
335.5 |
- |
337.6 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
84.0 |
- |
94.0 |
84.2 |
- |
86.8 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
780 |
- |
820 |
753 |
- |
763 | |||||
Trinidad |
290 |
- |
330 |
310 |
- |
320 | |||||
Other International |
20 |
- |
35 |
22 |
- |
26 | |||||
Total |
1,090 |
- |
1,185 |
1,085 |
- |
1,109 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
576.0 |
- |
600.7 |
543.7 |
- |
550.0 | |||||
Trinidad |
48.8 |
- |
55.7 |
52.4 |
- |
54.2 | |||||
Other International |
3.3 |
- |
5.8 |
4.4 |
- |
5.0 | |||||
Total |
628.1 |
- |
662.2 |
600.5 |
- |
609.2 | |||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
4Q 2017 |
Full Year 2017 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.10 |
- |
$ |
4.50 |
$ |
4.56 |
- |
$ |
4.70 | |
Transportation Costs |
$ |
3.15 |
- |
$ |
3.65 |
$ |
3.33 |
- |
$ |
3.47 | |
Depreciation, Depletion and Amortization |
$ |
15.15 |
- |
$ |
15.70 |
$ |
15.52 |
- |
$ |
15.67 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
90 |
- |
$ |
120 |
$ |
377 |
- |
$ |
407 | |
General and Administrative |
$ |
100 |
- |
$ |
110 |
$ |
404 |
- |
$ |
414 | |
Gathering and Processing |
$ |
35 |
- |
$ |
38 |
$ |
140 |
- |
$ |
143 | |
Capitalized Interest |
$ |
5 |
- |
$ |
7 |
$ |
26 |
- |
$ |
28 | |
Net Interest |
$ |
62 |
- |
$ |
64 |
$ |
273 |
- |
$ |
275 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.1% |
- |
6.5% |
6.7% |
- |
6.9% | |||||
Income Taxes |
|||||||||||
Effective Rate |
36% |
- |
41% |
36% |
- |
41% | |||||
Current Taxes ($MM) |
$ |
(10) |
- |
$ |
25 |
$ |
(30) |
- |
$ |
5 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
3,000 |
- |
$ |
3,350 | ||||||
Exploration and Development Facilities |
$ |
475 |
- |
$ |
510 | ||||||
Gathering, Processing and Other |
$ |
225 |
- |
$ |
240 | ||||||
Pricing - (Refer toBenchmark Commodity Pricingin text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
0.25 |
- |
$ |
2.25 |
$ |
(0.55) |
- |
$ |
0.00 | |
Trinidad - above (below) WTI |
$ |
(10.50) |
- |
$ |
(9.50) |
$ |
(9.47) |
- |
$ |
(9.27) | |
Other International - above (below) WTI |
$ |
(5.00) |
- |
$ |
(3.00) |
$ |
(5.00) |
- |
$ |
(4.50) | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
36% |
- |
42% |
41% |
- |
42% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.15) |
- |
$ |
(0.75) |
$ |
(0.97) |
- |
$ |
(0.86) | |
Realizations |
|||||||||||
Trinidad |
$ |
1.90 |
- |
$ |
2.30 |
$ |
2.22 |
- |
$ |
2.32 | |
Other International |
$ |
3.95 |
- |
$ |
4.45 |
$ |
3.79 |
- |
$ |
3.94 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX U.S. New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 21, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss third quarter 2017 results on Friday, November 3, 2017, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-schedules-webcast-of-third-quarter-2017-results-conference-call-for-november-3-2017-300524102.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 20, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) today announced the appointment of C. Christopher Gaut to its Board of Directors, effective October 1, 2017. Gaut most recently served as Chairman and Chief Executive Officer of Forum Energy Technologies, Inc. (Forum), a publicly traded oilfield manufacturing company, from 2010 through May of this year, and continues to serve as Executive Chairman of Forum. Gaut also serves as a director of Ensco plc (Ensco) and Key Energy Services, Inc.
"We are excited to add someone with Cris' extensive oilfield service industry experience to the EOG team," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "He brings years of financial and operational experience from both public and private company perspectives. We are very pleased to welcome Cris to the EOG Board of Directors."
Prior to Forum, Gaut was a Managing Director of SCF Partners (SCF), a private equity firm investing in oilfield service and equipment companies, from 2009 to 2010. Prior to SCF, Gaut worked for Halliburton Company (Halliburton) for six years, first as Executive Vice President and Chief Financial Officer, then as President of Drilling and Evaluation. Prior to Halliburton, Gaut was Ensco's Senior Vice President and Chief Financial Officer for more than 15 years. Gaut also served as Co-Chief Operating Officer during his final year with Ensco.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-appoints-c-christopher-gaut-to-board-of-directors-300523165.html
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 19, 2017 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable October 31, 2017, to stockholders of record as of October 17, 2017. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
View original content:http://www.prnewswire.com/news-releases/eog-resources-declares-quarterly-dividend-on-common-stock-300522388.html
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 30, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Barclays Global CEO Energy-Power Conference. Sandeep Bhakhri, Senior Vice President and Chief Information and Technology Officer, will present at 3:25 p.m. Central time (4:25 p.m. Eastern time) on Tuesday, September 5. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present at 6:45 a.m. Central time (7:45 a.m. Eastern time) on Wednesday, September 6.
EOG is also scheduled to present at the UBS Houston Energy Bus-Less Tour at 7:30 a.m. Central time on Thursday, September 14. Lloyd W. "Billy" Helms, Jr., Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the Wolfe Research Oil & Gas Leaders Conference at 7:00 a.m. Central time (8:00 a.m. Eastern time) on Thursday, September 28. Sandeep Bhakhri, Senior Vice President and Chief Information and Technology Officer, will present on behalf of EOG.
Please visit the Investors/Overview page on the EOG website to access the live webcasts. If you are unable to listen live, replays will be available on the Investors/Presentations and Events page for six months.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
Investors
David J. Streit
(713) 571-4902
W. John Wagner
(713) 571-4404
Media and Investors
Kimberly M. Ehmer
(713) 571-4676
View original content:http://www.prnewswire.com/news-releases/eog-resources-to-present-at-upcoming-energy-conferences-300511833.html
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 1, 2017 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported second quarter 2017 net income of $23.1 million, or $0.04 per share. This compares to a second quarter 2016 net loss of $292.6 million, or $0.53 per share.
Adjusted non-GAAP net income for the second quarter 2017 was $46.7 million, or $0.08 per share, compared to an adjusted non-GAAP net loss of $209.7 million, or $0.38 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching commodity derivative contract realizations to settlement months and making certain other adjustments in order to exclude non-recurring items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Increased crude oil volumes and higher commodity prices resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2017 compared to the second quarter 2016. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
EOG grew second quarter total crude oil volumes 25 percent to 334,700 barrels of oil per day (Bopd), setting a company oil production record. Natural gas liquids (NGLs) and natural gas production also exceeded targets, contributing to 10 percent total company production growth compared to the second quarter 2016. The company also delivered per-unit costs for lease and well, transportation and depreciation, depletion and amortization below targets.
"EOG's premium drilling strategy continues to drive outperformance every quarter, delivering strong production growth with industry-leading capital efficiency," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Our permanent shift to premium drilling, driven by an organic exploration focus and best-in-class technology, is a sustainable competitive advantage."
Updated 2017 Growth Targets
As a result of strong well productivity improvements, EOG increased 2017 production growth targets while maintaining its current plan of completing 480 net wells with capital expenditures of $3.7 to $4.1 billion. The company increased its full-year 2017 U.S. crude oil growth target to 20 percent from 18 percent and total company production growth target to seven percent from five percent. In addition to delivering strong growth, EOG is actively engaged in a robust exploration program to lease and test multiple new prospects.
"EOG can generate high returns at relatively low oil prices, and our disciplined investment strategy has positioned the company on a strong financial footing," Thomas said. "By applying industry-leading technology and geoscience to our acreage concentrated in the sweet spots of the largest oil plays in the U.S., EOG can continue to grow at strong rates within cash flow."
Delaware Basin
In the second quarter 2017, EOG continued its exploration and development program across the Delaware Basin.
EOG completed 25 wells in the Delaware Basin Wolfcamp in the second quarter with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 3,010 barrels of oil equivalent per day (Boed), or 1,945 Bopd, 480 barrels per day (Bpd) of NGLs and 3.5 million cubic feet per day (MMcfd) of natural gas. In Lea County, NM, EOG completed a four-well pattern, the Rattlesnake 28 Fed Com 706H-709H, with an average treated lateral length of 6,700 feet per well and average 30-day initial production rates per well of 3,870 Boed, or 2,545 Bopd, 600 Bpd of NGLs and 4.4 MMcfd of natural gas.
In the Delaware Basin Bone Spring, EOG completed 19 wells in the second quarter with an average treated lateral length of 5,600 feet per well and average 30-day initial production rates per well of 2,130 Boed, or 1,515 Bopd, 275 Bpd of NGLs and 2.0 MMcfd of natural gas. In Lea County, NM, EOG completed a three-well pattern, the Neptune 10 State Com 503H-505H, with an average treated lateral length of 9,700 feet per well and average 30-day initial production rates per well of 3,620 Boed, or 2,790 Bopd, 375 Bpd of NGLs and 2.7 MMcfd of natural gas.
In the Delaware Basin Leonard, EOG completed three wells in the second quarter with an average treated lateral length of 5,400 feet per well and average 30-day initial production rates per well of 1,615 Boed, or 1,075 Bopd, 245 Bpd of NGLs and 1.8 MMcfd of natural gas.
South Texas Eagle Ford
EOG's South Texas Eagle Ford generated strong initial production performance during the second quarter as EOG continued to apply its precision targeting concepts across its expansive acreage position in the black oil window of the play.
In the second quarter, EOG completed 51 wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 1,960 Boed, or 1,520 Bopd, 225 Bpd of NGLs and 1.3 MMcfd of natural gas. In Karnes County, EOG completed a three-well pattern, the Lynch Unit 2H-4H, with an average treated lateral length of 5,800 feet per well and average 30-day initial production rates per well of 3,245 Boed, or 2,555 Bopd, 350 Bpd of NGLs and 2.0 MMcfd of natural gas. In Gonzales County, EOG completed a four-well pattern, the Olympic A 1H–D 4H, with an average treated lateral length of 6,600 feet per well and average 30-day initial production rates per well of 2,910 Boed, or 2,160 Bopd, 380 Bpd of NGLs and 2.2 MMcfd of natural gas. In DeWitt County, EOG completed a five-well pattern, the Dio Unit 11H-15H, with an average treated lateral length of 5,100 feet per well and average 30-day initial production rates per well of 2,840 Boed, or 2,135 Bopd, 355 Bpd of NGLs and 2.1 MMcfd of natural gas.
South Texas Austin Chalk
In the second quarter 2017, testing continued in the South Texas Austin Chalk. EOG completed nine wells in Karnes County with an average treated lateral length of 4,000 feet per well and average 30-day initial production rates per well of 2,645 Boed, or 2,150 Bopd, 255 Bpd of NGLs and 1.5 MMcfd of natural gas.
Bakken and Powder River Basin
During the second quarter, EOG continued development of its premium oil plays across the Rocky Mountain region.
In the North Dakota Bakken, EOG completed 22 wells in the second quarter with an average treated lateral length of 8,400 feet per well and average 30-day initial production rates per well of 1,450 Boed, or 1,175 Bopd, 150 Bpd of NGLs and 0.7 MMcfd of natural gas. Of particular note is a four-well pattern in the Antelope field in McKenzie County, the Clarks Creek 73, 74, 75 and 110-0719H, completed with an average treated lateral length of 9,800 feet per well and average 30-day initial production rates per well of 2,965 Boed, or 2,075 Bopd, 500 Bpd of NGLs and 2.3 MMcfd of natural gas.
In the Powder River Basin Turner, EOG completed eight wells in the second quarter with an average treated lateral length of 8,700 feet per well and average 30-day initial production rates per well of 1,745 Boed, or 910 Bopd, 285 Bpd of NGLs and 3.3 MMcfd of natural gas.
In the DJ Basin, EOG completed 10 wells in the second quarter with an average treated lateral length of 9,000 feet per well and average 30-day initial production rates per well of 885 Boed, or 770 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.
Trinidad
In June 2017, EOG signed a new multi-year contract under which EOG will supply future natural gas volumes to the National Gas Company of Trinidad and Tobago Limited beginning in 2019. The new contract opens opportunities for additional investments that can deliver rates of return competitive with EOG's premier on-shore oil plays.
Hedging Activity
During the second quarter ended June 30, 2017, EOG entered into crude oil derivative contracts in order to fix the differential between pricing in Midland, TX and Cushing, OK. For the period January 1 through December 31, 2018, EOG entered into crude oil basis swap contracts for 15,000 Bopd at a weighted average price differential between Midland, TX and Cushing, OK of $1.063 per barrel. In addition, for the period January 1 through December 31, 2019, EOG entered into crude oil basis swap contracts for 20,000 Bopd at a weighted average price differential between Midland, TX and Cushing, OK of $1.075 per barrel.
During the second quarter ended June 30, 2017, EOG did not enter into additional natural gas derivative contracts.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At June 30, 2017, EOG's total debt outstanding was $7.0 billion for a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet at the end of the second quarter, EOG's net debt was $5.3 billion for a net debt-to-total capitalization ratio of 28 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales in the first six months of 2017 totaled $175 million.
Conference Call August 2, 2017
EOG's second quarter 2017 results conference call will be available via live audio webcast at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, August 2, 2017. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through August 2, 2018.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | ||||||||||||
Financial Report | ||||||||||||
(Unaudited; in millions, except per share data) | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Operating Revenues and Other |
$ |
2,612.5 |
$ |
1,775.7 |
$ |
5,223.0 |
$ |
3,130.1 | ||||
Net Income (Loss) |
$ |
23.1 |
$ |
(292.6) |
$ |
51.6 |
$ |
(764.3) | ||||
Net Income (Loss) Per Share |
||||||||||||
Basic |
$ |
0.04 |
$ |
(0.53) |
$ |
0.09 |
$ |
(1.40) | ||||
Diluted |
$ |
0.04 |
$ |
(0.53) |
$ |
0.09 |
$ |
(1.40) | ||||
Average Number of Common Shares |
||||||||||||
Basic |
574.4 |
547.3 |
574.2 |
547.0 | ||||||||
Diluted |
578.5 |
547.3 |
578.6 |
547.0 | ||||||||
Summary Income Statements | ||||||||||||
(Unaudited; in thousands, except per share data) | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Operating Revenues and Other |
||||||||||||
Crude Oil and Condensate |
$ |
1,445,454 |
$ |
1,059,690 |
$ |
2,875,515 |
$ |
1,813,401 | ||||
Natural Gas Liquids |
146,907 |
111,643 |
300,351 |
186,962 | ||||||||
Natural Gas |
224,008 |
155,983 |
454,610 |
321,486 | ||||||||
Gains (Losses) on Mark-to-Market Commodity |
9,446 |
(44,373) |
71,466 |
(38,938) | ||||||||
Gathering, Processing and Marketing |
778,797 |
485,256 |
1,505,334 |
819,209 | ||||||||
Losses on Asset Dispositions, Net |
(8,916) |
(15,550) |
(25,674) |
(6,403) | ||||||||
Other, Net |
16,776 |
23,091 |
41,435 |
34,372 | ||||||||
Total |
2,612,472 |
1,775,740 |
5,223,037 |
3,130,089 | ||||||||
Operating Expenses |
||||||||||||
Lease and Well |
255,186 |
218,393 |
510,963 |
459,258 | ||||||||
Transportation Costs |
186,356 |
179,471 |
365,070 |
369,925 | ||||||||
Gathering and Processing Costs |
34,746 |
29,226 |
72,890 |
57,750 | ||||||||
Exploration Costs |
34,711 |
30,559 |
91,605 |
60,388 | ||||||||
Dry Hole Costs |
27 |
(172) |
27 |
74 | ||||||||
Impairments |
78,934 |
72,714 |
272,121 |
144,331 | ||||||||
Marketing Costs |
790,599 |
480,046 |
1,527,135 |
820,900 | ||||||||
Depreciation, Depletion and Amortization |
865,384 |
862,491 |
1,681,420 |
1,791,382 | ||||||||
General and Administrative |
108,507 |
97,705 |
205,745 |
198,236 | ||||||||
Taxes Other Than Income |
130,114 |
93,480 |
260,407 |
154,159 | ||||||||
Total |
2,484,564 |
2,063,913 |
4,987,383 |
4,056,403 | ||||||||
Operating Income (Loss) |
127,908 |
(288,173) |
235,654 |
(926,314) | ||||||||
Other Income (Expense), Net |
4,972 |
(20,996) |
8,123 |
(25,433) | ||||||||
Income (Loss) Before Interest Expense and Income Taxes |
132,880 |
(309,169) |
243,777 |
(951,747) | ||||||||
Interest Expense, Net |
70,413 |
71,108 |
141,928 |
139,498 | ||||||||
Income (Loss) Before Income Taxes |
62,467 |
(380,277) |
101,849 |
(1,091,245) | ||||||||
Income Tax Provision (Benefit) |
39,414 |
(87,719) |
50,279 |
(326,911) | ||||||||
Net Income (Loss) |
$ |
23,053 |
$ |
(292,558) |
$ |
51,570 |
$ |
(764,334) | ||||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.3350 |
$ |
0.3350 | ||||
EOG RESOURCES, INC. | ||||||||||||
Operating Highlights | ||||||||||||
(Unaudited) | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Wellhead Volumes and Prices |
||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
||||||||||||
United States |
333.1 |
265.4 |
322.8 |
265.6 | ||||||||
Trinidad |
0.8 |
0.8 |
0.8 |
0.8 | ||||||||
Other International (B) |
0.8 |
1.5 |
1.6 |
1.4 | ||||||||
Total |
334.7 |
267.7 |
325.2 |
267.8 | ||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
||||||||||||
United States |
$ |
47.51 |
$ |
43.87 |
$ |
48.89 |
$ |
37.36 | ||||
Trinidad |
39.64 |
35.91 |
40.63 |
29.83 | ||||||||
Other International (B) |
35.13 |
- |
44.66 |
- | ||||||||
Composite |
47.46 |
43.65 |
48.85 |
37.23 | ||||||||
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||
United States |
86.6 |
84.3 |
82.7 |
81.8 | ||||||||
Other International (B) |
- |
- |
- |
- | ||||||||
Total |
86.6 |
84.3 |
82.7 |
81.8 | ||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
||||||||||||
United States |
$ |
18.65 |
$ |
14.56 |
$ |
20.06 |
$ |
12.54 | ||||
Other International (B) |
- |
- |
- |
- | ||||||||
Composite |
18.65 |
14.56 |
20.06 |
12.54 | ||||||||
Natural Gas Volumes (MMcfd) (A) |
||||||||||||
United States |
755 |
820 |
742 |
825 | ||||||||
Trinidad |
320 |
349 |
314 |
355 | ||||||||
Other International (B) |
21 |
25 |
21 |
25 | ||||||||
Total |
1,096 |
1,194 |
1,077 |
1,205 | ||||||||
Average Natural Gas Prices ($/Mcf) (C) |
||||||||||||
United States |
$ |
2.14 |
$ |
1.18 |
$ |
2.23 |
$ |
1.22 | ||||
Trinidad |
2.40 |
1.89 |
2.48 |
1.88 | ||||||||
Other International (B) |
3.66 |
3.35 |
3.71 |
3.49 | ||||||||
Composite |
2.25 |
1.44 |
2.33 |
1.47 | ||||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
||||||||||||
United States |
545.6 |
486.3 |
529.2 |
484.9 | ||||||||
Trinidad |
54.1 |
59.0 |
53.1 |
59.9 | ||||||||
Other International (B) |
4.2 |
5.8 |
5.1 |
5.6 | ||||||||
Total |
603.9 |
551.1 |
587.4 |
550.4 | ||||||||
Total MMBoe (D) |
55.0 |
50.1 |
106.3 |
100.2 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
June 30, |
December 31, | ||||
2017 |
2016 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,649,443 |
$ |
1,599,895 | |
Accounts Receivable, Net |
1,114,454 |
1,216,320 | |||
Inventories |
336,198 |
350,017 | |||
Assets from Price Risk Management Activities |
4,746 |
- | |||
Income Taxes Receivable |
91,256 |
12,305 | |||
Other |
187,276 |
206,679 | |||
Total |
3,383,373 |
3,385,216 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
50,973,760 |
49,592,091 | |||
Other Property, Plant and Equipment |
3,883,759 |
4,008,564 | |||
Total Property, Plant and Equipment |
54,857,519 |
53,600,655 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(29,277,359) |
(27,893,577) | |||
Total Property, Plant and Equipment, Net |
25,580,160 |
25,707,078 | |||
Deferred Income Taxes |
16,888 |
16,140 | |||
Other Assets |
283,196 |
190,767 | |||
Total Assets |
$ |
29,263,617 |
$ |
29,299,201 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,615,170 |
$ |
1,511,826 | |
Accrued Taxes Payable |
155,458 |
118,411 | |||
Dividends Payable |
96,145 |
96,120 | |||
Liabilities from Price Risk Management Activities |
- |
61,817 | |||
Current Portion of Long-Term Debt |
606,454 |
6,579 | |||
Other |
249,027 |
232,538 | |||
Total |
2,722,254 |
2,027,291 | |||
Long-Term Debt |
6,380,350 |
6,979,779 | |||
Other Liabilities |
1,199,778 |
1,282,142 | |||
Deferred Income Taxes |
5,059,520 |
5,028,408 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized at June 30, 2017, |
|||||
640,000,000 Shares Authorized at December 31, 2016, 577,711,399 Shares |
|||||
Issued at June 30, 2017 and 576,950,272 Shares Issued at December 31, 2016 |
205,777 |
205,770 | |||
Additional Paid in Capital |
5,485,832 |
5,420,385 | |||
Accumulated Other Comprehensive Loss |
(17,490) |
(19,010) | |||
Retained Earnings |
8,256,359 |
8,398,118 | |||
Common Stock Held in Treasury, 316,339 Shares at June 30, 2017 |
|||||
and 250,155 Shares at December 31, 2016 |
(28,763) |
(23,682) | |||
Total Stockholders' Equity |
13,901,715 |
13,981,581 | |||
Total Liabilities and Stockholders' Equity |
$ |
29,263,617 |
$ |
29,299,201 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Six Months Ended | |||||
June 30, | |||||
2017 |
2016 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
51,570 |
$ |
(764,334) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
1,681,420 |
1,791,382 | |||
Impairments |
272,121 |
144,331 | |||
Stock-Based Compensation Expenses |
58,061 |
59,471 | |||
Deferred Income Taxes |
35,162 |
(384,294) | |||
Losses on Asset Dispositions, Net |
25,674 |
6,403 | |||
Other, Net |
(6,691) |
29,991 | |||
Dry Hole Costs |
27 |
74 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
(71,466) |
38,938 | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
2,591 |
2,852 | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
(11,811) | |||
Other, Net |
(185) |
5,008 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
103,786 |
(22,572) | |||
Inventories |
(6,129) |
95,813 | |||
Accounts Payable |
76,704 |
(203,358) | |||
Accrued Taxes Payable |
(39,124) |
93,320 | |||
Other Assets |
(61,089) |
(33,589) | |||
Other Liabilities |
(66,869) |
1,565 | |||
Changes in Components of Working Capital Associated with Investing and Financing |
(79,138) |
(54,453) | |||
Net Cash Provided by Operating Activities |
1,976,425 |
794,737 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(1,885,417) |
(1,143,549) | |||
Additions to Other Property, Plant and Equipment |
(88,076) |
(44,584) | |||
Proceeds from Sales of Assets |
175,260 |
252,529 | |||
Changes in Components of Working Capital Associated with Investing Activities |
79,138 |
54,477 | |||
Net Cash Used in Investing Activities |
(1,719,095) |
(881,127) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
- |
(259,718) | |||
Long-Term Debt Borrowings |
- |
991,097 | |||
Long-Term Debt Repayments |
- |
(400,000) | |||
Dividends Paid |
(192,984) |
(184,036) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
11,811 | |||
Treasury Stock Purchased |
(21,678) |
(28,755) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
9,608 |
10,624 | |||
Debt Issuance Costs |
- |
(1,602) | |||
Repayment of Capital Lease Obligation |
(3,251) |
(3,150) | |||
Other, Net |
- |
(24) | |||
Net Cash (Used in) Provided by Financing Activities |
(208,305) |
136,247 | |||
Effect of Exchange Rate Changes on Cash |
523 |
11,359 | |||
Increase in Cash and Cash Equivalents |
49,548 |
61,216 | |||
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 | |||
Cash and Cash Equivalents at End of Period |
$ |
1,649,443 |
$ |
779,722 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
To Net Income (Loss) (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back an early lease termination payment as the result of a legal settlement in 2017 and to add back the transaction costs for the formation of a joint venture in 2017. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
June 30, 2017 |
June 30, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ 62,467 |
$(39,414) |
$ 23,053 |
$ 0.04 |
$ (380,277) |
$ 87,719 |
$(292,558) |
$ (0.53) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
(9,446) |
3,426 |
(6,020) |
(0.01) |
44,373 |
(15,819) |
28,554 |
0.05 | |||||||
Net Cash Received from (Payments for) |
|||||||||||||||
Settlements of Commodity Derivative |
|||||||||||||||
Contracts |
679 |
(245) |
434 |
- |
(14,835) |
5,289 |
(9,546) |
(0.01) | |||||||
Add: Net Losses on Asset Dispositions |
8,916 |
(3,151) |
5,765 |
0.01 |
15,550 |
(7,378) |
8,172 |
0.01 | |||||||
Add: Impairments |
23,397 |
(8,477) |
14,920 |
0.03 |
- |
- |
- |
- | |||||||
Add: Trinidad Tax Settlement |
- |
- |
- |
- |
- |
43,000 |
43,000 |
0.08 | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
19,663 |
(7,010) |
12,653 |
0.02 | |||||||
Add: Legal Settlement - Early Lease Termination |
10,202 |
(3,657) |
6,545 |
0.01 |
- |
- |
- |
- | |||||||
Add: Joint Venture Transaction Costs |
3,056 |
(1,095) |
1,961 |
- |
- |
- |
- |
- | |||||||
Adjustments to Net Income |
36,804 |
(13,199) |
23,605 |
0.04 |
64,751 |
18,082 |
82,833 |
0.15 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ 99,271 |
$(52,613) |
$ 46,658 |
$ 0.08 |
$ (315,526) |
$105,801 |
$(209,725) |
$ (0.38) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,439 |
547,335 | |||||||||||||
Diluted |
578,483 |
547,335 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
574,439 |
547,335 | |||||||||||||
Diluted |
578,483 |
547,335 | |||||||||||||
Six Months Ended |
Six Months Ended | ||||||||||||||
June 30, 2017 |
June 30, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$101,849 |
$(50,279) |
$ 51,570 |
$ 0.09 |
$(1,091,245) |
$326,911 |
$(764,334) |
$ (1.40) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
(71,466) |
25,617 |
(45,849) |
(0.08) |
38,938 |
(13,881) |
25,057 |
0.05 | |||||||
Net Cash Received from Settlements of |
|||||||||||||||
Commodity Derivative Contracts |
2,591 |
(929) |
1,662 |
- |
2,852 |
(1,017) |
1,835 |
- | |||||||
Add: Net Losses on Asset Dispositions |
25,674 |
(8,887) |
16,787 |
0.03 |
6,403 |
(4,168) |
2,235 |
- | |||||||
Add: Impairments |
161,148 |
(57,764) |
103,384 |
0.18 |
- |
- |
- |
- | |||||||
Add: Trinidad Tax Settlement |
- |
- |
- |
- |
- |
43,000 |
43,000 |
0.08 | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
42,054 |
(14,992) |
27,062 |
0.05 | |||||||
Add: Legal Settlement - Early Lease Termination |
10,202 |
(3,657) |
6,545 |
0.01 |
- |
- |
- |
- | |||||||
Add: Joint Venture Transaction Costs |
3,056 |
(1,095) |
1,961 |
- |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
131,205 |
(46,715) |
84,490 |
0.14 |
90,247 |
8,942 |
99,189 |
0.18 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$233,054 |
$(96,994) |
$136,060 |
$ 0.23 |
$(1,000,998) |
$335,853 |
$(665,145) |
$ (1.22) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
574,162 |
547,029 | |||||||||||||
Diluted |
578,573 |
547,029 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
574,162 |
547,029 | |||||||||||||
Diluted |
578,573 |
547,029 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
to Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and six-month periods ended June 30, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
1,078,376 |
$ |
503,146 |
$ |
1,976,425 |
$ |
794,737 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
29,402 |
25,527 |
80,136 |
48,884 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
- |
11,811 |
- |
11,811 | ||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||
and Liabilities |
||||||||||||
Accounts Receivable |
(75,098) |
154,970 |
(103,786) |
22,572 | ||||||||
Inventories |
30,865 |
(38,235) |
6,129 |
(95,813) | ||||||||
Accounts Payable |
(56,278) |
(86,269) |
(76,704) |
203,358 | ||||||||
Accrued Taxes Payable |
511 |
(90,860) |
39,124 |
(93,320) | ||||||||
Other Assets |
16,412 |
37,535 |
61,089 |
33,589 | ||||||||
Other Liabilities |
15,618 |
6,427 |
66,869 |
(1,565) | ||||||||
Changes in Components of Working Capital Associated with |
||||||||||||
Investing and Financing Activities |
15,814 |
56,681 |
79,138 |
54,453 | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,055,622 |
$ |
580,733 |
$ |
2,128,420 |
$ |
978,706 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
82% |
117% |
||||||||||
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | ||||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | ||||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | ||||||||||||
(Non-GAAP) to Net Income (Loss) (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense (Net), Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2017 |
2016 |
2017 |
2016 | |||||||||
Net Income (Loss) (GAAP) |
$ |
23,053 |
$ |
(292,558) |
$ |
51,570 |
$ |
(764,334) | ||||
Adjustments: |
||||||||||||
Interest Expense, Net |
70,413 |
71,108 |
141,928 |
139,498 | ||||||||
Income Tax Provision (Benefit) |
39,414 |
(87,719) |
50,279 |
(326,911) | ||||||||
Depreciation, Depletion and Amortization |
865,384 |
862,491 |
1,681,420 |
1,791,382 | ||||||||
Exploration Costs |
34,711 |
30,559 |
91,605 |
60,388 | ||||||||
Dry Hole Costs |
27 |
(172) |
27 |
74 | ||||||||
Impairments |
78,934 |
72,714 |
272,121 |
144,331 | ||||||||
EBITDAX (Non-GAAP) |
1,111,936 |
656,423 |
2,288,950 |
1,044,428 | ||||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
(9,446) |
44,373 |
(71,466) |
38,938 | ||||||||
Net Cash Received from (Payments for) Settlements of Commodity |
||||||||||||
Derivative Contracts |
679 |
(14,835) |
2,591 |
2,852 | ||||||||
Losses on Asset Dispositions, Net |
8,916 |
15,550 |
25,674 |
6,403 | ||||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,112,085 |
$ |
701,511 |
$ |
2,245,749 |
$ |
1,092,621 | ||||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
59% |
106% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
June 30, |
December 31, | ||||
2017 |
2016 | ||||
Total Stockholders' Equity - (a) |
$ |
13,902 |
$ |
13,982 | |
Current and Long-Term Debt (GAAP) - (b) |
6,987 |
6,986 | |||
Less: Cash |
(1,649) |
(1,600) | |||
Net Debt (Non-GAAP) - (c) |
5,338 |
5,386 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
20,889 |
$ |
20,968 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,240 |
$ |
19,368 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33% |
33% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
28% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Prices received by EOG for its crude oil production generally vary from NYMEX West Texas Intermediate prices due to adjustments for delivery location (basis) and other factors. EOG entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. Presented below is a comprehensive summary of EOG's crude oil basis swap contracts through August 1, 2017. The weighted average price differential expressed in $/Bbl represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts. | |||||||||||
Crude Oil Basis Swap Contracts | |||||||||||
Weighted | |||||||||||
Average Price | |||||||||||
Volume |
Differential | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2018 |
|||||||||||
January 1, 2018 through December 31, 2018 |
15,000 |
$ 1.063 | |||||||||
2019 |
|||||||||||
January 1, 2019 through December 31, 2019 |
20,000 |
$ 1.075 | |||||||||
On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts, which are included in the below table. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through August 1, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2017 |
|||||||||||
January 1, 2017 through February 28, 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
March 1, 2017 through June 30, 2017 (closed) |
30,000 |
50.05 | |||||||||
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG received for settling these contracts was $0.7 million. The offsetting contracts are excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2017 |
|||||||||||
March 1, 2017 through August 31, 2017 (closed) |
30,000 |
$ 3.10 | |||||||||
September 1, 2017 through November 30, 2017 |
30,000 |
3.10 | |||||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
35,000 |
$ 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2017 |
|||||||||||
March 1, 2017 through August 31, 2017 (closed) |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
September 1, 2017 through November 30, 2017 |
213,750 |
3.44 |
171,000 |
2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through August 1, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume |
|||||||||||
(MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2017 |
|||||||||||
March 1, 2017 through August 31, 2017 (closed) |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
September 1, 2017 through November 30, 2017 |
80,000 |
3.69 |
3.20 | ||||||||
Definitions |
|||||||||||
Bbld Barrels per day |
|||||||||||
$/Bbl Dollars per barrel |
|||||||||||
MMBtud Million British thermal units per day |
|||||||||||
$/MMBtu Dollars per million British thermal units |
|||||||||||
NYMEX U.S. New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated recoverable reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
2016 |
2015 |
2014 |
2013 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
282 |
$ |
237 |
$ |
201 |
|||||
Tax Benefit Imputed (based on 35%) |
(99) |
(83) |
(70) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
183 |
$ |
154 |
$ |
131 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
|||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
204 |
(a) |
4,559 |
(b) |
(199) |
(c) |
|||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
(893) |
$ |
34 |
$ |
2,716 |
|||||
Total Stockholders' Equity - (d) |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | |||
Average Total Stockholders' Equity * - (e) |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | |||
Less: Cash |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-4.8% |
-21.6% |
14.7% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
-3.7% |
0.9% |
13.7% |
||||||||
Return on Equity (ROE) |
|||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (e) |
-8.1% |
-29.5% |
17.6% |
||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (e) |
-6.6% |
0.2% |
16.4% |
||||||||
* Average for the current and immediately preceding year |
|||||||||||
Adjustments to Net Income (Loss) (GAAP) |
|||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: |
|||||||||||
Year Ended December 31, 2016 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 |
|||||
Add: Impairments of Certain Assets |
321 |
(113) |
208 |
||||||||
Less: Net Gains on Asset Dispositions |
(206) |
62 |
(144) |
||||||||
Add: Trinidad Tax Settlement |
- |
43 |
43 |
||||||||
Add: Voluntary Retirement Expense |
42 |
(15) |
27 |
||||||||
Add: Acquisition - State Apportionment Change |
- |
16 |
16 |
||||||||
Add: Acquisition Costs |
5 |
- |
5 |
||||||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 |
|||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
|||||||||||
Year Ended December 31, 2015 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
|||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
||||||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
||||||||
Add: Severance Costs |
9 |
(3) |
6 |
||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
|||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
|||||||||||
Year Ended December 31, 2014 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
|||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
- |
250 |
250 |
||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
Third Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Third Quarter and Full Year 2017 Forecast | |||||||||||
The forecast items for the third quarter and full year 2017 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
3Q 2017 |
Full Year 2017 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
335.0 |
- |
345.0 |
332.0 |
- |
338.0 | |||||
Trinidad |
0.5 |
- |
0.7 |
0.6 |
- |
0.8 | |||||
Other International |
0.0 |
- |
0.0 |
0.8 |
- |
0.8 | |||||
Total |
335.5 |
- |
345.7 |
333.4 |
- |
339.6 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
77.0 |
- |
83.0 |
80.0 |
- |
83.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
720 |
- |
760 |
730 |
- |
760 | |||||
Trinidad |
280 |
- |
320 |
295 |
- |
310 | |||||
Other International |
15 |
- |
30 |
21 |
- |
27 | |||||
Total |
1,015 |
- |
1,110 |
1,046 |
- |
1,097 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
532.0 |
- |
554.7 |
533.7 |
- |
547.7 | |||||
Trinidad |
47.2 |
- |
54.0 |
49.8 |
- |
52.5 | |||||
Other International |
2.5 |
- |
5.0 |
4.3 |
- |
5.3 | |||||
Total |
581.7 |
- |
613.7 |
587.8 |
- |
605.5 | |||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
3Q 2017 |
Full Year 2017 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.40 |
- |
$ |
4.80 |
$ |
4.40 |
- |
$ |
4.80 | |
Transportation Costs |
$ |
3.30 |
- |
$ |
3.80 |
$ |
3.30 |
- |
$ |
3.60 | |
Depreciation, Depletion and Amortization |
$ |
15.55 |
- |
$ |
15.95 |
$ |
15.65 |
- |
$ |
15.85 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
90 |
- |
$ |
120 |
$ |
390 |
- |
$ |
420 | |
General and Administrative |
$ |
100 |
- |
$ |
110 |
$ |
380 |
- |
$ |
400 | |
Gathering and Processing |
$ |
28 |
- |
$ |
32 |
$ |
130 |
- |
$ |
140 | |
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
25 |
- |
$ |
30 | |
Net Interest |
$ |
69 |
- |
$ |
72 |
$ |
273 |
- |
$ |
279 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.8% |
- |
7.2% |
6.9% |
- |
7.1% | |||||
Income Taxes |
|||||||||||
Effective Rate |
30% |
- |
35% |
35% |
- |
40% | |||||
Current Taxes ($MM) |
$ |
0 |
- |
$ |
35 |
$ |
10 |
- |
$ |
50 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
3,000 |
- |
$ |
3,350 | ||||||
Exploration and Development Facilities |
$ |
475 |
- |
$ |
510 | ||||||
Gathering, Processing and Other |
$ |
225 |
- |
$ |
240 | ||||||
Pricing - (Refer toBenchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(1.25) |
- |
$ |
(0.25) |
$ |
(1.50) |
- |
$ |
(0.50) | |
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(10.00) |
- |
$ |
(9.00) | |
Other International - above (below) WTI |
$ |
(4.00) |
- |
$ |
2.00 |
$ |
(7.00) |
- |
$ |
1.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
35% |
- |
41% |
37% |
- |
41% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.20) |
- |
$ |
(0.70) |
$ |
(1.10) |
- |
$ |
(0.80) | |
Realizations |
|||||||||||
Trinidad |
$ |
1.85 |
- |
$ |
2.25 |
$ |
2.20 |
- |
$ |
2.40 | |
Other International |
$ |
3.80 |
- |
$ |
4.30 |
$ |
3.85 |
- |
$ |
4.15 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX U.S. New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
View original content:http://www.prnewswire.com/news-releases/eog-resources-announces-second-quarter-2017-results-300497814.html
SOURCE EOG Resources, Inc.
HOUSTON, June 14, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss second quarter 2017 results on Wednesday, August 2, 2017, at 8 a.m. Central time (9 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Angie Lewis at 713-651-6722.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, May 10, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Barclays Americas Select Franchise Conference at 7:40 a.m. Central time (1:40 p.m. Greenwich Mean time) on Wednesday, May 17. David W. Trice, Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the UBS Global Oil and Gas Conference at 10 a.m. Central time on Thursday, May 25. Lloyd W. "Billy" Helms, Jr., Executive Vice President, Exploration and Production, will present on behalf of EOG.
EOG is also scheduled to present at the Bernstein Strategic Decisions Conference at 3 p.m. Central time (4 p.m. Eastern time) on Wednesday, May 31. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG.
Please visit the Investors/Overview page on the EOG website to access the live webcasts. If you are unable to listen live, replays will be available on the Investors/Presentations and Events page for six months.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact:
|
Investors | ||
Media and Investors |
SOURCE EOG Resources, Inc.
HOUSTON, May 8, 2017 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported first quarter 2017 net income of $28.5 million, or $0.05 per share. This compares to a first quarter 2016 net loss of $471.8 million, or $0.86 per share.
Adjusted non-GAAP net income for the first quarter 2017 was $89.4 million, or $0.15 per share, compared to an adjusted non-GAAP net loss of $455.4 million, or $0.83 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Higher commodity prices, increased production volumes, well productivity improvements and overall per-unit cost reductions resulted in increases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2017 compared to the first quarter 2016. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
EOG set a company record for crude oil volumes in the first quarter 2017 by producing 315,700 barrels of oil per day (Bopd), an 18 percent increase compared to the first quarter 2016. This strong production growth reflects the company's premium drilling strategy and technical advances in its prolific plays across multiple basins. EOG defines premium inventory as prospective well locations that will earn a minimum 30 percent direct after-tax rate of return at $40 crude oil and $2.50 natural gas prices.
EOG continues to reduce total well costs in each of its major plays. First quarter 2017 average completed well costs were 6 percent lower than full year 2016 averages in the Eagle Ford, Delaware Basin and Bakken using normalized lateral lengths. For all three plays, the overall cost reductions were achieved in spite of service and equipment price inflation in certain areas, which were more than offset by continued advances in drilling and completion tools and techniques, benefits from extended lateral lengths, and new contracts at lower prices.
During the first quarter 2017, lease and well expenses on a per-unit basis increased 4 percent compared to the same prior year period primarily because of last year's disposition of natural gas producing assets with lower per-unit operating costs, the Yates acquisition properties with higher per-unit operating costs, and higher production expenses in the United Kingdom. Per-unit transportation costs decreased 8 percent and depreciation, depletion and amortization expenses decreased 14 percent on a per-unit basis year-over-year. Total general and administrative expenses decreased 3 percent compared to the first quarter 2016 primarily due to expenses related to a voluntary retirement program in 2016.
"EOG continues to lead the industry in well productivity, with record-setting well performance driving company record crude oil volumes," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "During the first quarter 2017, we increased our premium inventory by 1,200 net well locations and 1.4 BnBoe of premium net resource potential, which is approximately 2.5 times the number of wells we expect to complete during all of 2017. EOG remains committed to creating significant shareholder value through low-cost, high-return growth and organic resource expansion."
Delaware Basin
In the first quarter 2017, EOG continued to increase development activity and expand resource potential in the Delaware Basin. EOG increased its Delaware Basin premium net locations by 700 to 4,150 locations.
EOG completed 33 wells in the Delaware Basin Wolfcamp in the first quarter 2017 with an average treated lateral length of 5,600 feet per well and average 30-day initial production rates per well of 2,855 barrels of oil equivalent per day (Boed), or 1,850 Bopd, 450 barrels per day (Bpd) of natural gas liquids (NGLs) and 3.3 million cubic feet per day (MMcfd) of natural gas.
Of special note is a four-well pattern in Lea County, N.M., the Whirling Wind 14 Fed Com #701H and the Whirling Wind 11 Fed Com #702H - #704H which were completed with an average treated lateral length of 7,100 feet per well and average 30-day initial production rates per well of 5,060 Boed, or 3,510 Bopd, 700 Bpd of NGLs and 5.1 MMcfd of natural gas. Each well exceeded the prior all-time industry record for 30-day initial production from Permian Basin horizontal oil wells.
"EOG's Whirling Wind wells shattered industry records in the Permian Basin," said Thomas. "Our advanced technology and proprietary techniques are leading to break-through well performance across our diverse portfolio of premium plays."
In the Delaware Basin Bone Spring, EOG completed three wells in the first quarter 2017 with an average treated lateral length of 8,800 feet per well and average 30-day initial production rates per well of 3,255 Boed, or 2,525 Bopd, 335 Bpd of NGLs and 2.4 MMcfd of natural gas.
In the Delaware Basin Leonard, EOG completed three wells in the first quarter 2017 with an average treated lateral length of 3,800 feet per well and average 30-day initial production rates per well of 840 Boed, or 505 Bopd, 150 Bpd of NGLs and 1.1 MMcfd of natural gas. These first quarter 2017 completions were drilled prior to 2016.
South Texas Eagle Ford
EOG's South Texas Eagle Ford continued to be the most active area in the company in the first quarter 2017. In addition to significant development activity, EOG expanded its Eagle Ford premium net locations by 500 to more than 2,400 locations. Part of the increase in premium locations was enabled by a shift to longer lateral drilling units. Seven wells that began production in the first quarter 2017 had lateral lengths in excess of 10,000 feet.
In the first quarter 2017, EOG completed 65 wells in the Eagle Ford with an average treated lateral length of 6,500 feet per well and average 30-day initial production rates per well of 1,390 Boed, or 1,130 Bopd, 130 Bpd of NGLs and 0.8 MMcfd of natural gas.
South Texas Austin Chalk
In the first quarter 2017, testing continued in the South Texas Austin Chalk. EOG completed five wells in Karnes County with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 2,605 Boed, or 1,895 Bopd, 360 Bpd of NGLs and 2.1 MMcfd of natural gas.
Rockies and the Bakken
During the first quarter, EOG continued to develop its premium Powder River Basin position and reduce its inventory of drilled uncompleted wells in the Bakken.
In the Powder River Basin, EOG completed five wells in the first quarter 2017 with an average treated lateral length of 4,900 feet per well and average 30-day initial production rates per well of 1,160 Boed, or 950 Bopd, 75 Bpd of NGLs and 0.8 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed 27 wells in the first quarter 2017 with an average treated lateral length of 8,500 feet per well and average 30-day initial production rates per well of 715 Boed, or 640 Bopd, 40 Bpd of NGLs and 0.2 MMcfd of natural gas. The first quarter 2017 completions in the Bakken included 24 wells that were drilled prior to 2016. Three wells completed in the first quarter 2017 were the first wells completed in the Bakken Lite area with EOG's high-density fracs. These three wells had an average treated lateral length of 7,700 feet per well and average 30-day initial production rates per well of 955 Boed, or 795 Bopd, 85 Bpd of NGLs and 0.5 MMcfd of natural gas.
Hedging Activity
For the period June 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu. For the period March 1 through November 30, 2018, EOG has natural gas financial price swap contracts in place for 35,000 MMBtu per day at a weighted average price of $3.00 per MMBtu.
For the period June 1 through November 30, 2017, EOG has sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period March 1 through November 30, 2018, EOG has sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.
For the period June 1 through November 30, 2017, EOG has purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period March 1 through November 30, 2018, EOG has purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.
For the period June 1 through November 30, 2017, EOG has natural gas collar contracts for 80,000 MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of $3.20 per MMBtu.
EOG did not have a net crude oil hedge position as of March 31, 2017.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At March 31, 2017, EOG's total debt outstanding was $7.0 billion for a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet at the end of the first quarter, EOG's net debt was $5.4 billion for a net debt-to-total capitalization ratio of 28 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales year-to-date 2017 totaled $118 million. This includes proceeds from two transactions that closed in the second quarter 2017.
Conference Call May 9, 2017
EOG's first quarter 2017 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, May 9, 2017. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through May 23, 2017.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | |||||
Financial Report | |||||
(Unaudited; in millions, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2017 |
2016 | ||||
Net Operating Revenues |
$ |
2,610.6 |
$ |
1,354.3 | |
Net Income (Loss) |
$ |
28.5 |
$ |
(471.8) | |
Net Income (Loss) Per Share |
|||||
Basic |
$ |
0.05 |
$ |
(0.86) | |
Diluted |
$ |
0.05 |
$ |
(0.86) | |
Average Number of Common Shares |
|||||
Basic |
573.9 |
546.7 | |||
Diluted |
578.6 |
546.7 | |||
Summary Income Statements | |||||
(Unaudited; in thousands, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2017 |
2016 | ||||
Net Operating Revenues |
|||||
Crude Oil and Condensate |
$ |
1,430,061 |
$ |
753,711 | |
Natural Gas Liquids |
153,444 |
75,319 | |||
Natural Gas |
230,602 |
165,503 | |||
Gains on Mark-to-Market Commodity |
|||||
Derivative Contracts |
62,020 |
5,435 | |||
Gathering, Processing and Marketing |
726,537 |
333,953 | |||
Gains (Losses) on Asset Dispositions, Net |
(16,758) |
9,147 | |||
Other, Net |
24,659 |
11,281 | |||
Total |
2,610,565 |
1,354,349 | |||
Operating Expenses |
|||||
Lease and Well |
255,777 |
240,865 | |||
Transportation Costs |
178,714 |
190,454 | |||
Gathering and Processing Costs |
38,144 |
28,524 | |||
Exploration Costs |
56,894 |
29,829 | |||
Dry Hole Costs |
- |
246 | |||
Impairments |
193,187 |
71,617 | |||
Marketing Costs |
736,536 |
340,854 | |||
Depreciation, Depletion and Amortization |
816,036 |
928,891 | |||
General and Administrative |
97,238 |
100,531 | |||
Taxes Other Than Income |
130,293 |
60,679 | |||
Total |
2,502,819 |
1,992,490 | |||
Operating Income (Loss) |
107,746 |
(638,141) | |||
Other Income (Expense), Net |
3,151 |
(4,437) | |||
Income (Loss) Before Interest Expense and Income Taxes |
110,897 |
(642,578) | |||
Interest Expense, Net |
71,515 |
68,390 | |||
Income (Loss) Before Income Taxes |
39,382 |
(710,968) | |||
Income Tax Provision (Benefit) |
10,865 |
(239,192) | |||
Net Income (Loss) |
$ |
28,517 |
$ |
(471,776) | |
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 | |
EOG RESOURCES, INC. | |||||
Operating Highlights | |||||
(Unaudited) | |||||
Three Months Ended | |||||
March 31, | |||||
2017 |
2016 | ||||
Wellhead Volumes and Prices |
|||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||
United States |
312.5 |
265.8 | |||
Trinidad |
0.8 |
0.7 | |||
Other International (B) |
2.4 |
1.4 | |||
Total |
315.7 |
267.9 | |||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||
United States |
$ |
50.38 |
$ |
30.87 | |
Trinidad |
41.56 |
22.78 | |||
Other International (B) |
47.77 |
32.33 | |||
Composite |
50.34 |
30.85 | |||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||
United States |
78.8 |
79.4 | |||
Other International (B) |
- |
- | |||
Total |
78.8 |
79.4 | |||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||
United States |
$ |
21.63 |
$ |
10.41 | |
Other International (B) |
- |
- | |||
Composite |
21.63 |
10.41 | |||
Natural Gas Volumes (MMcfd) (A) |
|||||
United States |
728 |
829 | |||
Trinidad |
308 |
361 | |||
Other International (B) |
22 |
25 | |||
Total |
1,058 |
1,215 | |||
Average Natural Gas Prices ($/Mcf) (C) |
|||||
United States |
$ |
2.32 |
$ |
1.27 | |
Trinidad |
2.57 |
1.88 | |||
Other International (B) |
3.76 |
3.63 | |||
Composite |
2.42 |
1.50 | |||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||
United States |
512.6 |
483.6 | |||
Trinidad |
52.2 |
60.8 | |||
Other International (B) |
5.9 |
5.5 | |||
Total |
570.7 |
549.9 | |||
Total MMBoe (D) |
51.4 |
50.0 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. | |||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
March 31, |
December 31, | ||||
2017 |
2016 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,546,566 |
$ |
1,599,895 | |
Accounts Receivable, Net |
1,187,112 |
1,216,320 | |||
Inventories |
314,194 |
350,017 | |||
Assets from Price Risk Management Activities |
1,142 |
- | |||
Income Taxes Receivable |
80,503 |
12,305 | |||
Other |
264,559 |
206,679 | |||
Total |
3,394,076 |
3,385,216 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
50,195,608 |
49,592,091 | |||
Other Property, Plant and Equipment |
3,977,721 |
4,008,564 | |||
Total Property, Plant and Equipment |
54,173,329 |
53,600,655 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(28,566,869) |
(27,893,577) | |||
Total Property, Plant and Equipment, Net |
25,606,460 |
25,707,078 | |||
Deferred Income Taxes |
16,232 |
16,140 | |||
Other Assets |
195,206 |
190,767 | |||
Total Assets |
$ |
29,211,974 |
$ |
29,299,201 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,556,875 |
$ |
1,511,826 | |
Accrued Taxes Payable |
143,710 |
118,411 | |||
Dividends Payable |
96,155 |
96,120 | |||
Liabilities from Price Risk Management Activities |
7,636 |
61,817 | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
221,052 |
232,538 | |||
Total |
2,032,007 |
2,027,291 | |||
Long-Term Debt |
6,980,008 |
6,979,779 | |||
Other Liabilities |
1,248,102 |
1,282,142 | |||
Deferred Income Taxes |
5,023,626 |
5,028,408 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
|||||
577,636,588Shares Issued at March 31, 2017 and 576,950,272 |
|||||
Shares Issued at December 31, 2016 |
205,776 |
205,770 | |||
Additional Paid in Capital |
5,447,291 |
5,420,385 | |||
Accumulated Other Comprehensive Loss |
(18,664) |
(19,010) | |||
Retained Earnings |
8,329,951 |
8,398,118 | |||
Common Stock Held in Treasury, 378,442 Shares at March 31, 2017 |
|||||
and 250,155 Shares at December 31, 2016 |
(36,123) |
(23,682) | |||
Total Stockholders' Equity |
13,928,231 |
13,981,581 | |||
Total Liabilities and Stockholders' Equity |
$ |
29,211,974 |
$ |
29,299,201 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Three Months Ended | |||||
March 31, | |||||
2017 |
2016 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
28,517 |
$ |
(471,776) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
816,036 |
928,891 | |||
Impairments |
193,187 |
71,617 | |||
Stock-Based Compensation Expenses |
30,460 |
32,380 | |||
Deferred Income Taxes |
694 |
(196,696) | |||
(Gains) Losses on Asset Dispositions, Net |
16,758 |
(9,147) | |||
Other, Net |
(3,052) |
5,442 | |||
Dry Hole Costs |
- |
246 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total Gains |
(62,020) |
(5,435) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
1,912 |
17,687 | |||
Other, Net |
(428) |
1,407 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
28,688 |
132,398 | |||
Inventories |
24,736 |
57,578 | |||
Accounts Payable |
20,426 |
(289,627) | |||
Accrued Taxes Payable |
(38,613) |
2,460 | |||
Other Assets |
(44,677) |
3,946 | |||
Other Liabilities |
(51,251) |
7,992 | |||
Changes in Components of Working Capital Associated with Investing and Financing |
|||||
Activities |
(63,324) |
2,228 | |||
Net Cash Provided by Operating Activities |
898,049 |
291,591 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(912,227) |
(547,399) | |||
Additions to Other Property, Plant and Equipment |
(34,336) |
(25,792) | |||
Proceeds from Sales of Assets |
46,812 |
6,667 | |||
Changes in Components of Working Capital Associated with Investing Activities |
63,324 |
(2,228) | |||
Net Cash Used in Investing Activities |
(836,427) |
(568,752) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
- |
(259,718) | |||
Long-Term Debt Borrowings |
- |
991,097 | |||
Long-Term Debt Repayments |
- |
(400,000) | |||
Dividends Paid |
(96,707) |
(92,170) | |||
Treasury Stock Purchased |
(18,628) |
(12,672) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
2,356 |
2,688 | |||
Debt Issuance Costs |
- |
(1,592) | |||
Repayment of Capital Lease Obligation |
(1,619) |
(1,569) | |||
Net Cash (Used in) Provided by Financing Activities |
(114,598) |
226,064 | |||
Effect of Exchange Rate Changes on Cash |
(353) |
1,072 | |||
Decrease in Cash and Cash Equivalents |
(53,329) |
(50,025) | |||
Cash and Cash Equivalents at Beginning of Period |
1,599,895 |
718,506 | |||
Cash and Cash Equivalents at End of Period |
$ |
1,546,566 |
$ |
668,481 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
To Net Income (Loss) (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month periods ended March 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net (gains) losses on asset dispositions in 2017 and 2016, to add back impairment charges related to certain of EOG's assets in 2017 and to add back certain voluntary retirement expense in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
March 31, 2017 |
March 31, 2016 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ 39,382 |
$(10,865) |
$28,517 |
$ 0.05 |
$(710,968) |
$239,192 |
$(471,776) |
$ (0.86) | |||||||
Adjustments: |
|||||||||||||||
Gains on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
(62,020) |
22,191 |
(39,829) |
(0.07) |
(5,435) |
1,938 |
(3,497) |
(0.01) | |||||||
Net Cash Received from Settlements of |
|||||||||||||||
Commodity Derivative Contracts |
1,912 |
(684) |
1,228 |
- |
17,687 |
(6,306) |
11,381 |
0.02 | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
16,758 |
(5,736) |
11,022 |
0.02 |
(9,147) |
3,210 |
(5,937) |
(0.01) | |||||||
Add: Impairments |
137,751 |
(49,287) |
88,464 |
0.15 |
- |
- |
- |
- | |||||||
Add: Voluntary Retirement Expense |
- |
- |
- |
- |
22,391 |
(7,982) |
14,409 |
0.03 | |||||||
Adjustments to Net Income (Loss) |
94,401 |
(33,516) |
60,885 |
0.10 |
25,496 |
(9,140) |
16,356 |
0.03 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$133,783 |
$(44,381) |
$89,402 |
$ 0.15 |
$(685,472) |
$230,052 |
$(455,420) |
$ (0.83) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
573,935 |
546,715 | |||||||||||||
Diluted |
578,593 |
546,715 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
573,935 |
546,715 | |||||||||||||
Diluted |
578,593 |
546,715 |
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||
(Unaudited; in thousands) | ||||||
The following chart reconciles the three-month periods ended March 31, 2017 and 2016 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||
Three Months Ended | ||||||
March 31, | ||||||
2017 |
2016 | |||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
898,049 |
$ |
291,591 | ||
Adjustments: |
||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
50,734 |
23,357 | ||||
Changes in Components of Working Capital and Other Assets |
||||||
and Liabilities |
||||||
Accounts Receivable |
(28,688) |
(132,398) | ||||
Inventories |
(24,736) |
(57,578) | ||||
Accounts Payable |
(20,426) |
289,627 | ||||
Accrued Taxes Payable |
38,613 |
(2,460) | ||||
Other Assets |
44,677 |
(3,946) | ||||
Other Liabilities |
51,251 |
(7,992) | ||||
Changes in Components of Working Capital Associated with |
||||||
Investing and Financing Activities |
63,324 |
(2,228) | ||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,072,798 |
$ |
397,973 | ||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase |
170% |
|||||
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, Net, | ||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | ||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | ||||||
(Non-GAAP) to Net Income (Loss) (GAAP) | ||||||
(Unaudited; in thousands) | ||||||
The following chart adjusts the three-month periods ended March 31, 2017 and 2016 reported Net Income (Loss) (GAAP) to Earnings Before Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Net, Income Taxes (Income Tax Provision (Benefit)), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||
Three Months Ended |
||||||
March 31, |
||||||
2017 |
2016 |
|||||
Net Income (Loss) (GAAP) |
$ |
28,517 |
$ |
(471,776) |
||
Adjustments: |
||||||
Interest Expense, Net |
71,515 |
68,390 |
||||
Income Tax Provision (Benefit) |
10,865 |
(239,192) |
||||
Depreciation, Depletion and Amortization |
816,036 |
928,891 |
||||
Exploration Costs |
56,894 |
29,829 |
||||
Dry Hole Costs |
- |
246 |
||||
Impairments |
193,187 |
71,617 |
||||
EBITDAX (Non-GAAP) |
1,177,014 |
388,005 |
||||
Total Gains on MTM Commodity Derivative Contracts |
(62,020) |
(5,435) |
||||
Net Cash Received from Settlements of Commodity |
||||||
Derivative Contracts |
1,912 |
17,687 |
||||
(Gains) Losses on Asset Dispositions, Net |
16,758 |
(9,147) |
||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,133,664 |
$ |
391,110 |
||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase |
190% |
|||||
EOG RESOURCES, INC. | ||||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | ||||||
Capitalization (Non-GAAP) as Used in the Calculation of | ||||||
The Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | ||||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | ||||||
(Unaudited; in millions, except ratio data) | ||||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | ||||||
At |
At | |||||
March 31, |
December 31, | |||||
2017 |
2016 | |||||
Total Stockholders' Equity - (a) |
$ |
13,928 |
$ |
13,982 | ||
Current and Long-Term Debt (GAAP) - (b) |
6,987 |
6,986 | ||||
Less: Cash |
(1,547) |
(1,600) | ||||
Net Debt (Non-GAAP) - (c) |
5,440 |
5,386 | ||||
Total Capitalization (GAAP) - (a) + (b) |
$ |
20,915 |
$ |
20,968 | ||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,368 |
$ |
19,368 | ||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33% |
33% | ||||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
28% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial Commodity | |||||||||||
Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. On March 14, 2017, EOG executed the optional early termination provision granting EOG the right to terminate certain crude oil price swaps with notional volumes of 30,000 Bbld at a weighted average price of $50.05 per Bbl for the period March 1, 2017 through June 30, 2017. EOG received cash of $4.6 million for the early termination of these contracts. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through May 8, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2017 |
|||||||||||
January 1, 2017 through February 28, 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
March 1, 2017 through June 30, 2017 (closed) |
30,000 |
50.05 | |||||||||
On March 14, 2017, EOG entered into a crude oil price swap contract for the period March 1, 2017 through June 30, 2017, with notional volumes of 5,000 Bbld at a price of $48.81 per Bbl. This contract offsets the remaining crude oil price swap contract for the same time period with notional volumes of 5,000 Bbld at a price of $50.00 per Bbl. The net cash EOG will receive for settling these contracts is $0.7 million. The offsetting contracts were excluded from the above table. | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through May 8, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2017 |
|||||||||||
March 1, 2017 through May 31, 2017 (closed) |
30,000 |
$ 3.10 | |||||||||
June 1, 2017 through November 30, 2017 |
30,000 |
3.10 | |||||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
35,000 |
$ 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through May 8, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2017 |
|||||||||||
March 1, 2017 through May 31, 2017 (closed) |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
June 1, 2017 through November 30, 2017 |
213,750 |
3.44 |
171,000 |
2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through May 8, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMBtu) | |||||||||||
Volume (MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2017 |
|||||||||||
March 1, 2017 through May 31, 2017 (closed) |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
June 1, 2017 through November 30, 2017 |
80,000 |
3.69 |
3.20 | ||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) | ||||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | ||||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | ||||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | ||||||||||||
(Unaudited; in millions, except ratio data) | ||||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Loss) (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income (Loss), Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | ||||||||||||
2016 |
2015 |
2014 |
2013 | |||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
||||||||||||
Net Interest Expense (GAAP) |
$ |
282 |
$ |
237 |
$ |
201 |
||||||
Tax Benefit Imputed (based on 35%) |
(99) |
(83) |
(70) |
|||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
183 |
$ |
154 |
$ |
131 |
||||||
Net Income (Loss) (GAAP) - (b) |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
||||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
204 |
(a) |
4,559 |
(b) |
(199) |
(c) |
||||||
Adjusted Net Income (Loss) (Non-GAAP) - (c) |
$ |
(893) |
$ |
34 |
$ |
2,716 |
||||||
Total Stockholders' Equity - (d) |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | ||||
Average Total Stockholders' Equity * - (e) |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
||||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | ||||
Less: Cash |
(1,600) |
(719) |
(2,087) |
(1,318) | ||||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | ||||
Total Capitalization (GAAP) - (d) + (f) |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | ||||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | ||||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
||||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-4.8% |
-21.6% |
14.7% |
|||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
-3.7% |
0.9% |
13.7% |
|||||||||
Return on Equity (ROE) |
||||||||||||
ROE (GAAP) (GAAP Net Income) - (b) / (e) |
-8.1% |
-29.5% |
17.6% |
|||||||||
ROE (Non-GAAP) (Non-GAAP Adjusted Net Income) - (c) / (e) |
-6.6% |
0.2% |
16.4% |
|||||||||
* Average for the current and immediately preceding year |
||||||||||||
Adjustments to Net Income (Loss) (GAAP) |
||||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: |
||||||||||||
Year Ended December 31, 2016 |
||||||||||||
Before |
Income Tax |
After |
||||||||||
Tax |
Impact |
Tax |
||||||||||
Adjustments: |
||||||||||||
Add: |
Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 |
|||||
Add: |
Impairments of Certain Assets |
321 |
(113) |
208 |
||||||||
Less: |
Net Gains on Asset Dispositions |
(206) |
62 |
(144) |
||||||||
Add: |
Trinidad Tax Settlement |
- |
43 |
43 |
||||||||
Add: |
Voluntary Retirement Expense |
42 |
(15) |
27 |
||||||||
Add: |
Acquisition - State Apportionment Change |
- |
16 |
16 |
||||||||
Add: |
Acquisition Costs |
5 |
- |
5 |
||||||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 |
||||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
||||||||||||
Year Ended December 31, 2015 |
||||||||||||
Before |
Income Tax |
After |
||||||||||
Tax |
Impact |
Tax |
||||||||||
Adjustments: |
||||||||||||
Add: |
Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
|||||
Add: |
Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
||||||||
Less: |
Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
||||||||
Add: |
Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
||||||||
Add: |
Severance Costs |
9 |
(3) |
6 |
||||||||
Add: |
Net Losses on Asset Dispositions |
9 |
(4) |
5 |
||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
||||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
||||||||||||
Year Ended December 31, 2014 |
||||||||||||
Before |
Income Tax |
After |
||||||||||
Tax |
Impact |
Tax |
||||||||||
Adjustments: |
||||||||||||
Less: |
Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
|||||
Add: |
Impairments of Certain Assets |
824 |
(271) |
553 |
||||||||
Less: |
Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
||||||||
Add |
Tax Expense Related to the Repatriation of Accumulated |
|||||||||||
Foreign Earnings in Future Years |
- |
250 |
250 |
|||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
Second Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Second Quarter and Full Year 2017 Forecast |
|||||||||||
The forecast items for the second quarter and full year 2017 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2017 |
Full Year 2017 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
322.0 |
- |
332.0 |
320.0 |
- |
335.0 | |||||
Trinidad |
0.2 |
- |
0.4 |
0.3 |
- |
0.5 | |||||
Other International |
0.0 |
- |
0.0 |
4.0 |
- |
7.0 | |||||
Total |
322.2 |
- |
332.4 |
324.3 |
- |
342.5 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
72.0 |
- |
78.0 |
72.0 |
- |
82.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
710 |
- |
750 |
725 |
- |
760 | |||||
Trinidad |
280 |
- |
320 |
275 |
- |
315 | |||||
Other International |
18 |
- |
24 |
25 |
- |
30 | |||||
Total |
1,008 |
- |
1,094 |
1,025 |
- |
1,105 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
512.3 |
- |
535.0 |
512.8 |
- |
543.7 | |||||
Trinidad |
46.9 |
- |
53.7 |
46.1 |
- |
53.0 | |||||
Other International |
3.0 |
- |
4.0 |
8.2 |
- |
12.0 | |||||
Total |
562.2 |
- |
592.7 |
567.1 |
- |
608.7 | |||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
2Q 2017 |
Full Year 2017 | ||||||||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.60 |
- |
$ |
5.00 |
$ |
4.25 |
- |
$ |
4.95 | |
Transportation Costs |
$ |
3.20 |
- |
$ |
3.60 |
$ |
3.10 |
- |
$ |
3.70 | |
Depreciation, Depletion and Amortization |
$ |
15.70 |
- |
$ |
16.10 |
$ |
15.50 |
- |
$ |
16.00 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
95 |
- |
$ |
125 |
$ |
415 |
- |
$ |
465 | |
General and Administrative |
$ |
85 |
- |
$ |
95 |
$ |
365 |
- |
$ |
395 | |
Gathering and Processing |
$ |
28 |
- |
$ |
30 |
$ |
125 |
- |
$ |
145 | |
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
25 |
- |
$ |
30 | |
Net Interest |
$ |
69 |
- |
$ |
72 |
$ |
273 |
- |
$ |
283 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.9% |
- |
7.3% |
6.5% |
- |
6.9% | |||||
Income Taxes |
|||||||||||
Effective Rate |
32% |
- |
37% |
31% |
- |
36% | |||||
Current Taxes ($MM) |
$ |
50 |
- |
$ |
85 |
$ |
135 |
- |
$ |
175 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
3,000 |
- |
$ |
3,350 | ||||||
Exploration and Development Facilities |
$ |
475 |
- |
$ |
510 | ||||||
Gathering, Processing and Other |
$ |
225 |
- |
$ |
240 | ||||||
Pricing - (Refer toBenchmark Commodity Pricingin text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(2.00) |
- |
$ |
0.00 |
$ |
(2.50) |
- |
$ |
(0.50) | |
Trinidad - above (below) WTI |
$ |
(11.00) |
- |
$ |
(9.00) |
$ |
(11.00) |
- |
$ |
(9.00) | |
Other International - above (below) WTI |
$ |
(4.00) |
- |
$ |
2.00 |
$ |
(7.00) |
- |
$ |
1.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
36% |
- |
44% |
36% |
- |
44% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.10) |
- |
$ |
(0.60) |
$ |
(1.15) |
- |
$ |
(0.65) | |
Realizations |
|||||||||||
Trinidad |
$ |
2.20 |
- |
$ |
2.60 |
$ |
2.10 |
- |
$ |
2.70 | |
Other International |
$ |
3.30 |
- |
$ |
3.80 |
$ |
3.30 |
- |
$ |
4.30 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, April 27, 2017 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable July 31, 2017, to stockholders of record as of July 17, 2017. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, April 4, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss first quarter 2017 results on Tuesday, May 9, 2017, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 27, 2017 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a fourth quarter 2016 net loss of $142.4 million, or $0.25 per share. This compares to a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share. For full year 2016, EOG reported a net loss of $1.1 billion, or $1.98 per share, compared to a net loss of $4.5 billion, or $8.29 per share, for the full year 2015.
Adjusted non-GAAP net loss for the fourth quarter 2016 was $6.7 million, or $0.01 per share, compared to adjusted non-GAAP net loss of $149.5 million, or $0.27 per share, for the same prior year period. Adjusted non-GAAP net loss for the full year 2016 was $892.6 million, or $1.61 per share, compared to adjusted non-GAAP net income of $33.9 million, or $0.06 per share, for the full year 2015. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Higher crude oil, NGL and natural gas prices, significant well productivity improvements, and lease and well cost reductions resulted in increases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX for the fourth quarter 2016 compared to the fourth quarter 2015. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Operational Highlights
Tremendous capital efficiency improvements in 2016 offset the impact of a significant reduction in capital expenditures resulting from low oil prices. 2016 total company crude oil and condensate volumes declined less than one percent to 282,500 barrels of oil per day (Bopd) while exploration and development expenditures (excluding acquisitions) decreased 42 percent compared to 2015. Increased development activity and significant well productivity improvements drove substantial volume increases in the Delaware Basin, with additional growth from the Powder River and DJ Basins. These contributions were offset by volume declines in the Bakken and Eagle Ford resulting from lower activity levels. Natural gas liquids volumes grew 6 percent while natural gas volumes decreased 7 percent primarily due to natural decline and the sale of the company's Barnett and Haynesville Shale dry gas assets. Compared to the same prior year period, lease and well expenses decreased 20 percent and transportation expenses decreased 8 percent, both on a per-unit basis. Total operating costs, which includes lease and well, transportation, gathering and processing, and general and administrative expenses, were down 15 percent year over year.
"EOG achieved near company-record returns on new capital in 2016 in spite of the lowest crude oil prices in 13 years," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Through continued improvements in well productivity, cost reductions and expanded resource potential, EOG is positioned to excel as crude oil prices continue to recover. More than ever, EOG continues to lead the industry through its innovative technology and disciplined culture."
2017 Capital Plan
EOG's 2017 plan is designed to maximize returns and grow crude oil volumes while maintaining a strong balance sheet through disciplined spending. EOG expects to grow total company crude oil volumes by 18 percent, assuming investment and dividend payments within cash flow at a $50 average oil price.
Capital expenditures for 2017 are expected to range from $3.7 to $4.1 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. The company expects to complete approximately 480 net wells in 2017, compared to 445 net wells in 2016. EOG anticipates flat to lower completed well costs in 2017 versus 2016 levels as continued efficiencies and service contract expirations are expected to offset potential cost increases.
Capital will be allocated primarily to EOG's highest rate-of-return oil assets in the Eagle Ford, Delaware Basin, Rockies and the Bakken. After reducing the drilled uncompleted well inventory to a normal operating level in 2016, the company will increase its focus on its 6,000 remaining premium drilling locations. EOG is capable of delivering very strong rates of return in the current commodity price environment through premium drilling combined with the company's expectations that well costs will remain flat or lower in 2017. Premium inventory includes wells with a direct after-tax rate of return of at least 30 percent assuming $40 flat crude oil prices.
"EOG's goal during the last two years was to exit the industry downturn in better shape than when we entered it," Thomas said. "We clearly accomplished that goal with spectacular improvements in all facets of the business. We made major technology advances in our proprietary well targeting, completion designs, drilling practices and production operations. EOG is now set to resume strong oil growth within cash flow."
Delaware Basin
In the fourth quarter 2016, EOG continued active development of its world-class position in the Delaware Basin. EOG integrated the assets acquired in the Yates transaction and further optimized its proprietary well targeting methods across its expanded position of 416,000 net acres.
EOG completed 17 wells in the Delaware Basin Wolfcamp in the fourth quarter with an average treated lateral length of 4,900 feet per well and average 30-day initial production rates per well of 2,405 barrels of oil equivalent per day (Boed), or 1,595 Bopd, 365 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.7 million cubic feet per day (MMcfd) of natural gas. In Lea County, N.M., EOG completed the Endurance 36 State Com #705H and #706H with an average treated lateral length of 7,000 feet per well and average 30-day initial production rates per well of 2,495 Bopd, 505 Bpd of NGLs and 3.7 MMcfd of natural gas.
In the Delaware Basin Bone Spring, EOG completed three wells in the fourth quarter with an average treated lateral length of 4,400 feet per well and average 30-day initial production rates per well of 1,680 Boed, or 1,280 Bopd, 180 Bpd of NGLs and 1.3 MMcfd of natural gas. In Lea County, N.M., EOG completed the Della 29 Fed Com #602H with a treated lateral of 4,500 feet and 30-day initial production rates of 1,905 Bopd, 225 Bpd of NGLs and 1.7 MMcfd of natural gas. This well is six miles north of EOG's next closest Bone Spring well.
In the Delaware Basin Leonard, EOG completed eight wells in the fourth quarter with an average treated lateral length of 4,600 feet per well and average 30-day initial production rates per well of 1,745 Boed, or 985 Bopd, 345 Bpd of NGLs and 2.5 MMcfd of natural gas. In Lea County, N.M., EOG completed the Leghorn 32 State #201H with a treated lateral of 4,500 feet and 30-day initial production rates of 2,550 Bopd, 480 Bpd of NGLs and 3.6 MMcfd of natural gas. This well is 12 miles north of EOG's next closest Leonard well.
South Texas Eagle Ford
EOG continued to achieve strong well results and efficiencies in the South Texas Eagle Ford in the fourth quarter 2016. For the full year 2016, crude oil production declined just 8 percent year-over-year, despite a 28 percent reduction in the number of well completions.
In the fourth quarter, EOG completed 75 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and average 30-day initial production rates per well of 1,190 Boed, or 990 Bopd, 85 Bpd of NGLs and 0.7 MMcfd of natural gas. The fourth quarter 2016 completions in the Eagle Ford included 45 wells that were drilled prior to 2016.
South Texas Austin Chalk
EOG continued to test its position in the South Texas Austin Chalk, which lies above the South Texas Eagle Ford. In the fourth quarter, EOG completed nine wells in the Austin Chalk with an average treated lateral length of 4,100 feet per well and average 30-day initial production rates per well of 1,975 Boed, or 1,475 Bopd, 220 Bpd of NGLs and 1.7 MMcfd of natural gas.
Rockies and the Bakken
During the fourth quarter, EOG significantly reduced its inventory of drilled uncompleted wells in the Rockies and the Bakken.
In the Powder River Basin, EOG completed three wells in the fourth quarter with average 30-day initial production rates per well of 2,155 Boed, or 1,810 Bopd, 135 Bpd of NGLs and 1.3 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed 34 wells in the fourth quarter with average 30-day initial production rates per well of 820 Boed, or 715 Bopd, 55 Bpd of NGLs and 0.3 MMcfd of natural gas. The fourth quarter 2016 completions in the Bakken included 31 wells that were drilled prior to 2016.
Reserves
At year-end 2016, total company net proved reserves were 2,147 million barrels of oil equivalent (MMBoe), comprised of 55 percent crude oil and condensate, 19 percent NGLs and 26 percent natural gas. Net proved reserve additions from all sources excluding revisions due to price replaced 163 percent of EOG's 2016 production at a finding and development cost of $5.22 per barrel of oil equivalent. Revisions due to price reduced net proved reserves by 101 MMBoe and asset divestitures decreased net proved reserves by 168 MMBoe. Total company net proved reserves increased 1.4 percent in 2016 as proved reserve additions from drilling activities and revisions other than price offset the impact of asset divestitures and declines in commodity prices. (For more reserves detail and a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.)
For the 29th consecutive year, internal reserves estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.
Hedging Activity
For the period January 1 through June 30, 2017, EOG has crude oil financial price swap contracts in place for 35,000 Bopd at a weighted average price of $50.04 per barrel.
For the period March 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu. For the period March 1 through November 30, 2018, EOG has natural gas financial price swap contracts in place for 35,000 MMBtu per day at a weighted average price of $3.00 per MMBtu.
For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.
For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.
For the period March 1 through November 30, 2017, EOG has natural gas collar contracts for 80,000 MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of $3.20 per MMBtu.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At December 31, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 33 percent. Considering cash on the balance sheet of $1.6 billion at the end of the fourth quarter, EOG's net debt was $5.4 billion with a net debt-to-total capitalization ratio of 28 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales for the full year 2016 totaled $1.1 billion, which includes $662 million of proceeds from sales made during the fourth quarter 2016. Associated production of the divested assets in 2016 at the time of each respective sale was an aggregate 220 MMcfd of natural gas, 4,000 Bopd and 8,800 Bpd of NGLs (this was partially offset by the full year impact of acquired production from the Yates transaction of 2,900 Bopd, 150 Bpd of NGLs and 20 MMcfd of natural gas).
Dividend
The board of directors declared a dividend of $0.1675 per share on EOG's Common Stock, payable April 28, 2017, to stockholders of record as of April 13, 2017. The indicated annual rate is $0.67 per share.
Conference Call February 28, 2017
EOG's fourth quarter and full year 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Tuesday, February 28, 2017. To access the live audio webcast and related presentation materials, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
$ |
2,402.0 |
$ |
1,796.8 |
$ |
7,650.6 |
$ |
8,757.4 | |||
Net Loss |
$ |
(142.4) |
$ |
(284.3) |
$ |
(1,096.7) |
$ |
(4,524.5) | |||
Net Loss Per Share |
|||||||||||
Basic |
$ |
(0.25) |
$ |
(0.52) |
$ |
(1.98) |
$ |
(8.29) | |||
Diluted |
$ |
(0.25) |
$ |
(0.52) |
$ |
(1.98) |
$ |
(8.29) | |||
Average Number of Common Shares |
|||||||||||
Basic |
567.3 |
546.4 |
553.4 |
545.7 | |||||||
Diluted |
567.3 |
546.4 |
553.4 |
545.7 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
|||||||||||
Crude Oil and Condensate |
$ |
1,366,223 |
$ |
1,040,470 |
$ |
4,317,341 |
$ |
4,934,562 | |||
Natural Gas Liquids |
137,849 |
96,521 |
437,250 |
407,658 | |||||||
Natural Gas |
215,373 |
217,381 |
742,152 |
1,061,038 | |||||||
Gains (Losses) on Mark-to-Market Commodity |
(65,787) |
4,970 |
(99,608) |
61,924 | |||||||
Gathering, Processing and Marketing |
614,594 |
432,292 |
1,966,259 |
2,253,135 | |||||||
Gains (Losses) on Asset Dispositions, Net |
104,034 |
(3,656) |
205,835 |
(8,798) | |||||||
Other, Net |
29,753 |
8,783 |
81,403 |
47,909 | |||||||
Total |
2,402,039 |
1,796,761 |
7,650,632 |
8,757,428 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
241,846 |
247,916 |
927,452 |
1,182,282 | |||||||
Transportation Costs |
193,319 |
207,580 |
764,106 |
849,319 | |||||||
Gathering and Processing Costs |
32,516 |
39,653 |
122,901 |
146,156 | |||||||
Exploration Costs |
39,110 |
34,946 |
124,953 |
149,494 | |||||||
Dry Hole Costs |
193 |
429 |
10,657 |
14,746 | |||||||
Impairments |
297,946 |
168,171 |
620,267 |
6,613,546 | |||||||
Marketing Costs |
634,248 |
461,848 |
2,007,635 |
2,385,982 | |||||||
Depreciation, Depletion and Amortization |
862,524 |
769,457 |
3,553,417 |
3,313,644 | |||||||
General and Administrative |
102,182 |
109,014 |
394,815 |
366,594 | |||||||
Taxes Other Than Income |
103,642 |
87,500 |
349,710 |
421,744 | |||||||
Total |
2,507,526 |
2,126,514 |
8,875,913 |
15,443,507 | |||||||
Operating Loss |
(105,487) |
(329,753) |
(1,225,281) |
(6,686,079) | |||||||
Other (Expense) Income, Net |
(17,198) |
(6,080) |
(50,543) |
1,916 | |||||||
Loss Before Interest Expense and Income Taxes |
(122,685) |
(335,833) |
(1,275,824) |
(6,684,163) | |||||||
Interest Expense, Net |
71,325 |
62,993 |
281,681 |
237,393 | |||||||
Loss Before Income Taxes |
(194,010) |
(398,826) |
(1,557,505) |
(6,921,556) | |||||||
Income Tax Benefit |
(51,658) |
(114,530) |
(460,819) |
(2,397,041) | |||||||
Net Loss |
$ |
(142,352) |
$ |
(284,296) |
$ |
(1,096,686) |
$ |
(4,524,515) | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.6700 |
$ |
0.6700 |
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
306.0 |
279.9 |
278.3 |
283.3 | |||||||
Trinidad |
0.9 |
0.9 |
0.8 |
0.9 | |||||||
Other International (B) |
4.8 |
0.2 |
3.4 |
0.2 | |||||||
Total |
311.7 |
281.0 |
282.5 |
284.4 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
47.93 |
$ |
40.34 |
$ |
41.84 |
$ |
47.55 | |||
Trinidad |
40.04 |
32.38 |
33.76 |
39.51 | |||||||
Other International (B) |
38.96 |
53.28 |
36.72 |
57.32 | |||||||
Composite |
47.76 |
40.32 |
41.76 |
47.53 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
80.9 |
79.1 |
81.6 |
76.9 | |||||||
Other International (B) |
- |
- |
- |
0.1 | |||||||
Total |
80.9 |
79.1 |
81.6 |
77.0 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
18.51 |
$ |
13.25 |
$ |
14.63 |
$ |
14.50 | |||
Other International (B) |
- |
- |
- |
4.61 | |||||||
Composite |
18.51 |
13.25 |
14.63 |
14.49 | |||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
800 |
860 |
810 |
886 | |||||||
Trinidad |
323 |
370 |
340 |
349 | |||||||
Other International (B) |
22 |
27 |
25 |
30 | |||||||
Total |
1,145 |
1,257 |
1,175 |
1,265 | |||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
2.05 |
$ |
1.44 |
$ |
1.60 |
$ |
1.97 | |||
Trinidad |
1.89 |
2.57 |
1.88 |
2.89 | |||||||
Other International (B) |
3.85 |
6.51 |
3.64 |
5.05 | |||||||
Composite |
2.04 |
1.88 |
1.73 |
2.30 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
520.3 |
502.2 |
494.9 |
507.9 | |||||||
Trinidad |
54.6 |
62.7 |
57.5 |
59.1 | |||||||
Other International (B) |
8.6 |
4.6 |
7.6 |
5.2 | |||||||
Total |
583.5 |
569.5 |
560.0 |
572.2 | |||||||
Total MMBoe (D) |
53.7 |
52.4 |
205.0 |
208.9 | |||||||
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. The Argentina operations were sold in the third quarter of 2016. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
December 31, |
December 31, | ||||
2016 |
2015 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,599,895 |
$ |
718,506 | |
Accounts Receivable, Net |
1,216,320 |
930,610 | |||
Inventories |
350,017 |
598,935 | |||
Income Taxes Receivable |
12,305 |
40,704 | |||
Deferred Income Taxes |
169,387 |
147,812 | |||
Other |
206,679 |
155,677 | |||
Total |
3,554,603 |
2,592,244 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
49,592,091 |
50,613,241 | |||
Other Property, Plant and Equipment |
4,008,564 |
3,986,610 | |||
Total Property, Plant and Equipment |
53,600,655 |
54,599,851 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(27,893,577) |
(30,389,130) | |||
Total Property, Plant and Equipment, Net |
25,707,078 |
24,210,721 | |||
Other Assets |
197,752 |
167,505 | |||
Total Assets |
$ |
29,459,433 |
$ |
26,970,470 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,511,826 |
$ |
1,471,953 | |
Accrued Taxes Payable |
118,411 |
93,618 | |||
Dividends Payable |
96,120 |
91,546 | |||
Liabilities from Price Risk Management Activities |
61,817 |
- | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
232,538 |
155,591 | |||
Total |
2,027,291 |
1,819,287 | |||
Long-Term Debt |
6,979,779 |
6,648,911 | |||
Other Liabilities |
1,282,142 |
971,335 | |||
Deferred Income Taxes |
5,188,640 |
4,587,902 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
205,770 |
205,502 | |||
Additional Paid in Capital |
5,420,385 |
2,923,461 | |||
Accumulated Other Comprehensive Loss |
(19,010) |
(33,338) | |||
Retained Earnings |
8,398,118 |
9,870,816 | |||
Common Stock Held in Treasury, 250,155 Shares and 292,179 Shares at |
(23,682) |
(23,406) | |||
Total Stockholders' Equity |
13,981,581 |
12,943,035 | |||
Total Liabilities and Stockholders' Equity |
$ |
29,459,433 |
$ |
26,970,470 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Twelve Months Ended | |||||
December 31, | |||||
2016 |
2015 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Loss to Net Cash Provided by Operating Activities: |
|||||
Net Loss |
$ |
(1,096,686) |
$ |
(4,524,515) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
3,553,417 |
3,313,644 | |||
Impairments |
620,267 |
6,613,546 | |||
Stock-Based Compensation Expenses |
128,090 |
130,577 | |||
Deferred Income Taxes |
(515,206) |
(2,482,307) | |||
(Gains) Losses on Asset Dispositions, Net |
(205,835) |
8,798 | |||
Other, Net |
61,690 |
11,896 | |||
Dry Hole Costs |
10,657 |
14,746 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total Losses (Gains) |
99,608 |
(61,924) | |||
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts |
(22,219) |
730,114 | |||
Excess Tax Benefits from Stock-Based Compensation |
(29,357) |
(26,058) | |||
Other, Net |
10,971 |
12,532 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(232,799) |
641,412 | |||
Inventories |
170,694 |
58,450 | |||
Accounts Payable |
(74,048) |
(1,409,197) | |||
Accrued Taxes Payable |
92,782 |
11,798 | |||
Other Assets |
(40,636) |
118,143 | |||
Other Liabilities |
(16,225) |
(66,257) | |||
Changes in Components of Working Capital Associated with Investing and Financing |
(156,102) |
499,767 | |||
Net Cash Provided by Operating Activities |
2,359,063 |
3,595,165 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(2,489,756) |
(4,725,150) | |||
Additions to Other Property, Plant and Equipment |
(93,039) |
(288,013) | |||
Proceeds from Sales of Assets |
1,119,215 |
192,807 | |||
Net Cash Received from Yates Acquisition |
54,534 |
- | |||
Changes in Components of Working Capital Associated with Investing Activities |
156,102 |
(499,900) | |||
Net Cash Used in Investing Activities |
(1,252,944) |
(5,320,256) | |||
Financing Cash Flows |
|||||
Net Commercial Paper (Repayments) Borrowings |
(259,718) |
259,718 | |||
Long-Term Debt Borrowings |
991,097 |
990,225 | |||
Long-Term Debt Repayments |
(563,829) |
(500,000) | |||
Dividends Paid |
(372,845) |
(367,005) | |||
Excess Tax Benefits from Stock-Based Compensation |
29,357 |
26,058 | |||
Treasury Stock Purchased |
(82,125) |
(48,791) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
23,296 |
22,690 | |||
Debt Issuance Costs |
(1,602) |
(5,951) | |||
Repayment of Capital Lease Obligation |
(6,353) |
(6,156) | |||
Other, Net |
- |
133 | |||
Net Cash (Used in) Provided by Financing Activities |
(242,722) |
370,921 | |||
Effect of Exchange Rate Changes on Cash |
17,992 |
(14,537) | |||
Increase (Decrease) in Cash and Cash Equivalents |
881,389 |
(1,368,707) | |||
Cash and Cash Equivalents at Beginning of Period |
718,506 |
2,087,213 | |||
Cash and Cash Equivalents at End of Period |
$ |
1,599,895 |
$ |
718,506 | |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
To Net Loss (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to add back impairment charges related to certain of EOG's assets in 2016 and 2015, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, and to add back acquisition costs and state apportionment change related to the Yates transaction in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
December 31, 2016 |
December 31, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Loss (GAAP) |
$ (194,010) |
$ 51,658 |
$ (142,352) |
$ (0.25) |
$ (398,826) |
$ 114,530 |
$ (284,296) |
$ (0.52) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
65,787 |
(23,583) |
42,204 |
0.07 |
(4,970) |
1,772 |
(3,198) |
(0.01) | |||||||
Net Cash Received from Settlements of |
- |
29 |
29 |
- |
69,093 |
(24,632) |
44,461 |
0.08 | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
(104,034) |
36,856 |
(67,178) |
(0.12) |
3,656 |
(735) |
2,921 |
0.01 | |||||||
Add: Impairments |
217,839 |
(76,728) |
141,111 |
0.25 |
94,484 |
(16,335) |
78,149 |
0.15 | |||||||
Add: Legal Settlement - Early Leasehold Termination |
- |
- |
- |
- |
19,355 |
(6,900) |
12,455 |
0.02 | |||||||
Add: Voluntary Retirement Expense |
- |
(57) |
(57) |
- |
- |
- |
- |
- | |||||||
Add: Acquisition - State Apportionment Change |
- |
16,424 |
16,424 |
0.03 |
- |
- |
- |
- | |||||||
Add: Acquisition Costs |
2,173 |
955 |
3,128 |
0.01 |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
181,765 |
(46,104) |
135,661 |
0.24 |
181,618 |
(46,830) |
134,788 |
0.25 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ (12,245) |
$ 5,554 |
$ (6,691) |
$ (0.01) |
$ (217,208) |
$ 67,700 |
$ (149,508) |
$ (0.27) | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
567,337 |
546,432 | |||||||||||||
Diluted |
567,337 |
546,432 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
567,337 |
546,432 | |||||||||||||
Diluted |
567,337 |
546,432 | |||||||||||||
Twelve Months Ended |
Twelve Months Ended | ||||||||||||||
December 31, 2016 |
December 31, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Loss (GAAP) |
$(1,557,505) |
$460,819 |
$(1,096,686) |
$ (1.98) |
$(6,921,556) |
$2,397,041 |
$(4,524,515) |
$ (8.29) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
99,608 |
(35,640) |
63,968 |
0.12 |
(61,924) |
22,076 |
(39,848) |
(0.07) | |||||||
Net Cash Received from (Payments for) |
(22,219) |
7,950 |
(14,269) |
(0.03) |
730,114 |
(260,286) |
469,828 |
0.86 | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
(205,835) |
61,491 |
(144,344) |
(0.26) |
8,798 |
(4,183) |
4,615 |
0.01 | |||||||
Add: Impairments |
320,617 |
(113,368) |
207,249 |
0.37 |
6,307,592 |
(2,182,220) |
4,125,372 |
7.56 | |||||||
Add: Legal Settlement - Early Leasehold Termination |
- |
- |
- |
- |
19,355 |
(6,900) |
12,455 |
0.02 | |||||||
Less: Texas Margin Tax Rate Reduction |
- |
- |
- |
- |
- |
(19,500) |
(19,500) |
(0.04) | |||||||
Add: Severance Costs |
- |
- |
- |
- |
8,505 |
(3,032) |
5,473 |
0.01 | |||||||
Add: Trinidad Tax Settlement |
- |
43,000 |
43,000 |
0.08 |
- |
- |
- |
- | |||||||
Add: Voluntary Retirement Expense |
42,054 |
(15,047) |
27,007 |
0.05 |
- |
- |
- |
- | |||||||
Add: Acquisition - State Apportionment Change |
- |
16,424 |
16,424 |
0.03 |
- |
- |
- |
- | |||||||
Add: Acquisition Costs |
5,100 |
(88) |
5,012 |
0.01 |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
239,325 |
(35,278) |
204,047 |
0.37 |
7,012,440 |
(2,454,045) |
4,558,395 |
8.35 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$(1,318,180) |
$425,541 |
$ (892,639) |
$ (1.61) |
$ 90,884 |
$ (57,004) |
$ 33,880 |
$ 0.06 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
553,384 |
545,697 | |||||||||||||
Diluted |
553,384 |
545,697 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
553,384 |
545,697 | |||||||||||||
Diluted |
553,384 |
549,610 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
To Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||||
December 31, |
December 31, | |||||||||||
2016 |
2015 |
2016 |
2015 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
804,745 |
$ |
615,813 |
$ |
2,359,063 |
$ |
3,595,165 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
33,931 |
28,758 |
104,199 |
124,011 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
7,286 |
1,839 |
29,357 |
26,058 | ||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||
and Liabilities |
||||||||||||
Accounts Receivable |
220,939 |
(193,101) |
232,799 |
(641,412) | ||||||||
Inventories |
(33,131) |
(31,443) |
(170,694) |
(58,450) | ||||||||
Accounts Payable |
(127,165) |
98,986 |
74,048 |
1,409,197 | ||||||||
Accrued Taxes Payable |
21,214 |
65,777 |
(92,782) |
(11,798) | ||||||||
Other Assets |
28,110 |
28,822 |
40,636 |
(118,143) | ||||||||
Other Liabilities |
53,024 |
50,574 |
16,225 |
66,257 | ||||||||
Changes in Components of Working Capital Associated with |
36,342 |
19,436 |
156,102 |
(499,767) | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
1,045,295 |
$ |
685,461 |
$ |
2,748,953 |
$ |
3,891,118 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Increase/Decrease |
52% |
-29% |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Loss (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Loss (GAAP) |
$ |
(142,352) |
$ |
(284,296) |
$ |
(1,096,686) |
$ |
(4,524,515) | |||
Adjustments: |
|||||||||||
Interest Expense, Net |
71,325 |
62,993 |
281,681 |
237,393 | |||||||
Income Tax Benefit |
(51,658) |
(114,530) |
(460,819) |
(2,397,041) | |||||||
Depreciation, Depletion and Amortization |
862,524 |
769,457 |
3,553,417 |
3,313,644 | |||||||
Exploration Costs |
39,110 |
34,946 |
124,953 |
149,494 | |||||||
Dry Hole Costs |
193 |
429 |
10,657 |
14,746 | |||||||
Impairments |
297,946 |
168,171 |
620,267 |
6,613,546 | |||||||
EBITDAX (Non-GAAP) |
1,077,088 |
637,170 |
3,033,470 |
3,407,267 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
65,787 |
(4,970) |
99,608 |
(61,924) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity Derivative Contracts |
- |
69,093 |
(22,219) |
730,114 | |||||||
(Gains) Losses on Asset Dispositions, Net |
(104,034) |
3,656 |
(205,835) |
8,798 | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
1,038,841 |
$ |
704,949 |
$ |
2,905,024 |
$ |
4,084,255 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Increase/Decrease |
47% |
-29% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
December 31, |
December 31, | ||||
2016 |
2015 | ||||
Total Stockholders' Equity - (a) |
$ |
13,982 |
$ |
12,943 | |
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,655 | |||
Less: Cash |
(1,600) |
(719) | |||
Net Debt (Non-GAAP) - (c) |
5,386 |
5,936 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
20,968 |
$ |
19,598 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
19,368 |
$ |
18,879 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
33% |
34% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
28% |
31% |
EOG RESOURCES, INC. | ||||||||
Reserves Supplemental Data | ||||||||
(Unaudited) | ||||||||
2016 NET PROVED RESERVES RECONCILIATION SUMMARY |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
CRUDE OIL & CONDENSATE (MMBbl) |
||||||||
Beginning Reserves |
1,087.9 |
1.1 |
8.6 |
1,097.6 |
||||
Revisions |
42.0 |
- |
0.9 |
42.9 |
||||
Purchases in place |
25.8 |
- |
- |
25.8 |
||||
Extensions, discoveries and other additions |
123.4 |
- |
- |
123.4 |
||||
Sales in place |
(8.7) |
- |
- |
(8.7) |
||||
Production |
(101.9) |
(0.3) |
(1.2) |
(103.4) |
||||
Ending Reserves |
1,168.5 |
0.8 |
8.3 |
1,177.6 |
||||
NATURAL GAS LIQUIDS (MMBbl) |
||||||||
Beginning Reserves |
382.9 |
- |
- |
382.9 |
||||
Revisions |
53.7 |
- |
- |
53.7 |
||||
Purchases in place |
1.3 |
- |
- |
1.3 |
||||
Extensions, discoveries and other additions |
41.9 |
- |
- |
41.9 |
||||
Sales in place |
(33.5) |
- |
- |
(33.5) |
||||
Production |
(29.9) |
- |
- |
(29.9) |
||||
Ending Reserves |
416.4 |
- |
- |
416.4 |
||||
NATURAL GAS (Bcf) |
||||||||
Beginning Reserves |
3,489.8 |
316.6 |
19.5 |
3,825.9 |
||||
Revisions |
298.4 |
29.5 |
5.2 |
333.1 |
||||
Purchases in place |
91.5 |
- |
- |
91.5 |
||||
Extensions, discoveries and other additions |
202.1 |
59.9 |
- |
262.0 |
||||
Sales in place |
(752.0) |
- |
- |
(752.0) |
||||
Production |
(308.6) |
(125.1) |
(8.9) |
(442.6) |
||||
Ending Reserves |
3,021.2 |
280.9 |
15.8 |
3,317.9 |
||||
OIL EQUIVALENTS (MMBoe) |
||||||||
Beginning Reserves |
2,052.3 |
53.8 |
12.0 |
2,118.1 |
||||
Revisions |
145.5 |
5.0 |
1.7 |
152.2 |
||||
Purchases in place |
42.3 |
- |
- |
42.3 |
||||
Extensions, discoveries and other additions |
199.0 |
10.0 |
- |
209.0 |
||||
Sales in place |
(167.6) |
- |
- |
(167.6) |
||||
Production |
(183.2) |
(21.1) |
(2.8) |
(207.1) |
||||
Ending Reserves |
2,088.3 |
47.7 |
10.9 |
2,146.9 |
||||
Net Proved Developed Reserves (MMBoe) |
||||||||
At December 31, 2015 |
1,018.5 |
50.7 |
3.3 |
1,072.5 |
||||
At December 31, 2016 |
1,038.5 |
44.5 |
10.9 |
1,093.9 |
||||
2016 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Acquisition Cost of Unproved Properties |
$3,216.6 |
$ - |
$ - |
$3,216.6 |
||||
Exploration Costs |
156.3 |
2.7 |
6.8 |
165.8 |
||||
Development Costs |
2,228.0 |
75.4 |
30.3 |
2,333.7 |
||||
Total Drilling |
5,600.9 |
78.1 |
37.1 |
5,716.1 |
||||
Acquisition Cost of Proved Properties |
749.0 |
- |
- |
749.0 |
||||
Total Exploration & Development Expenditures |
6,349.9 |
78.1 |
37.1 |
6,465.1 |
||||
Gathering, Processing and Other |
108.6 |
- |
0.2 |
108.8 |
||||
Asset Retirement Costs |
24.7 |
(3.2) |
(41.4) |
(19.9) |
||||
Total Expenditures |
6,483.2 |
74.9 |
(4.1) |
6,554.0 |
||||
Proceeds from Sales in Place |
(1,109.4) |
- |
(9.2) |
(1,118.6) |
||||
Net Expenditures |
$5,373.8 |
$ 74.9 |
$ (13.3) |
$5,435.4 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe ) * |
||||||||
All-in Total, Net of Revisions |
$ 6.50 |
$ 5.21 |
$ 21.82 |
$ 6.52 |
||||
All-in Total, Excluding Revisions Due to Price |
$ 5.14 |
$ 6.05 |
$ 21.82 |
$ 5.22 |
||||
RESERVE REPLACEMENT * |
||||||||
Drilling Only |
109% |
47% |
0% |
101% |
||||
All-in Total, Net of Revisions & Dispositions |
120% |
71% |
61% |
114% |
||||
All-in Total, Excluding Revisions Due to Price |
176% |
61% |
61% |
163% |
||||
All-in Total, Liquids |
187% |
0% |
75% |
185% |
||||
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures (Non-GAAP) | ||||||||
As Used in the Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | ||||||||
(Unaudited; in millions, except ratio information) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including an "All-In" calculation, which reflects total exploration and development expenditures divided by total net proved reserve additions from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||
For the Twelve Months Ended December 31, 2016 |
||||||||
United |
Other |
|||||||
States |
Trinidad |
International |
Total |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,374.6 |
$ 74.9 |
$ (4.3) |
$ 6,445.2 |
||||
Less: Asset Retirement Costs |
(24.7) |
3.2 |
41.4 |
19.9 |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(3,101.8) |
- |
- |
(3,101.8) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(732.3) |
- |
- |
(732.3) |
||||
Total Exploration & Development Expenditures (Non-GAAP) (a) |
$ 2,515.8 |
$ 78.1 |
$ 37.1 |
$ 2,631.0 |
||||
Total Expenditures (GAAP) |
$ 6,483.2 |
$ 74.9 |
$ (4.1) |
$ 6,554.0 |
||||
Less: Asset Retirement Costs |
(24.7) |
3.2 |
41.4 |
19.9 |
||||
Non-Cash Acquisition Costs of Unproved Properties |
(3,101.8) |
- |
- |
(3,101.8) |
||||
Non-Cash Acquisition Costs of Proved Properties |
(732.3) |
- |
- |
(732.3) |
||||
Non-Cash Acquisition Costs of Other Assets |
(16.6) |
- |
- |
(16.6) |
||||
Total Cash Expenditures (Non-GAAP) |
$ 2,607.8 |
$ 78.1 |
$ 37.3 |
$ 2,723.2 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||
Revisions due to price (b) |
(102.8) |
2.1 |
- |
(100.7) |
||||
Revisions other than price |
248.3 |
2.9 |
1.7 |
252.9 |
||||
Purchases in place |
42.3 |
- |
- |
42.3 |
||||
Extensions, discoveries and other additions (c) |
199.0 |
10.0 |
- |
209.0 |
||||
Total Proved Reserve Additions (d) |
386.8 |
15.0 |
1.7 |
403.5 |
||||
Sales in place |
(167.6) |
- |
- |
(167.6) |
||||
Net Proved Reserve Additions From All Sources (e) |
219.2 |
15.0 |
1.7 |
235.9 |
||||
Production (f) |
183.2 |
21.1 |
2.8 |
207.1 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
All-in Total, Net of Revisions (a / d) |
$ 6.50 |
$ 5.21 |
$ 21.82 |
$ 6.52 |
||||
All-in Total, Excluding Revisions Due to Price (a / (d - b)) |
$ 5.14 |
$ 6.05 |
$ 21.82 |
$ 5.22 |
||||
RESERVE REPLACEMENT |
||||||||
Drilling Only (c / f) |
109% |
47% |
0% |
101% |
||||
All-in Total, Net of Revisions & Dispositions (e / f) |
120% |
71% |
61% |
114% |
||||
All-in Total, Excluding Revisions Due to Price ((e - b ) / f) |
176% |
61% |
61% |
163% |
||||
Net Proved Reserve Additions From All Sources - Liquids (MMBbls) |
||||||||
Revisions |
95.7 |
- |
0.9 |
96.6 |
||||
Purchases in place |
27.1 |
- |
- |
27.1 |
||||
Extensions, discoveries and other additions (g) |
165.3 |
- |
- |
165.3 |
||||
Total Proved Reserve Additions |
288.1 |
- |
0.9 |
289.0 |
||||
Sales in place |
(42.2) |
- |
- |
(42.2) |
||||
Net Proved Reserve Additions From All Sources (h) |
245.9 |
- |
0.9 |
246.8 |
||||
Production (i) |
131.8 |
0.3 |
1.2 |
133.3 |
||||
RESERVE REPLACEMENT - LIQUIDS |
||||||||
Drilling Only (g / i) |
125% |
0% |
0% |
124% |
||||
All-in Total, Net of Revisions & Dispositions (h / i) |
187% |
0% |
75% |
185% |
||||
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of Drillbit Exploration and Development Expenditures (Non-GAAP) | ||||||||
As Used in the Calculation of Proved Developed Reserve Replacement Costs ($ / BOE) | ||||||||
To Total Costs Incurred in Exploration and Development Activities (GAAP) | ||||||||
(Unaudited; in millions, except ratio information) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Drillbit Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Proved Developed Reserve Replacement Costs per Boe. These statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. | ||||||||
For the Twelve Months Ended December 31, 2016 |
||||||||
Total |
||||||||
PROVED DEVELOPED RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$ 6,445.2 |
|||||||
Less: Asset Retirement Costs |
19.9 |
|||||||
Acquisition Costs of Unproved Properties |
(3,216.6) |
|||||||
Acquisition Cost of Proved Properties |
(749.0) |
|||||||
Drillbit Exploration & Development Expenditures (Non-GAAP) (j) |
$ 2,499.5 |
|||||||
Total Proved Reserves - Extensions, discoveries and other additions (MMBoe) |
209.0 |
|||||||
Add: Conversion of proved undeveloped reserves to proved developed |
149.2 |
|||||||
Less: Proved undeveloped extensions and discoveries |
(138.1) |
|||||||
Proved Developed Reserves - Extensions and discoveries (MMBoe) |
220.1 |
|||||||
Total Proved Reserves - Revisions (MMBoe) |
152.2 |
|||||||
Less: Proved Undeveloped Reserves - Revisions |
(64.4) |
|||||||
Proved Developed - Revisions due to price |
76.7 |
|||||||
Proved Developed Reserves - Revisions other than price (MMBoe) |
164.5 |
|||||||
Proved Developed Reserves - Extensions and discoveries plus revisions |
||||||||
other than price (MMBoe) (k) |
384.6 |
|||||||
Proved Developed Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe) (j / k) |
$ 6.50 |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial | |||||||||||
Commodity Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 20, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2016 |
|||||||||||
April 12, 2016 through April 30, 2016 (closed) |
90,000 |
$ 42.30 | |||||||||
May 1, 2016 through June 30, 2016 (closed) |
128,000 |
42.56 | |||||||||
2017 |
|||||||||||
January 2017 (closed) |
35,000 |
$ 50.04 | |||||||||
February 1, 2017 through June 30, 2017 |
35,000 |
50.04 | |||||||||
EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the average U.S. NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price. Presented below is a comprehensive summary of EOG's crude oil collar contracts through February 20, 2017, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Collar Contracts | |||||||||||
Weighted Average Price ($/Bbl) | |||||||||||
Volume (Bbld) |
Ceiling Price |
Floor Price | |||||||||
2016 |
|||||||||||
September 1, 2016 through December 31, 2016 (closed) |
70,000 |
$ 54.25 |
$ 45.00 | ||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2016 |
|||||||||||
March 1, 2016 through August 31, 2016 (closed) |
60,000 |
$ 2.49 | |||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
30,000 |
$ 3.10 | |||||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
35,000 |
$ 3.00 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2016 |
|||||||||||
September 2016 (closed) |
56,250 |
$ 3.46 |
- |
$ - | |||||||
October 1, 2016 through November 30, 2016 (closed) |
106,250 |
3.48 |
- |
- | |||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the Henry Hub Index Price in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 20, 2017, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. | |||||||||||
Natural Gas Collar Contracts | |||||||||||
Weighted Average Price ($/MMbtu) | |||||||||||
Volume (MMBtud) |
Ceiling Price |
Floor Price | |||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
80,000 |
$ 3.69 |
$ 3.20 | ||||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
2016 |
2015 |
2014 |
2013 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
282 |
$ |
237 |
$ |
201 |
|||||
Tax Benefit Imputed (based on 35%) |
(99) |
(83) |
(70) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
183 |
$ |
154 |
$ |
131 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(1,097) |
$ |
(4,525) |
$ |
2,915 |
|||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
204 |
(a) |
4,559 |
(b) |
(199) |
(c) |
|||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
(893) |
$ |
34 |
$ |
2,716 |
|||||
Total Stockholders' Equity - (d) |
$ |
13,982 |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 | |||
Average Total Stockholders' Equity * - (e) |
$ |
13,463 |
$ |
15,328 |
$ |
16,566 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,986 |
$ |
6,655 |
$ |
5,906 |
$ |
5,909 | |||
Less: Cash |
(1,600) |
(719) |
(2,087) |
(1,318) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,386 |
$ |
5,936 |
$ |
3,819 |
$ |
4,591 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
20,968 |
$ |
19,598 |
$ |
23,619 |
$ |
21,327 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
19,368 |
$ |
18,879 |
$ |
21,532 |
$ |
20,009 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
19,124 |
$ |
20,206 |
$ |
20,771 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-4.8% |
-21.6% |
14.7% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
-3.7% |
0.9% |
13.7% |
||||||||
Return on Equity (ROE) (Non-GAAP) |
|||||||||||
ROE (GAAP Net Income) - (b) / (e) |
-8.1% |
-29.5% |
17.6% |
||||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
-6.6% |
0.2% |
16.4% |
||||||||
* Average for the current and immediately preceding year |
Adjustments to Net Income (Loss) (GAAP) |
||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2016: |
||||||||
Year Ended December 31, 2016 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
77 |
$ |
(28) |
$ |
49 | ||
Add: Impairments of Certain Assets |
321 |
(113) |
208 | |||||
Less: Net Gains on Asset Dispositions |
(206) |
62 |
(144) | |||||
Add: Trinidad Tax Settlement |
- |
43 |
43 | |||||
Add: Voluntary Retirement Expense |
42 |
(15) |
27 | |||||
Add: Acquisition - State Apportionment Change |
- |
16 |
16 | |||||
Add: Acquisition Costs |
5 |
- |
5 | |||||
Total |
$ |
239 |
$ |
(35) |
$ |
204 | ||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
||||||||
Year Ended December 31, 2015 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 | ||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 | |||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) | |||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 | |||||
Add: Severance Costs |
9 |
(3) |
6 | |||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 | |||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 | ||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
||||||||
Year Ended December 31, 2014 | ||||||||
Before |
Income Tax |
After | ||||||
Tax |
Impact |
Tax | ||||||
Adjustments: |
||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) | ||
Add: Impairments of Certain Assets |
824 |
(271) |
553 | |||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) | |||||
Add: Tax Expense Related to the Repatriation of Accumulated |
- |
250 |
250 | |||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
EOG RESOURCES, INC. | |||||||||||
First Quarter and Full Year 2017 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) First Quarter and Full Year 2017 Forecast |
|||||||||||
The forecast items for the first quarter and full year 2017 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
1Q 2017 |
Full Year 2017 | ||||||||||
Daily Sales Volumes |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
300.0 |
- |
310.0 |
320.0 |
- |
335.0 | |||||
Trinidad |
0.3 |
- |
0.5 |
0.3 |
- |
0.5 | |||||
Other International |
2.0 |
- |
4.0 |
4.0 |
- |
7.0 | |||||
Total |
302.3 |
- |
314.5 |
324.3 |
- |
342.5 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
72.0 |
- |
78.0 |
72.0 |
- |
82.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
670 |
- |
710 |
725 |
- |
760 | |||||
Trinidad |
300 |
- |
330 |
275 |
- |
315 | |||||
Other International |
18 |
- |
24 |
25 |
- |
30 | |||||
Total |
988 |
- |
1,064 |
1,025 |
- |
1,105 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
483.7 |
- |
506.3 |
512.8 |
- |
543.7 | |||||
Trinidad |
50.3 |
- |
55.5 |
46.1 |
- |
53.0 | |||||
Other International |
5.0 |
- |
8.0 |
8.2 |
- |
12.0 | |||||
Total |
539.0 |
- |
569.8 |
567.1 |
- |
608.7 | |||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.60 |
- |
$ |
5.00 |
$ |
4.30 |
- |
$ |
5.00 | |
Transportation Costs |
$ |
3.40 |
- |
$ |
4.00 |
$ |
3.10 |
- |
$ |
3.90 | |
Depreciation, Depletion and Amortization |
$ |
15.80 |
- |
$ |
16.10 |
$ |
15.50 |
- |
$ |
16.00 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
95 |
- |
$ |
125 |
$ |
415 |
- |
$ |
465 | |
General and Administrative |
$ |
90 |
- |
$ |
100 |
$ |
365 |
- |
$ |
395 | |
Gathering and Processing |
$ |
28 |
- |
$ |
30 |
$ |
105 |
- |
$ |
125 | |
Capitalized Interest |
$ |
7 |
- |
$ |
8 |
$ |
25 |
- |
$ |
30 | |
Net Interest |
$ |
69 |
- |
$ |
71 |
$ |
273 |
- |
$ |
283 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.7% |
- |
7.1% |
6.5% |
- |
6.9% | |||||
Income Taxes |
|||||||||||
Effective Rate |
31% |
- |
36% |
31% |
- |
36% | |||||
Current Taxes ($MM) |
$ |
30 |
- |
$ |
45 |
$ |
130 |
- |
$ |
170 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
3,000 |
- |
$ |
3,350 | ||||||
Exploration and Development Facilities |
$ |
475 |
- |
$ |
510 | ||||||
Gathering, Processing and Other |
$ |
225 |
- |
$ |
240 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(2.00) |
- |
$ |
(1.00) |
$ |
(2.50) |
- |
$ |
(0.50) | |
Trinidad - above (below) WTI |
$ |
(9.75) |
- |
$ |
(7.75) |
$ |
(9.50) |
- |
$ |
(7.50) | |
Other International - above (below) WTI |
$ |
(10.00) |
- |
$ |
(8.00) |
$ |
(3.00) |
- |
$ |
0.00 | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
31% |
- |
35% |
31% |
- |
35% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.10) |
- |
$ |
(0.70) |
$ |
(1.15) |
- |
$ |
(0.65) | |
Realizations |
|||||||||||
Trinidad |
$ |
2.00 |
- |
$ |
2.40 |
$ |
1.90 |
- |
$ |
2.50 | |
Other International |
$ |
3.75 |
- |
$ |
4.25 |
$ |
3.50 |
- |
$ |
4.50 | |
Definitions |
||||||||||||
$/Bbl |
U.S. Dollars per barrel |
|||||||||||
$/Boe |
U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf |
U.S. Dollars per thousand cubic feet |
|||||||||||
$MM |
U.S. Dollars in millions |
|||||||||||
MBbld |
Thousand barrels per day |
|||||||||||
MBoed |
Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd |
Million cubic feet per day |
|||||||||||
NYMEX |
New York Mercantile Exchange |
|||||||||||
WTI |
West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 22, 2017 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today announced the appointment of Robert P. Daniels to its Board of Directors, effective March 1, 2017. Daniels served as an Executive Vice President of Anadarko Petroleum Corporation, a publicly traded oil and gas exploration and production company (Anadarko), from May 2013 until his retirement in December 2016, and as a Senior Vice President of Anadarko from May 2004 to May 2013. Mr. Daniels also serves as a director of MicroSeismic, Inc. and is active in industry and civic associations.
"We are very pleased to welcome Bob to the EOG Board of Directors," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "He brings a record of accomplishment across many aspects of the global energy industry during his 32-year career at Anadarko, and his experience and sound judgment will be a valuable asset to our Board and company."
Leighton Steward Set to Retire as a Director
EOG also announced that H. Leighton Steward has informed the Board of his decision to retire from the Board at the end of his current term and not stand for re-election as a director at its 2017 Annual Meeting of Stockholders. Mr. Steward was first elected a Director of EOG in 2004, following a distinguished career in the oil and gas exploration and production industry. Beginning in 1962, Mr. Steward was employed in various management capacities at Shell Oil Company, including Chief of Exploration Operations, Worldwide. In 1982, he joined Louisiana Land & Exploration Company (LL&E) and served as Chairman, President and Chief Executive Officer from 1989 until 1997 when Burlington Resources acquired LL&E. Mr. Steward then became Vice Chairman of Burlington Resources and served in this position until his retirement in 2000.
"I would like to thank Leighton for his 13 years of dedicated service to EOG," Thomas said. "Leighton has played an integral part in helping guide EOG through its evolution from a conventional natural gas company to its present position as the technical leader in unconventional oil and gas and the largest producer of oil in the lower-48 United States." Thomas concluded, "I have personally benefited from his wise counsel and guidance. On behalf of everyone at EOG, I offer Leighton and his wife Lynda our best wishes as he continues his retirement."
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
W. John Wagner | |
(713) 571-4404 | |
Media and Investors | |
Kimberly M. Ehmer | |
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, Jan. 17, 2017 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss fourth quarter and full year 2016 results on Tuesday, February 28, 2017, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page for one year.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
Investors/Media | |
Kimberly M. Ehmer | |
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, Dec. 14, 2016 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable January 31, 2017, to stockholders of record as of January 17, 2017. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors | |
Cedric W. Burgher | ||
(713) 571-4658 | ||
David J. Streit | ||
(713) 571-4902 | ||
Media and Investors | ||
Kimberly M. Ehmer | ||
(713) 571-4676 |
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 3, 2016 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) today reported a third quarter 2016 net loss of $190.0 million, or $0.35 per share. This compares to a third quarter 2015 net loss of $4.1 billion, or $7.47 per share.
Adjusted non-GAAP net loss for the third quarter 2016 was $220.8 million, or $0.40 per share, compared to adjusted non-GAAP net income of $13.5 million, or $0.02 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring and certain other items. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Lower crude oil and natural gas prices more than offset significant well productivity improvements and lease and well cost reductions, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the third quarter 2016 compared to the third quarter 2015. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Operational Highlights
U.S. crude oil volumes of 275,700 barrels of oil per day (Bopd) in the third quarter 2016 exceeded the midpoint of the company's guidance by 3 percent. Compared to the same prior year period, lease and well expenses decreased 18 percent on a per-unit basis.
In the third quarter 2016, total crude oil production increased 1 percent while exploration and development expenditures (excluding property acquisitions) decreased 32 percent, compared to the same period last year. Natural gas liquids production increased 5 percent, while total natural gas production for the third quarter 2016 decreased 10 percent versus the same prior year period.
"Even in a low commodity price environment, 2016 is proving to be a breakout year for EOG with record well productivity, sustainable cost reductions and organic growth in all our core plays, coupled with a historic transaction that adds substantial high-return growth potential," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "EOG's third quarter accomplishments reflect the hard work and ingenuity of our great employees and our unique culture."
2020 Crude Oil Production Outlook and 2016 Capital Plan Update
As a result of continued improvements in capital efficiency which have been augmented by the Yates transaction, EOG is increasing its crude oil organic production growth outlook through 2020. The long term outlook includes growth from key areas such as the Eagle Ford, Delaware Basin, Rockies and the Bakken. In addition to the growth illustrated in the outlook, the company continues to evaluate high-quality emerging plays through its ongoing exploration efforts.
Assuming balanced spending including dividend payments and a flat $50 West Texas Intermediate crude oil (WTI) price, EOG now expects 15 percent compound annual crude oil production growth through 2020. If the assumed WTI price is increased to $60, EOG would expect 25 percent compound annual crude oil production growth through 2020. This reflects an increase from the company's prior outlook of 10 to 20 percent growth at $50 to $60 WTI.
"EOG's future has never been brighter, and we are already in a position to make a material improvement to the long-term outlook we provided last quarter," Thomas said. "The company-wide premium drilling strategy and the recently closed Yates transaction are significantly boosting capital efficiency and enabling us to extend our lead in unconventional resource productivity."
For 2016, EOG is increasing its capital spending guidance range by $200 million to $2.6 to $2.8 billion, excluding acquisitions. The spending increase will be directed toward well completions, which are now targeted to increase from the initial plan of 270 and the prior revised forecast of 350 to 450 net wells in 2016. Drilling productivity continues to improve, and the company now expects to drill 290 net wells, 40 more than its prior forecast and 90 more than its original 2016 plans.
Delaware Basin
EOG increased its Delaware Basin net resource potential by 155 percent to 6.0 billion barrels of oil equivalent (BnBoe) in the third quarter 2016 (inclusive of the recent Yates transaction). Delaware Basin net well locations increased by 27 percent to 6,330. The average planned lateral length for these locations increased from 4,500 feet to over 7,000 feet.
"With the Yates transaction, EOG's Delaware Basin position now exceeds 400,000 net acres in the core window of this world-class play," Thomas said. "Our technical and operational advances applied to the combined assets have produced a major increase in EOG's Delaware Basin potential. As we continue to make advances in cost management and technology, we believe our resource potential over time will continue to increase in both size and quality."
In the Delaware Basin Wolfcamp, EOG increased its net resource potential from 1.3 BnBoe to 2.9 BnBoe and net well locations from 2,130 to 2,660. For the Delaware Basin Wolfcamp oil play, EOG's average gross reserves per well increased to 1,330 thousand barrels of crude oil equivalent (MBoe) from 750 MBoe, while average gross reserves per well increased to 1,550 MBoe from 900 MBoe in the combo portion of the play.
For the Delaware Basin Second Bone Spring, EOG increased its net resource potential from 0.5 BnBoe to 1.4 BnBoe and net well locations from 1,250 to 1,870. Average gross reserves per well increased to 950 MBoe from 500 MBoe.
EOG also increased its Delaware Basin Leonard net resource potential from 0.6 BnBoe to 1.7 BnBoe and net well locations from 1,600 to 1,800. Average gross reserves per well increased to 1,175 MBoe from 500 MBoe.
In the third quarter 2016, EOG completed 22 wells in the Delaware Basin Wolfcamp with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 2,350 barrels of oil equivalent per day (Boed), or 1,675 Bopd, 275 barrels per day (Bpd) of natural gas liquids (NGLs) and 2.4 million cubic feet per day (MMcfd) of natural gas. In the Delaware Basin Second Bone Spring, EOG completed four wells in the third quarter with an average treated lateral length of 4,600 feet per well and an average 30-day initial production rate per well of 1,240 Boed, or 940 Bopd, 120 Bpd of NGLs and 1.1 MMcfd of natural gas.
South Texas Eagle Ford
EOG's oil-rich South Texas Eagle Ford acreage continued to deliver exceptional results in the third quarter 2016 and was once again the largest contributor to EOG's U.S. crude oil production.
In the third quarter, EOG completed 47 wells in the Eagle Ford with an average treated lateral length of 5,700 feet per well and an average 30-day initial production rate per well of 1,825 Boed, or 1,425 Bopd, 190 Bpd of NGLs and 1.3 MMcfd of natural gas.
Rockies and the Bakken
In the third quarter, EOG completed nine wells in the Powder River Basin with an average 30-day initial production rate per well of 1,560 Boed, or 840 Bopd, 245 Bpd of NGLs and 2.8 MMcfd of natural gas.
In the DJ Basin Codell in Wyoming, EOG completed five wells in the third quarter with an average 30-day initial production rate per well of 720 Boed, or 610 Bopd, 70 Bpd of NGLs and 0.3 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed 13 wells in the third quarter with an average 30-day initial production rate per well of 850 Boed, or 763 Bopd, 45 Bpd of NGLs and 0.3 MMcfd of natural gas.
Hedging Activity
For the period November 1 through December 31, 2016, EOG has crude oil financial price collar contracts in place for 70,000 Bopd at an average ceiling price of $54.25 per barrel and an average floor price of $45.00 per barrel.
For the period March 1 through November 30, 2017, EOG has natural gas financial price swap contracts in place for 30,000 million British thermal units (MMBtu) per day at a weighted average price of $3.10 per MMBtu.
For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 120,000 MMBtu per day at an average strike price of $3.38 per MMBtu.
For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 96,000 MMBtu per day at an average strike price of $2.94 per MMBtu.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At September 30, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 37 percent. Taking into account cash on the balance sheet of $1.1 billion at the end of the third quarter, EOG's net debt was $5.9 billion with a net debt-to-total capitalization ratio of 33 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales this year to date total $625 million. This includes proceeds from a transaction that has already closed in the fourth quarter 2016. Associated production of the divested assets was 80 MMcfd of natural gas, 3,400 Bopd and 4,290 Bpd of NGLs.
Conference Call November 4, 2016
EOG's third quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, November 4, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Media and Investors
Kimberly M. Ehmer
(713) 571-4676
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
$ |
2,118.5 |
$ |
2,172.4 |
$ |
5,248.6 |
$ |
6,960.7 | |||
Net Loss |
$ |
(190.0) |
$ |
(4,075.7) |
$ |
(954.3) |
$ |
(4,240.2) | |||
Net Loss Per Share |
|||||||||||
Basic |
$ |
(0.35) |
$ |
(7.47) |
$ |
(1.74) |
$ |
(7.77) | |||
Diluted |
$ |
(0.35) |
$ |
(7.47) |
$ |
(1.74) |
$ |
(7.77) | |||
Average Number of Common Shares |
|||||||||||
Basic |
547.8 |
545.9 |
547.3 |
545.5 | |||||||
Diluted |
547.8 |
545.9 |
547.3 |
545.5 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
|||||||||||
Crude Oil and Condensate |
$ |
1,137,717 |
$ |
1,181,092 |
$ |
2,951,118 |
$ |
3,894,092 | |||
Natural Gas Liquids |
112,439 |
95,217 |
299,401 |
311,137 | |||||||
Natural Gas |
205,293 |
281,837 |
526,779 |
843,657 | |||||||
Gains (Losses) on Mark-to-Market Commodity |
5,117 |
29,239 |
(33,821) |
56,954 | |||||||
Gathering, Processing and Marketing |
532,456 |
572,217 |
1,351,665 |
1,820,843 | |||||||
Gains (Losses) on Asset Dispositions, Net |
108,204 |
(1,185) |
101,801 |
(5,142) | |||||||
Other, Net |
17,278 |
14,011 |
51,650 |
39,126 | |||||||
Total |
2,118,504 |
2,172,428 |
5,248,593 |
6,960,667 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
226,348 |
283,221 |
685,606 |
934,366 | |||||||
Transportation Costs |
200,862 |
203,594 |
570,787 |
641,739 | |||||||
Gathering and Processing Costs |
32,635 |
35,497 |
90,385 |
106,503 | |||||||
Exploration Costs |
25,455 |
31,344 |
85,843 |
114,548 | |||||||
Dry Hole Costs |
10,390 |
198 |
10,464 |
14,317 | |||||||
Impairments |
177,990 |
6,307,420 |
322,321 |
6,445,375 | |||||||
Marketing Costs |
552,487 |
615,303 |
1,373,387 |
1,924,134 | |||||||
Depreciation, Depletion and Amortization |
899,511 |
722,172 |
2,690,893 |
2,544,187 | |||||||
General and Administrative |
94,397 |
90,959 |
292,633 |
257,580 | |||||||
Taxes Other Than Income |
91,909 |
105,677 |
246,068 |
334,244 | |||||||
Total |
2,311,984 |
8,395,385 |
6,368,387 |
13,316,993 | |||||||
Operating Loss |
(193,480) |
(6,222,957) |
(1,119,794) |
(6,356,326) | |||||||
Other (Expense) Income, Net |
(7,912) |
8,607 |
(33,345) |
7,996 | |||||||
Loss Before Interest Expense and Income Taxes |
(201,392) |
(6,214,350) |
(1,153,139) |
(6,348,330) | |||||||
Interest Expense, Net |
70,858 |
60,571 |
210,356 |
174,400 | |||||||
Loss Before Income Taxes |
(272,250) |
(6,274,921) |
(1,363,495) |
(6,522,730) | |||||||
Income Tax Benefit |
(82,250) |
(2,199,182) |
(409,161) |
(2,282,511) | |||||||
Net Loss |
$ |
(190,000) |
$ |
(4,075,739) |
$ |
(954,334) |
$ |
(4,240,219) | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.5025 |
$ |
0.5025 |
EOG RESOURCES, INC. |
||||||||||||
Operating Highlights |
||||||||||||
(Unaudited) |
||||||||||||
Three Months Ended |
Nine Months Ended |
|||||||||||
September 30, |
September 30, |
|||||||||||
2016 |
2015 |
2016 |
2015 |
|||||||||
Wellhead Volumes and Prices |
||||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
||||||||||||
United States |
275.7 |
278.3 |
269.0 |
284.4 |
||||||||
Trinidad |
0.7 |
1.0 |
0.8 |
0.9 |
||||||||
Other International (B) |
6.2 |
0.2 |
3.0 |
0.2 |
||||||||
Total |
282.6 |
279.5 |
272.8 |
285.5 |
||||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
||||||||||||
United States |
$ |
43.66 |
$ |
45.93 |
$ |
39.53 |
$ |
49.94 |
||||
Trinidad |
34.81 |
38.56 |
31.36 |
41.98 |
||||||||
Other International (B) |
43.53 |
61.80 |
35.30 |
58.44 |
||||||||
Composite |
43.63 |
45.91 |
39.46 |
49.92 |
||||||||
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||
United States |
81.9 |
77.7 |
81.9 |
76.2 |
||||||||
Other International (B) |
- |
0.1 |
- |
0.1 |
||||||||
Total |
81.9 |
77.8 |
81.9 |
76.3 |
||||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
||||||||||||
United States |
$ |
14.92 |
$ |
13.25 |
$ |
13.34 |
$ |
14.94 |
||||
Other International (B) |
- |
8.05 |
- |
6.05 |
||||||||
Composite |
14.92 |
13.24 |
13.34 |
14.93 |
||||||||
Natural Gas Volumes (MMcfd) (A) |
||||||||||||
United States |
791 |
889 |
813 |
895 |
||||||||
Trinidad |
329 |
355 |
346 |
342 |
||||||||
Other International (B) |
24 |
30 |
25 |
31 |
||||||||
Total |
1,144 |
1,274 |
1,184 |
1,268 |
||||||||
Average Natural Gas Prices ($/Mcf) (C) |
||||||||||||
United States |
$ |
1.94 |
$ |
2.04 |
$ |
1.46 |
$ |
2.14 |
||||
Trinidad |
1.86 |
2.90 |
1.88 |
3.01 |
||||||||
Other International (B) |
3.74 |
7.18 |
(E) |
3.57 |
4.63 |
(E) | ||||||
Composite |
1.95 |
2.40 |
1.62 |
2.44 |
||||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
||||||||||||
United States |
489.4 |
504.2 |
486.4 |
509.8 |
||||||||
Trinidad |
55.6 |
60.2 |
58.5 |
57.9 |
||||||||
Other International (B) |
10.2 |
5.2 |
7.2 |
5.4 |
||||||||
Total |
555.2 |
569.6 |
552.1 |
573.1 |
||||||||
Total MMBoe (D) |
51.1 |
52.4 |
151.3 |
156.5 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China and Canada operations. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. | |||||||||||
(E) Includes revenue adjustment of $3.62 per Mcf and $1.19 per Mcf for the quarter and year-to-date, respectively, related to a price adjustment for natural gas sales made in China from June 2012 to March 2015. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
September 30, |
December 31, | ||||
2016 |
2015 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
1,048,727 |
$ |
718,506 | |
Accounts Receivable, Net |
920,189 |
930,610 | |||
Inventories |
429,667 |
598,935 | |||
Assets from Price Risk Management Activities |
2,185 |
- | |||
Income Taxes Receivable |
178 |
40,704 | |||
Deferred Income Taxes |
137,098 |
147,812 | |||
Other |
199,720 |
155,677 | |||
Total |
2,737,764 |
2,592,244 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
50,465,979 |
50,613,241 | |||
Other Property, Plant and Equipment |
4,013,602 |
3,986,610 | |||
Total Property, Plant and Equipment |
54,479,581 |
54,599,851 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(31,835,196) |
(30,389,130) | |||
Total Property, Plant and Equipment, Net |
22,644,385 |
24,210,721 | |||
Other Assets |
172,772 |
167,505 | |||
Total Assets |
$ |
25,554,921 |
$ |
26,970,470 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,296,240 |
$ |
1,471,953 | |
Accrued Taxes Payable |
143,257 |
93,618 | |||
Dividends Payable |
91,842 |
91,546 | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
195,045 |
155,591 | |||
Total |
1,732,963 |
1,819,287 | |||
Long-Term Debt |
6,979,538 |
6,648,911 | |||
Other Liabilities |
975,763 |
971,335 | |||
Deferred Income Taxes |
4,068,345 |
4,587,902 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
|||||
551,425,785 Shares Issued at September 30, 2016 and 550,150,823 |
|||||
Shares Issued at December 31, 2015 |
205,514 |
205,502 | |||
Additional Paid in Capital |
2,992,887 |
2,923,461 | |||
Accumulated Other Comprehensive Loss |
(25,100) |
(33,338) | |||
Retained Earnings |
8,641,704 |
9,870,816 | |||
Common Stock Held in Treasury, 197,181 Shares at September 30, 2016 |
|||||
and 292,179 Shares at December 31, 2015 |
(16,693) |
(23,406) | |||
Total Stockholders' Equity |
11,798,312 |
12,943,035 | |||
Total Liabilities and Stockholders' Equity |
$ |
25,554,921 |
$ |
26,970,470 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Nine Months Ended | |||||
September 30, | |||||
2016 |
2015 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Loss to Net Cash Provided by Operating Activities: |
|||||
Net Loss |
$ |
(954,334) |
$ |
(4,240,219) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
2,690,893 |
2,544,187 | |||
Impairments |
322,321 |
6,445,375 | |||
Stock-Based Compensation Expenses |
97,072 |
101,926 | |||
Deferred Income Taxes |
(492,489) |
(2,377,030) | |||
(Gains) Losses on Asset Dispositions, Net |
(101,801) |
5,142 | |||
Other, Net |
42,149 |
3,735 | |||
Dry Hole Costs |
10,464 |
14,317 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total Losses (Gains) |
33,821 |
(56,954) | |||
Net Cash (Payments for) Received from Settlements of Commodity Derivative Contracts |
(22,219) |
661,021 | |||
Excess Tax Benefits from Stock-Based Compensation |
(22,071) |
(24,219) | |||
Other, Net |
7,513 |
8,904 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(11,860) |
448,311 | |||
Inventories |
137,563 |
27,007 | |||
Accounts Payable |
(201,213) |
(1,310,211) | |||
Accrued Taxes Payable |
113,996 |
77,575 | |||
Other Assets |
(12,526) |
146,965 | |||
Other Liabilities |
36,799 |
(15,683) | |||
Changes in Components of Working Capital Associated with Investing and Financing |
(119,760) |
519,203 | |||
Net Cash Provided by Operating Activities |
1,554,318 |
2,979,352 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(1,781,547) |
(3,918,065) | |||
Additions to Other Property, Plant and Equipment |
(60,343) |
(252,295) | |||
Proceeds from Sales of Assets |
457,665 |
144,285 | |||
Changes in Components of Working Capital Associated with Investing Activities |
120,614 |
(519,323) | |||
Net Cash Used in Investing Activities |
(1,263,611) |
(4,545,398) | |||
Financing Cash Flows |
|||||
Net Commercial Paper (Repayments) Borrowings |
(259,718) |
29,700 | |||
Long-Term Debt Borrowings |
991,097 |
990,225 | |||
Long-Term Debt Repayments |
(400,000) |
(500,000) | |||
Dividends Paid |
(276,726) |
(274,577) | |||
Excess Tax Benefits from Stock-Based Compensation |
22,071 |
24,219 | |||
Treasury Stock Purchased |
(55,641) |
(43,419) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
14,283 |
14,967 | |||
Debt Issuance Costs |
(1,602) |
(5,933) | |||
Repayment of Capital Lease Obligation |
(4,746) |
(4,599) | |||
Other, Net |
(854) |
120 | |||
Net Cash Provided by Financing Activities |
28,164 |
230,703 | |||
Effect of Exchange Rate Changes on Cash |
11,350 |
(9,181) | |||
Increase (Decrease) in Cash and Cash Equivalents |
330,221 |
(1,344,524) | |||
Cash and Cash Equivalents at Beginning of Period |
718,506 |
2,087,213 | |||
Cash and Cash Equivalents at End of Period |
$ |
1,048,727 |
$ |
742,689 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
to Net Loss (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net (gains) losses on asset dispositions in 2016 and 2015, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016, to add back certain voluntary retirement expense in 2016, to add back impairment charges related to certain of EOG's assets in 2016 and 2015, and to add back acquisition costs related to the Yates transaction in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
September 30, 2016 |
September 30, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Loss (GAAP) |
$ (272,250) |
$ 82,250 |
$ (190,000) |
$ (0.35) |
$ (6,274,921) |
$ 2,199,182 |
$ (4,075,739) |
$ (7.47) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
(5,117) |
1,824 |
(3,293) |
(0.01) |
(29,239) |
10,424 |
(18,815) |
(0.03) | |||||||
Net Cash Received from (Payments for) |
|||||||||||||||
Settlements of Commodity Derivative |
|||||||||||||||
Contracts |
(25,071) |
8,938 |
(16,133) |
(0.03) |
99,879 |
(35,607) |
64,272 |
0.12 | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
(108,204) |
28,802 |
(79,402) |
(0.13) |
1,185 |
(4,614) |
(3,429) |
(0.01) | |||||||
Add: Impairments of Certain Assets |
102,778 |
(36,640) |
66,138 |
0.12 |
6,213,107 |
(2,165,884) |
4,047,223 |
7.41 | |||||||
Add: Acquisition Costs |
2,927 |
(1,043) |
1,884 |
- |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
(32,687) |
1,881 |
(30,806) |
(0.05) |
6,284,932 |
(2,195,681) |
4,089,251 |
7.49 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ (304,937) |
$ 84,131 |
$ (220,806) |
$ (0.40) |
$ 10,011 |
$ 3,501 |
$ 13,512 |
$ 0.02 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
547,838 |
545,920 | |||||||||||||
Diluted |
547,838 |
545,920 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
547,838 |
545,920 | |||||||||||||
Diluted |
547,838 |
549,434 | |||||||||||||
Nine Months Ended |
Nine Months Ended | ||||||||||||||
September 30, 2016 |
September 30, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Loss (GAAP) |
$ (1,363,495) |
$ 409,161 |
$ (954,334) |
$ (1.74) |
$ (6,522,730) |
$ 2,282,511 |
$ (4,240,219) |
$ (7.77) | |||||||
Adjustments: |
|||||||||||||||
(Gains) Losses on Mark-to-Market Commodity |
33,821 |
(12,057) |
21,764 |
0.04 |
(56,954) |
20,304 |
(36,650) |
(0.07) | |||||||
Net Cash Received from (Payments for) |
(22,219) |
7,921 |
(14,298) |
(0.03) |
661,021 |
(235,654) |
425,367 |
0.79 | |||||||
Add: Net (Gains) Losses on Asset Dispositions |
(101,801) |
24,635 |
(77,166) |
(0.14) |
5,142 |
(3,448) |
1,694 |
- | |||||||
Less: Texas Margin Tax Rate Reduction |
- |
- |
- |
- |
- |
(19,500) |
(19,500) |
(0.04) | |||||||
Add: Severance Costs |
- |
- |
- |
- |
8,505 |
(3,032) |
5,473 |
0.01 | |||||||
Add: Trinidad Tax Settlement |
- |
43,000 |
43,000 |
0.08 |
- |
- |
- |
- | |||||||
Add: Voluntary Retirement Expense |
42,054 |
(14,992) |
27,062 |
0.05 |
- |
- |
- |
- | |||||||
Add: Impairments of Certain Assets |
102,778 |
(36,640) |
66,138 |
0.12 |
6,213,107 |
(2,165,884) |
4,047,223 |
7.41 | |||||||
Add: Acquisition Costs |
2,927 |
(1,043) |
1,884 |
- |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
57,560 |
10,824 |
68,384 |
0.12 |
6,830,821 |
(2,407,214) |
4,423,607 |
8.10 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ (1,305,935) |
$ 419,985 |
$ (885,950) |
$ (1.62) |
$ 308,091 |
$ (124,703) |
$ 183,388 |
$ 0.33 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
547,295 |
545,466 | |||||||||||||
Diluted |
547,295 |
545,466 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
547,295 |
545,466 | |||||||||||||
Diluted |
547,295 |
549,414 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
to Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and nine-month periods ended September 30, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Nine Months Ended | |||||||||||
September 30, |
September 30, | |||||||||||
2016 |
2015 |
2016 |
2015 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
759,581 |
$ |
1,131,432 |
$ |
1,554,318 |
$ |
2,979,352 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
21,384 |
25,286 |
70,268 |
95,253 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
10,260 |
7,826 |
22,071 |
24,219 | ||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||
and Liabilities |
||||||||||||
Accounts Receivable |
(10,712) |
(150,128) |
11,860 |
(448,311) | ||||||||
Inventories |
(41,750) |
10,602 |
(137,563) |
(27,007) | ||||||||
Accounts Payable |
(2,145) |
310,567 |
201,213 |
1,310,211 | ||||||||
Accrued Taxes Payable |
(20,676) |
(13,451) |
(113,996) |
(77,575) | ||||||||
Other Assets |
(21,063) |
(70,851) |
12,526 |
(146,965) | ||||||||
Other Liabilities |
(35,234) |
(33,165) |
(36,799) |
15,683 | ||||||||
Changes in Components of Working Capital Associated with |
||||||||||||
Investing and Financing Activities |
65,307 |
(349,401) |
119,760 |
(519,203) | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
724,952 |
$ |
868,717 |
$ |
1,703,658 |
$ |
3,205,657 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-17% |
-47% |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Loss (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and nine-month periods ended September 30, 2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes (Income Tax Benefit), Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended |
Nine Months Ended | ||||||||||
September 30, |
September 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Loss (GAAP) |
$ |
(190,000) |
$ |
(4,075,739) |
$ |
(954,334) |
$ |
(4,240,219) | |||
Adjustments: |
|||||||||||
Interest Expense, Net |
70,858 |
60,571 |
210,356 |
174,400 | |||||||
Income Tax Benefit |
(82,250) |
(2,199,182) |
(409,161) |
(2,282,511) | |||||||
Depreciation, Depletion and Amortization |
899,511 |
722,172 |
2,690,893 |
2,544,187 | |||||||
Exploration Costs |
25,455 |
31,344 |
85,843 |
114,548 | |||||||
Dry Hole Costs |
10,390 |
198 |
10,464 |
14,317 | |||||||
Impairments |
177,990 |
6,307,420 |
322,321 |
6,445,375 | |||||||
EBITDAX (Non-GAAP) |
911,954 |
846,784 |
1,956,382 |
2,770,097 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
(5,117) |
(29,239) |
33,821 |
(56,954) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity |
|||||||||||
Derivative Contracts |
(25,071) |
99,879 |
(22,219) |
661,021 | |||||||
(Gains) Losses on Asset Dispositions, Net |
(108,204) |
1,185 |
(101,801) |
5,142 | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
773,562 |
$ |
918,609 |
$ |
1,866,183 |
$ |
3,379,306 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-16% |
-45% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
September 30, |
December 31, | ||||
2016 |
2015 | ||||
Total Stockholders' Equity - (a) |
$ |
11,798 |
$ |
12,943 | |
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,655 | |||
Less: Cash |
(1,049) |
(719) | |||
Net Debt (Non-GAAP) - (c) |
5,937 |
5,936 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
18,784 |
$ |
19,598 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
17,735 |
$ |
18,879 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
37% |
34% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
33% |
31% |
EOG RESOURCES, INC. | |||||||||||
Crude Oil and Natural Gas Financial | |||||||||||
Commodity Derivative Contracts | |||||||||||
EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. Presented below is a comprehensive summary of EOG's crude oil price swap contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(Bbld) |
($/Bbl) | ||||||||||
2016 |
|||||||||||
April 12, 2016 through April 30, 2016 (closed) |
90,000 |
$ 42.30 | |||||||||
May 1, 2016 through June 30, 2016 (closed) |
128,000 |
42.56 | |||||||||
EOG has entered into crude oil collar contracts, which establish ceiling and floor prices for the sale of notional volumes of crude oil as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the average NYMEX West Texas Intermediate crude oil price for the contract month (Index Price) in the event the Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Index Price in the event the Index Price is below the floor price. Presented below is a comprehensive summary of EOG's crude oil collar contracts through November 3, 2016, with notional volumes expressed in Bbld and prices expressed in $/Bbl. | |||||||||||
Crude Oil Collar Contracts | |||||||||||
Weighted Average Price ($/Bbl) | |||||||||||
Volume (Bbld) |
Ceiling Price |
Floor Price | |||||||||
2016 |
|||||||||||
September 1, 2016 through October 31, 2016 (closed) |
70,000 |
$ 54.25 |
$ 45.00 | ||||||||
November 1, 2016 through December 31, 2016 |
70,000 |
54.25 |
45.00 | ||||||||
Presented below is a comprehensive summary of EOG's natural gas price swap contracts through November 3, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. | |||||||||||
Natural Gas Price Swap Contracts | |||||||||||
Weighted | |||||||||||
Volume |
Average Price | ||||||||||
(MMBtud) |
($/MMBtu) | ||||||||||
2016 |
|||||||||||
March 1, 2016 through August 31, 2016 (closed) |
60,000 |
$ 2.49 | |||||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
30,000 |
$ 3.10 | |||||||||
EOG has sold call options which establish a ceiling price for the sale of notional volumes of natural gas as specified in the call option contracts. The call options require that EOG pay the difference between the call option strike price and either the average or last business day NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the call option strike price. In addition, EOG has purchased put options which establish a floor price for the sale of notional volumes of natural gas as specified in the put option contracts. The put options grant EOG the right to receive the difference between the put option strike price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the put option strike price. Presented below is a comprehensive summary of EOG's natural gas call and put option contracts through November 3, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMbtu. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2016 |
|||||||||||
September 2016 (closed) |
56,250 |
$ 3.46 |
- |
$ - | |||||||
October 1, 2016 through November 30, 2016 (closed) |
106,250 |
3.48 |
- |
- | |||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
213,750 |
$ 3.44 |
171,000 |
$ 2.92 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
120,000 |
$ 3.38 |
96,000 |
$ 2.94 | |||||||
Definitions |
|||||||||||
Bbld |
Barrels per day |
||||||||||
$/Bbl |
Dollars per barrel |
||||||||||
MMBtud |
Million British thermal units per day |
||||||||||
$/MMBtu |
Dollars per million British thermal units |
||||||||||
NYMEX |
New York Mercantile Exchange |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
2015 |
2014 |
2013 |
2012 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
237 |
$ |
201 |
$ |
235 |
|||||
Tax Benefit Imputed (based on 35%) |
(83) |
(70) |
(82) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
154 |
$ |
131 |
$ |
153 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
|||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
4,559 |
(a) |
(199) |
(b) |
49 |
(c) |
|||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
34 |
$ |
2,716 |
$ |
2,246 |
|||||
Total Stockholders' Equity - (d) |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
$ |
13,285 | |||
Average Total Stockholders' Equity * - (e) |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,660 |
$ |
5,910 |
$ |
5,913 |
$ |
6,312 | |||
Less: Cash |
(719) |
(2,087) |
(1,318) |
(876) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,941 |
$ |
3,823 |
$ |
4,595 |
$ |
5,436 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,603 |
$ |
23,623 |
$ |
21,331 |
$ |
19,597 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,884 |
$ |
21,536 |
$ |
20,013 |
$ |
18,721 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,210 |
$ |
20,775 |
$ |
19,367 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-21.6% |
14.7% |
12.1% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
0.9% |
13.7% |
12.4% |
||||||||
Return on Equity (ROE) (Non-GAAP) |
|||||||||||
ROE (GAAP Net Income) - (b) / (e) |
-29.5% |
17.6% |
15.3% |
||||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
0.2% |
16.4% |
15.6% |
||||||||
* Average for the current and immediately preceding year |
|||||||||||
Adjustments to Net Income (Loss) (GAAP) |
|||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
|||||||||||
Year Ended December 31, 2015 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
|||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
||||||||
Less: Texas Margin Tax Rate Reduction |
- |
(20) |
(20) |
||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
||||||||
Add: Severance Costs |
9 |
(3) |
6 |
||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
||||||||
Total |
$ |
7,013 |
$ |
(2,454) |
$ |
4,559 |
|||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
|||||||||||
Year Ended December 31, 2014 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
|||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
|||||||||||
Foreign Earnings in Future Years |
- |
250 |
250 |
||||||||
Total |
$ |
(484) |
$ |
285 |
$ |
(199) |
|||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2013: |
|||||||||||
Year Ended December 31, 2013 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
283 |
$ |
(101) |
$ |
182 |
|||||
Add: Impairments of Certain Assets |
7 |
(3) |
4 |
||||||||
Less: Net Gains on Asset Dispositions |
(198) |
61 |
(137) |
||||||||
Total |
$ |
92 |
$ |
(43) |
$ |
49 |
EOG RESOURCES, INC. | |||||||||||
Fourth Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Fourth Quarter and Full Year 2016 Forecast |
|||||||||||
The forecast items for the fourth quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges |
|||||||||||
(Unaudited) |
|||||||||||
4Q 2016 |
Full Year 2016 | ||||||||||
Daily Production |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
290.0 |
- |
300.0 |
274.3 |
- |
276.8 | |||||
Trinidad |
0.4 |
- |
0.8 |
0.7 |
- |
0.8 | |||||
Other International |
5.0 |
- |
9.0 |
3.5 |
- |
4.5 | |||||
Total |
295.4 |
- |
309.8 |
278.5 |
- |
282.1 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
79.0 |
- |
83.0 |
81.1 |
- |
82.2 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
810 |
- |
840 |
813 |
- |
820 | |||||
Trinidad |
300 |
- |
330 |
335 |
- |
342 | |||||
Other International |
20 |
- |
24 |
24 |
- |
25 | |||||
Total |
1,130 |
- |
1,194 |
1,172 |
- |
1,187 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
504.0 |
- |
523.0 |
490.9 |
- |
495.7 | |||||
Trinidad |
50.4 |
- |
55.8 |
56.5 |
- |
57.8 | |||||
Other International |
8.3 |
- |
13.0 |
7.5 |
- |
8.7 | |||||
Total |
562.7 |
- |
591.8 |
554.9 |
- |
562.2 | |||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.40 |
- |
$ |
4.90 |
$ |
4.50 |
- |
$ |
4.66 | |
Transportation Costs |
$ |
3.75 |
- |
$ |
4.25 |
$ |
3.77 |
- |
$ |
3.90 | |
Depreciation, Depletion and Amortization |
$ |
17.70 |
- |
$ |
18.10 |
$ |
17.77 |
- |
$ |
17.87 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
105 |
- |
$ |
135 |
$ |
421 |
- |
$ |
451 | |
General and Administrative |
$ |
90 |
- |
$ |
100 |
$ |
338 |
- |
$ |
348 | |
Gathering and Processing |
$ |
29 |
- |
$ |
31 |
$ |
119 |
- |
$ |
121 | |
Capitalized Interest |
$ |
33 |
- |
$ |
37 |
$ |
58 |
- |
$ |
62 | |
Net Interest |
$ |
41 |
- |
$ |
44 |
$ |
251 |
- |
$ |
254 | |
Taxes Other Than Income (% of Wellhead Revenue) |
5.9% |
- |
6.3% |
6.3% |
- |
6.5% | |||||
Income Taxes |
|||||||||||
Effective Rate |
28% |
- |
33% |
28% |
- |
33% | |||||
Current Taxes ($MM) |
$ |
25 |
- |
$ |
40 |
$ |
108 |
- |
$ |
123 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
2,200 |
- |
$ |
2,300 | ||||||
Exploration and Development Facilities |
$ |
325 |
- |
$ |
375 | ||||||
Gathering, Processing and Other |
$ |
75 |
- |
$ |
125 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(2.40) |
- |
$ |
(1.40) |
$ |
(1.90) |
- |
$ |
(1.63) | |
Trinidad - above (below) WTI |
$ |
(10.50) |
- |
$ |
(9.50) |
$ |
(10.31) |
- |
$ |
(10.10) | |
Other International - above (below) WTI |
$ |
(6.00) |
- |
$ |
(4.00) |
$ |
(4.00) |
- |
$ |
(3.50) | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
29% |
- |
33% |
31% |
- |
32% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.05) |
- |
$ |
(0.65) |
$ |
(0.86) |
- |
$ |
(0.76) | |
Realizations |
|||||||||||
Trinidad |
$ |
1.70 |
- |
$ |
2.10 |
$ |
1.83 |
- |
$ |
1.93 | |
Other International |
$ |
3.45 |
- |
$ |
3.95 |
$ |
3.54 |
- |
$ |
3.66 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, Nov. 1, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Bank of America Merrill Lynch Global Energy Conference on Thursday, November 17 at 12:20 p.m. Central time (1:20 p.m. Eastern time). Lloyd W. "Billy" Helms, Jr., Executive Vice President, Exploration and Production, will present on behalf of EOG. Please visit the Investors/Overview page on the EOG website to access the live webcast. If you are unable to listen to the live webcast, a replay will be available on the Investors/Presentations and Events page until February 15.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
Investors and Media |
SOURCE EOG Resources, Inc.
HOUSTON, Oct. 11, 2016 /PRNewswire/ -- EOG Resources, Inc. (EOG) will host a conference call to discuss third quarter 2016 results on Friday, November 4, 2016, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors/Overview page on the EOG website to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available on the Investors/ Presentations and Events page for one year.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors | |
Cedric W. Burgher | ||
(713) 571-4658 | ||
David J. Streit | ||
(713) 571-4902 | ||
Kimberly M. Ehmer | ||
(713) 571-4676 | ||
Media | ||
K Leonard | ||
(713) 571-3870 |
SOURCE EOG Resources, Inc.
HOUSTON, Sept. 28, 2016 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable October 31, 2016, to stockholders of record as of October 17, 2016. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
David J. Streit | |
(713) 571-4902 | |
Media | |
K Leonard | |
(713) 571-3870 |
SOURCE EOG Resources, Inc.
HOUSTON and ARTESIA, N.M., Sept. 6, 2016 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) and Yates Petroleum Corporation today announced definitive agreements under which EOG has agreed to combine with Yates Petroleum Corporation, Abo Petroleum Corporation, MYCO Industries, Inc. and certain other entities (collectively, Yates). Under the terms of this private, negotiated transaction, EOG will issue 26.06 million shares of common stock valued at $2.3 billion and pay $37 million in cash, subject to certain closing adjustments and lock-up provisions. EOG will assume and repay at closing $245 million of Yates debt offset by $131 million of anticipated cash from Yates, subject also to certain closing adjustments.
"This transaction combines the companies' existing large, premier, stacked-pay acreage positions in the heart of the Delaware and Powder River basins, paving the way for years of high-return drilling and production growth," said William R. "Bill" Thomas, Chairman and Chief Executive Officer of EOG. "We are excited by this unique opportunity to advance EOG's strategy of generating high-return growth by developing premium wells at low costs that enhance long-term shareholder value.
"Additionally we are thrilled to welcome Yates' 300 employees to the EOG family and look forward to continuing the important presence Yates has established in the community of Artesia, N.M."
Yates is a privately held, independent crude oil and natural gas company with 1.6 million net acres across the western United States. Since 1924, when it drilled the first commercial oil well on New Mexico state trust lands, Yates has amassed a rich acreage position across the western United States. Highlights of Yates' assets are summarized below:
EOG is the largest oil producer in the Lower 48, with average net daily production of 551 thousand barrels of crude oil equivalent and a reputation for technological leadership in the development of unconventional resource plays.
"EOG is our partner of choice as we look to extend Yates' 93-year legacy," said John A. Yates Sr., Chairman Emeritus of Yates Petroleum Corporation and son of founder Martin Yates Jr. "As we enter a new era of unconventional resource development, we are excited to join forces with another pioneering company like EOG."
Douglas E. Brooks, Chief Executive Officer of Yates Petroleum Corporation, added, "This is a tremendous opportunity to combine EOG's strong technical competencies with the enormous resource potential of the Yates acreage to create significant value for Yates and EOG shareholders alike."
Yates immediately adds an estimated 1,740 net premium drilling locations in the Delaware Basin and Powder River Basin to EOG's growing inventory of premium drilling locations, a 40 percent increase. A premium drilling location is defined by EOG as a direct after-tax rate of return of at least 30 percent assuming a $40 flat crude oil price. EOG plans to commence drilling on the Yates acreage in late 2016 with additional rigs added in 2017.
"Through this transaction, our premium drilling strategy is gaining added momentum. With improving well productivity and this newly enhanced resource base, our organization can generate further increases in returns and capital efficiency," Thomas said. "The combination enhances the size and quality of EOG's existing portfolio of oil resource plays."
Doubles Position in Delaware Basin and Adjacent Plays
Yates has 186,000 net acres of stacked pay in the Delaware Basin in New Mexico that is highly prospective for the Wolfcamp, Bone Spring and Leonard Shale formations. This brings the combined company's total Delaware Basin acreage position to approximately 424,000 net acres, a 78 percent increase to EOG's existing holdings.
Additionally, Yates has 138,000 net acres on the Northwest Shelf in New Mexico that is prospective for the Yeso, Abo, Wolfcamp and Cisco formations. These shallow plays have the potential to contribute additional amounts of premium inventory with the application of EOG's advanced completion and precision targeting technologies and low cost structure. Along with EOG's existing acreage, the newly combined company will have 574,000 net acres in the Delaware Basin and Northwest Shelf. A summary of the acreage is listed below.
Delaware Basin and Northwest Shelf Acreage Summary | |||
By Play |
Yates |
EOG |
Combined |
Wolfcamp |
186,000 |
168,000 |
354,000 |
Bone Spring |
186,000 |
111,000 |
297,000 |
Leonard |
67,000 |
93,000 |
160,000 |
By Area Delaware Basin |
186,000 |
238,000 |
424,000 |
Northwest Shelf |
138,000 |
12,000 |
150,000 |
Total |
324,000 |
250,000 |
574,000 |
Expands Powder River Basin Acreage
The combination also adds 81,000 net acres from Yates in the core development area of the Powder River Basin that is prospective for the Turner Oil play. In total, Yates contributes 200,000 net acres in the Powder River Basin. This doubles EOG's total Powder River Basin acreage to 400,000 net acres. The enhanced acreage position has significant exploration potential for multiple stacked-pay formations.
Transaction Terms
Under the terms of the agreements, which were approved by the boards of directors of EOG and Yates, and the Yates stockholders, EOG will issue 26.06 million shares of common stock valued at $2.3 billion and pay $37 million in cash, subject to certain closing adjustments and lock-up provisions. EOG will assume and repay at closing $245 million of Yates debt offset by $131 million of anticipated cash from Yates, subject also to certain closing adjustments. Closing is anticipated in early October 2016, subject to customary closing conditions. Following the transaction closing, EOG intends to maintain Yates' office in Artesia, N.M., to support the newly combined operation.
Wells Fargo Securities, LLC acted as exclusive financial and technical advisor to Yates Petroleum Corporation, Abo Petroleum Corporation and MYCO Industries, Inc. for this transaction. Thompson & Knight LLP, Modrall Sperling Law Firm and Kemp Smith LLP acted as legal advisors to Yates Petroleum Corporation, Abo Petroleum Corporation and MYCO Industries, Inc., respectively. Akin Gump Strauss Hauer & Feld LLP acted as legal advisor to EOG.
Conference Call Tuesday, September 6, 2016
EOG will host a conference call to discuss the transaction that will be available via live audio webcast at 10 a.m. Central time (11 a.m. Eastern time) on Tuesday, September 6, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through September 20, 2016.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
Yates Petroleum Corporation is a privately owned, independent exploration and production company, headquartered in Artesia, N.M. Yates Petroleum Corporation has a rich acreage position across the western United States in proven, horizontal resource plays. Yates' focus areas in the Permian Basin and Powder River Basins are stacked oil plays with low-risk, multi-zone opportunities. Yates has a valuable resource in its employees, who possess a deep technical knowledge across all of its areas of operation. For additional information about Yates, please visit www.yatespetroleum.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements herein, other than statements of historical fact, including, among others, statements regarding EOG's projections and expectations with respect to the future operations of the combined company, the future drilling activities and production growth in respect of the acquired Yates acreage, the returns and performance to be achieved from the combined company's assets, EOG's business strategy, plans and objectives in respect of the acquired Yates acreage and the anticipated closing date of the transaction described herein, are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements are enumerated in EOG's most recent Quarterly Reports on Form 10-Q filed with the United States Securities and Exchange Commission (SEC); see the sections entitled "Information Regarding Forward-Looking Statements" therein. Also, see "Risk Factors" on pages 13 through 21 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015 filed with the SEC for a discussion of certain risk factors that affect or may affect EOG's business, financial position and results of operations. You should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. Reconciliation and calculation schedules for EOG non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release or accompanying investor presentation that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.
Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Kimberly M. Ehmer
(713) 571-4676
Media
K Leonard
(713) 571-3870
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 30, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Barclays CEO Energy-Power Conference at 7:25 a.m. Central time (8:25 a.m. Eastern time) on Wednesday, September 7. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG. A replay of the webcast will be available until October 7.
EOG is also scheduled to present at the UBS Energy Bus-less Tour at 11:15 a.m. Central time (12:15 p.m. Eastern time) on Wednesday, September 14. David W. Trice, Executive Vice President, Exploration and Production, will present on behalf of EOG. A replay of the webcast will be available until October 14.
Live webcasts of the presentations, as well as accompanying slides, will be available in the Investors Overview section of EOG's website, http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
Investors
Cedric W. Burgher
(713) 571-4658
Kimberly M. Ehmer
(713) 571-4676
David J. Streit
(713) 571-4902
Media
K Leonard
(713) 571-3870
SOURCE EOG Resources, Inc.
HOUSTON, Aug. 4, 2016 /PRNewswire/ --
EOG Resources, Inc. (EOG) today reported a second quarter 2016 net loss of $292.6 million, or $0.53 per share. This compares to second quarter 2015 net income of $5.3 million, or $0.01 per share.
Adjusted non-GAAP net loss for the second quarter 2016 was $209.7 million, or $0.38 per share, compared to adjusted non-GAAP net income of $153.1 million, or $0.28 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching hedge realizations to settlement months and making certain other adjustments in order to exclude non-recurring items. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Lower commodity prices more than offset significant well productivity improvements and cost reductions, resulting in decreases in adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the second quarter 2016 compared to the second quarter 2015. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Operational Highlights
In the second quarter 2016, EOG increased its inventory of net premium drilling locations from 3,200 to 4,300. Premium inventory is defined by a direct after-tax rate of return hurdle rate of at least 30 percent assuming $40 flat crude oil prices. Total premium net resource potential increased from 2.0 billion barrels of oil equivalent (BnBoe) to 3.5 BnBoe. These additions were the result of advances in completion technology, precision targeting, longer laterals and cost reductions.
U.S. crude oil volumes of 265,400 barrels of oil per day (Bopd) in the second quarter 2016 exceeded the midpoint of the company's guidance by 2 percent. Compared to the same prior year period, lease and well expenses decreased 23 percent, and transportation costs decreased 13 percent, both on a per-unit basis. Total general and administrative expenses decreased 5 percent compared to the second quarter 2015, excluding expenses related to a voluntary retirement program.
Exploration and development expenditures (excluding property acquisitions) decreased 49 percent, while total crude oil production declined by only 4 percent, in the second quarter 2016 compared to the same period last year. Total natural gas production for the second quarter 2016 decreased 5 percent versus the same prior year period.
"The benefits of EOG's premium drilling strategy are beginning to show in our operating performance," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We are committed to focusing capital on our premium assets which we are confident will increasingly lead to break-out performance as prices improve. This quarter's addition of 1.5 BnBoe of additional premium net resource potential further solidifies our ability to deliver premium returns over the long term."
2016 Capital Plan Update and 2020 Crude Oil Production Outlook
As a result of cost reductions and efficiency improvements, EOG has increased its targeted number of well completions for 2016 from 270 to 350 net wells. Many of the additional well completions are scheduled for late 2016. In addition, due to increased drilling productivity, the company expects to drill 250 net wells, 50 more than in its original 2016 plans. This increase in activity will be accomplished while maintaining 2016 capital expenditure guidance of $2.4 to $2.6 billion, excluding acquisitions.
EOG can achieve significant production growth with balanced cash flow from 2017 through 2020, even in a moderate commodity price environment. Based on EOG's long-term plan and assuming a flat $50 West Texas Intermediate crude oil price (WTI), EOG would expect 10 percent compound annual crude oil production growth through 2020. Assuming flat $60 WTI, EOG would expect 20 percent compound annual crude oil production growth through 2020.
"EOG's long-term outlook reflects superior capital efficiency and continued capital discipline, hallmarks of the company since its founding," Thomas said. "Our premium drilling strategy is the key to our future success, and it is underpinned by EOG's industry-leading asset quality, scale, technology, well performance and low-cost structure. Most importantly, EOG's high-performance culture prioritizes rates of return over other performance metrics."
South Texas Eagle Ford
The South Texas Eagle Ford, EOG's largest high-return play, continues to lead the company in activity and production. In the second quarter, EOG increased its Eagle Ford premium inventory by 390 net drilling locations to almost 2,000 total. This large inventory of high-quality locations could be expanded significantly should additional cost reductions or improvements in well productivity be achieved. For example, EOG estimates that a 10 percent reduction in completed well costs or a 10 percent improvement in estimated recoverable reserves per well would more than double EOG's premium inventory in the Eagle Ford.
In the second quarter, EOG completed 60 wells in the Eagle Ford with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 1,705 barrels of oil equivalent per day (Boed), or 1,340 Bopd, 175 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.1 million cubic feet per day (MMcfd) of natural gas.
Delaware Basin
In the second quarter, EOG expanded its premium inventory in all three of its major Delaware Basin formations – the Wolfcamp, the Second Bone Spring and the Leonard. By organically adding more than 500 net premium drilling locations, EOG is well positioned for years of high-return growth in this world-class basin. EOG continues to improve well economics in the Delaware Basin through advances in well and completion designs, including recent breakthroughs that enable higher productivity with longer laterals.
In the Delaware Basin Wolfcamp, EOG completed 16 wells in the second quarter with an average treated lateral length of 6,500 feet per well, a 44 percent increase in lateral length from the prior quarter. The average 30-day initial production rate per well was 2,410 Boed, or 1,610 Bopd, 340 Bpd of NGLs and 2.8 MMcfd of natural gas. In the Delaware Basin Second Bone Spring, EOG completed nine wells in the second quarter with an average treated lateral length of 4,500 feet per well and an average 30-day initial production rate per well of 1,500 Boed, or 1,120 Bopd, 155 Bpd of NGLs and 1.4 MMcfd of natural gas.
Rockies and the Bakken
EOG is continuing to optimize its core Rockies and Bakken plays, adding 200 additional net premium drilling locations to its inventory in the DJ Basin Codell in Wyoming. The Codell is a liquids-rich sandstone formation that now has significant premium potential due to cost reductions and efficiencies along with the application of EOG's precision targeting and completion technology.
In the DJ Basin Codell in Wyoming, EOG completed the Jubilee 541-3502H well in the second quarter with average 30-day initial production rates of 1,190 Bopd, 130 Bpd of NGLs and 0.5 MMcfd of natural gas.
In the Powder River Basin Turner, EOG completed the Arbalest 73-06H, 272-06H and 66-0607H wells on the same pad during the second quarter with average 30-day initial production rates per well of 1,000 Bopd, 330 Bpd of NGLs and 3.8 MMcfd of natural gas.
In the North Dakota Bakken, EOG completed the Austin 421-2821H, 422-2821H and 423-2821H wells in a three-well pattern in the second quarter with average 30-day initial production rates per well of 1,100 Bopd, 90 Bpd of NGLs and 0.5 MMcfd of natural gas. Also in the North Dakota Bakken, EOG completed the West Clark 103-0136H and 104-0136H wells in a two-well pattern with average 30-day initial production rates per well of 1,210 Bopd, 390 Bpd of NGLs and 1.8 MMcfd of natural gas.
In the Three Forks, EOG completed the West Clark 117-0136H well in the second quarter with average 30-day initial production rates of 1,290 Bopd, 380 Bpd of NGLs and 1.8 MMcfd of natural gas.
Hedging Activity
For the period March 1 through August 31, 2016, EOG had natural gas financial price swap contracts in place for 60,000 million British thermal units (MMBtu) per day at a weighted average price of $2.49 per MMBtu.
For the period September 1 through November 30, 2016, EOG sold natural gas call option contracts for 43,750 MMBtu per day at an average strike price of $3.45 per MMBtu. For the period March 1 through November 30, 2017, EOG sold natural gas call option contracts for 43,750 MMBtu per day at an average strike price of $3.45 per MMBtu. For the period March 1 through November 30, 2018, EOG sold natural gas call option contracts for 12,500 MMBtu per day at an average strike price of $3.32 per MMBtu.
For the period March 1 through November 30, 2017, EOG purchased natural gas put option contracts for 35,000 MMBtu per day at an average strike price of $2.90 per MMBtu. For the period March 1 through November 30, 2018, EOG purchased natural gas put option contracts for 10,000 MMBtu per day at an average strike price of $2.90 per MMBtu.
A comprehensive summary of natural gas derivative contracts is provided in the attached tables.
Capital Structure and Asset Sales
At June 30, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 37 percent. Taking into account cash on the balance sheet of $780 million at the end of the second quarter, EOG's net debt was $6.2 billion with a net debt-to-total capitalization ratio of 34 percent. For a reconciliation of non-GAAP measures to GAAP measures, please refer to the attached tables.
Proceeds from asset sales this year to date total $425 million. This includes proceeds from two transactions that closed in the third quarter 2016. The assets were divested in more than a dozen separate transactions of non-core natural gas and liquids-rich properties. Associated production of the divested assets was 45 MMcfd of natural gas, 3,300 Bopd and 3,700 Bpd of NGLs. Sales of additional non-core assets are in progress and anticipated to close in 2016.
Conference Call August 5, 2016
EOG's second quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, August 5, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through August 19, 2016.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." For additional information about EOG, please visit www.eogresources.com.
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Six Months Ended | ||||||||||
June 30, |
June 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
$ |
1,775.7 |
$ |
2,469.7 |
$ |
3,130.1 |
$ |
4,788.2 | |||
Net Income ( Loss) |
$ |
(292.6) |
$ |
5.3 |
$ |
(764.3) |
$ |
(164.5) | |||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
(0.53) |
$ |
0.01 |
$ |
(1.40) |
$ |
(0.30) | |||
Diluted |
$ |
(0.53) |
$ |
0.01 |
$ |
(1.40) |
$ |
(0.30) | |||
Average Number of Common Shares |
|||||||||||
Basic |
547.3 |
545.5 |
547.0 |
545.2 | |||||||
Diluted |
547.3 |
549.7 |
547.0 |
545.2 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Six Months Ended | ||||||||||
June 30, |
June 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Operating Revenues |
|||||||||||
Crude Oil and Condensate |
$ |
1,059,690 |
$ |
1,452,756 |
$ |
1,813,401 |
$ |
2,713,000 | |||
Natural Gas Liquids |
111,643 |
103,930 |
186,962 |
215,920 | |||||||
Natural Gas |
155,983 |
274,038 |
321,486 |
561,820 | |||||||
Gains (Losses) on Mark-to-Market Commodity |
|||||||||||
Derivative Contracts |
(44,373) |
(48,493) |
(38,938) |
27,715 | |||||||
Gathering, Processing and Marketing |
485,256 |
678,356 |
819,209 |
1,248,626 | |||||||
Losses on Asset Dispositions, Net |
(15,550) |
(5,564) |
(6,403) |
(3,957) | |||||||
Other, Net |
23,091 |
14,678 |
34,372 |
25,115 | |||||||
Total |
1,775,740 |
2,469,701 |
3,130,089 |
4,788,239 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
218,393 |
289,664 |
459,258 |
651,145 | |||||||
Transportation Costs |
179,471 |
209,833 |
369,925 |
438,145 | |||||||
Gathering and Processing Costs |
29,226 |
34,997 |
57,750 |
71,006 | |||||||
Exploration Costs |
30,559 |
43,755 |
60,388 |
83,204 | |||||||
Dry Hole Costs |
(172) |
(551) |
74 |
14,119 | |||||||
Impairments |
72,714 |
68,519 |
144,331 |
137,955 | |||||||
Marketing Costs |
480,046 |
670,169 |
820,900 |
1,308,831 | |||||||
Depreciation, Depletion and Amortization |
862,491 |
909,227 |
1,791,382 |
1,822,015 | |||||||
General and Administrative |
97,705 |
82,324 |
198,236 |
166,621 | |||||||
Taxes Other Than Income |
93,480 |
122,138 |
154,159 |
228,567 | |||||||
Total |
2,063,913 |
2,430,075 |
4,056,403 |
4,921,608 | |||||||
Operating Income (Loss) |
(288,173) |
39,626 |
(926,314) |
(133,369) | |||||||
Other Income (Expense), Net |
(20,996) |
9,380 |
(25,433) |
(611) | |||||||
Income (Loss) Before Interest Expense and Income Taxes |
(309,169) |
49,006 |
(951,747) |
(133,980) | |||||||
Interest Expense, Net |
71,108 |
60,484 |
139,498 |
113,829 | |||||||
Loss Before Income Taxes |
(380,277) |
(11,478) |
(1,091,245) |
(247,809) | |||||||
Income Tax Benefit |
(87,719) |
(16,746) |
(326,911) |
(83,329) | |||||||
Net Income (Loss) |
$ |
(292,558) |
$ |
5,268 |
$ |
(764,334) |
$ |
(164,480) | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.3350 |
$ |
0.3350 |
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended |
Six Months Ended | ||||||||||
June 30, |
June 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
265.4 |
276.5 |
265.6 |
287.5 | |||||||
Trinidad |
0.8 |
0.7 |
0.8 |
0.9 | |||||||
Other International (B) |
1.5 |
0.3 |
1.4 |
0.2 | |||||||
Total |
267.7 |
277.5 |
267.8 |
288.6 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
43.87 |
$ |
57.47 |
$ |
37.36 |
$ |
51.91 | |||
Trinidad |
35.91 |
49.53 |
29.83 |
44.03 | |||||||
Other International (B) |
- |
62.40 |
- |
56.67 | |||||||
Composite |
43.65 |
57.45 |
37.23 |
51.89 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
84.3 |
73.4 |
81.8 |
75.4 | |||||||
Other International (B) |
- |
0.1 |
- |
0.1 | |||||||
Total |
84.3 |
73.5 |
81.8 |
75.5 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
14.56 |
$ |
15.55 |
$ |
12.54 |
$ |
15.83 | |||
Other International (B) |
- |
7.81 |
- |
5.80 | |||||||
Composite |
14.56 |
15.54 |
12.54 |
15.82 | |||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
820 |
891 |
825 |
898 | |||||||
Trinidad |
349 |
334 |
355 |
336 | |||||||
Other International (B) |
25 |
32 |
25 |
31 | |||||||
Total |
1,194 |
1,257 |
1,205 |
1,265 | |||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
1.18 |
$ |
2.11 |
$ |
1.22 |
$ |
2.19 | |||
Trinidad |
1.89 |
3.05 |
1.88 |
3.07 | |||||||
Other International (B) |
3.35 |
3.49 |
3.49 |
3.39 | |||||||
Composite |
1.44 |
2.40 |
1.47 |
2.45 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
486.3 |
498.3 |
484.9 |
512.6 | |||||||
Trinidad |
59.0 |
56.5 |
59.9 |
56.8 | |||||||
Other International (B) |
5.8 |
5.7 |
5.6 |
5.5 | |||||||
Total |
551.1 |
560.5 |
550.4 |
574.9 | |||||||
Total MMBoe (D) |
50.1 |
51.0 |
100.2 |
104.1 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
June 30, |
December 31, | ||||
2016 |
2015 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
779,722 |
$ |
718,506 | |
Accounts Receivable, Net |
935,592 |
930,610 | |||
Inventories |
495,826 |
598,935 | |||
Income Taxes Receivable |
4,880 |
40,704 | |||
Deferred Income Taxes |
46,712 |
147,812 | |||
Other |
187,389 |
155,677 | |||
Total |
2,450,121 |
2,592,244 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
51,355,620 |
50,613,241 | |||
Other Property, Plant and Equipment |
4,001,132 |
3,986,610 | |||
Total Property, Plant and Equipment |
55,356,752 |
54,599,851 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(32,143,873) |
(30,389,130) | |||
Total Property, Plant and Equipment, Net |
23,212,879 |
24,210,721 | |||
Other Assets |
167,538 |
167,505 | |||
Total Assets |
$ |
25,830,538 |
$ |
26,970,470 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,305,651 |
$ |
1,471,953 | |
Accrued Taxes Payable |
138,395 |
93,618 | |||
Dividends Payable |
91,679 |
91,546 | |||
Liabilities from Price Risk Management Activities |
1,315 |
- | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
168,642 |
155,591 | |||
Total |
1,712,261 |
1,819,287 | |||
Long-Term Debt |
6,979,286 |
6,648,911 | |||
Other Liabilities |
978,513 |
971,335 | |||
Deferred Income Taxes |
4,103,777 |
4,587,902 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
|||||
551,004,831 Shares Issued at June 30, 2016 and 550,150,823 |
|||||
Shares Issued at December 31, 2015 |
205,510 |
205,502 | |||
Additional Paid in Capital |
2,982,047 |
2,923,461 | |||
Accumulated Other Comprehensive Loss |
(25,264) |
(33,338) | |||
Retained Earnings |
8,923,666 |
9,870,816 | |||
Common Stock Held in Treasury, 375,869 Shares at June 30, 2016 |
|||||
and 292,179 Shares at December 31, 2015 |
(29,258) |
(23,406) | |||
Total Stockholders' Equity |
12,056,701 |
12,943,035 | |||
Total Liabilities and Stockholders' Equity |
$ |
25,830,538 |
$ |
26,970,470 |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Six Months Ended | |||||
June 30, | |||||
2016 |
2015 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Loss to Net Cash Provided by Operating Activities: |
|||||
Net Loss |
$ |
(764,334) |
$ |
(164,480) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
1,791,382 |
1,822,015 | |||
Impairments |
144,331 |
137,955 | |||
Stock-Based Compensation Expenses |
59,471 |
61,650 | |||
Deferred Income Taxes |
(384,294) |
(154,803) | |||
Losses on Asset Dispositions, Net |
6,403 |
3,957 | |||
Other, Net |
29,991 |
6,787 | |||
Dry Hole Costs |
74 |
14,119 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total (Gains) Losses |
38,938 |
(27,715) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
2,852 |
561,142 | |||
Excess Tax Benefits from Stock-Based Compensation |
(11,811) |
(16,393) | |||
Other, Net |
5,008 |
6,346 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
(22,572) |
298,183 | |||
Inventories |
95,813 |
37,609 | |||
Accounts Payable |
(203,358) |
(999,644) | |||
Accrued Taxes Payable |
93,320 |
64,124 | |||
Other Assets |
(33,589) |
76,114 | |||
Other Liabilities |
1,565 |
(48,848) | |||
Changes in Components of Working Capital Associated with Investing and Financing |
|||||
Activities |
(54,453) |
169,802 | |||
Net Cash Provided by Operating Activities |
794,737 |
1,847,920 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(1,143,549) |
(2,611,848) | |||
Additions to Other Property, Plant and Equipment |
(44,584) |
(201,597) | |||
Proceeds from Sales of Assets |
252,529 |
116,166 | |||
Changes in Components of Working Capital Associated with Investing Activities |
54,477 |
(169,903) | |||
Net Cash Used in Investing Activities |
(881,127) |
(2,867,182) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
(259,718) |
- | |||
Long-Term Debt Borrowings |
991,097 |
990,225 | |||
Long-Term Debt Repayments |
(400,000) |
(500,000) | |||
Dividends Paid |
(184,036) |
(183,130) | |||
Excess Tax Benefits from Stock-Based Compensation |
11,811 |
16,393 | |||
Treasury Stock Purchased |
(28,755) |
(26,362) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
10,624 |
14,484 | |||
Debt Issuance Costs |
(1,602) |
(1,585) | |||
Repayment of Capital Lease Obligation |
(3,150) |
(3,053) | |||
Other, Net |
(24) |
101 | |||
Net Cash Provided by Financing Activities |
136,247 |
307,073 | |||
Effect of Exchange Rate Changes on Cash |
11,359 |
(7,629) | |||
Increase (Decrease) in Cash and Cash Equivalents |
61,216 |
(719,818) | |||
Cash and Cash Equivalents at Beginning of Period |
718,506 |
2,087,213 | |||
Cash and Cash Equivalents at End of Period |
$ |
779,722 |
$ |
1,367,395 |
EOG RESOURCES, INC. | |||||||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||||||
to Net Income (Loss) (GAAP) | |||||||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2016 and 2015 reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (gains) losses from these transactions, to eliminate the net losses on asset dispositions in 2015 and 2016, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back severance costs associated with EOG's North American operations in 2015, to eliminate the impact of the Trinidad tax settlement in 2016 and to add back certain voluntary retirement expense in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||||||
Three Months Ended |
Three Months Ended | ||||||||||||||
June 30, 2016 |
June 30, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ (380,277) |
$ 87,719 |
$ (292,558) |
$ (0.53) |
$ (11,478) |
$ 16,746 |
$ 5,268 |
$ 0.01 | |||||||
Adjustments: |
|||||||||||||||
Gains (Losses) on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
44,373 |
(15,819) |
28,554 |
0.05 |
48,493 |
(17,288) |
31,205 |
0.06 | |||||||
Net Cash Received from (Payments for) |
|||||||||||||||
Settlements of Commodity Derivative |
|||||||||||||||
Contracts |
(14,835) |
5,289 |
(9,546) |
(0.01) |
193,435 |
(68,960) |
124,475 |
0.23 | |||||||
Add: Net Losses on Asset Dispositions |
15,550 |
(7,378) |
8,172 |
0.01 |
5,564 |
570 |
6,134 |
0.01 | |||||||
Less: Texas Margin Tax Rate Reduction |
- |
- |
- |
- |
- |
(19,500) |
(19,500) |
(0.04) | |||||||
Add: Severance Costs |
- |
- |
- |
- |
8,505 |
(3,032) |
5,473 |
0.01 | |||||||
Add: Trinidad Tax Settlement |
- |
43,000 |
43,000 |
0.08 |
- |
- |
- |
- | |||||||
Add: Voluntary Retirement Expense |
19,663 |
(7,010) |
12,653 |
0.02 |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
64,751 |
18,082 |
82,833 |
0.15 |
255,997 |
(108,210) |
147,787 |
0.27 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ (315,526) |
$ 105,801 |
$ (209,725) |
$ (0.38) |
$ 244,519 |
$ (91,464) |
$ 153,055 |
$ 0.28 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
547,335 |
545,504 | |||||||||||||
Diluted |
547,335 |
549,683 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
547,335 |
545,504 | |||||||||||||
Diluted |
547,335 |
549,683 | |||||||||||||
Six Months Ended |
Six Months Ended | ||||||||||||||
June 30, 2016 |
June 30, 2015 | ||||||||||||||
Income |
Diluted |
Income |
Diluted | ||||||||||||
Before |
Tax |
After |
Earnings |
Before |
Tax |
After |
Earnings | ||||||||
Tax |
Impact |
Tax |
per Share |
Tax |
Impact |
Tax |
per Share | ||||||||
Reported Net Income (Loss) (GAAP) |
$ (1,091,245) |
$ 326,911 |
$ (764,334) |
$ (1.40) |
$ (247,809) |
$ 83,329 |
$ (164,480) |
$ (0.30) | |||||||
Adjustments: |
|||||||||||||||
Gains (Losses) on Mark-to-Market Commodity |
|||||||||||||||
Derivative Contracts |
38,938 |
(13,881) |
25,057 |
0.05 |
(27,715) |
9,880 |
(17,835) |
(0.03) | |||||||
Net Cash Received from (Payments for) |
|||||||||||||||
Settlements of Commodity Derivative |
|||||||||||||||
Contracts |
2,852 |
(1,017) |
1,835 |
0.00 |
561,142 |
(200,047) |
361,095 |
0.66 | |||||||
Add: Net Losses on Asset Dispositions |
6,403 |
(4,168) |
2,235 |
0.00 |
3,957 |
1,166 |
5,123 |
0.01 | |||||||
Less: Texas Margin Tax Rate Reduction |
- |
- |
- |
- |
- |
(19,500) |
(19,500) |
(0.04) | |||||||
Add: Severance Costs |
- |
- |
- |
- |
8,505 |
(3,032) |
5,473 |
0.01 | |||||||
Add: Trinidad Tax Settlement |
- |
43,000 |
43,000 |
0.08 |
- |
- |
- |
- | |||||||
Add: Voluntary Retirement Expense |
42,054 |
(14,992) |
27,062 |
0.05 |
- |
- |
- |
- | |||||||
Adjustments to Net Income (Loss) |
90,247 |
8,942 |
99,189 |
0.18 |
545,889 |
(211,533) |
334,356 |
0.61 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ (1,000,998) |
$ 335,853 |
$ (665,145) |
$ (1.22) |
$ 298,080 |
$ (128,204) |
$ 169,876 |
$ 0.31 | |||||||
Average Number of Common Shares (GAAP) |
|||||||||||||||
Basic |
547,029 |
545,245 | |||||||||||||
Diluted |
547,029 |
545,245 | |||||||||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||||||
Basic |
547,029 |
545,245 | |||||||||||||
Diluted |
547,029 |
549,505 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
to Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and six-month periods ended June 30, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Six Months Ended | |||||||||||
June 30, |
June 30, | |||||||||||
2016 |
2015 |
2016 |
2015 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
503,146 |
$ |
887,373 |
$ |
794,737 |
$ |
1,847,920 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
25,527 |
37,870 |
48,884 |
69,967 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
11,811 |
7,535 |
11,811 |
16,393 | ||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||
and Liabilities |
||||||||||||
Accounts Receivable |
154,970 |
54,917 |
22,572 |
(298,183) | ||||||||
Inventories |
(38,235) |
(99,781) |
(95,813) |
(37,609) | ||||||||
Accounts Payable |
(86,269) |
321,769 |
203,358 |
999,644 | ||||||||
Accrued Taxes Payable |
(90,860) |
(62,019) |
(93,320) |
(64,124) | ||||||||
Other Assets |
37,535 |
(16,938) |
33,589 |
(76,114) | ||||||||
Other Liabilities |
6,427 |
16,993 |
(1,565) |
48,848 | ||||||||
Changes in Components of Working Capital Associated with |
||||||||||||
Investing and Financing Activities |
56,681 |
90,190 |
54,453 |
(169,802) | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
580,733 |
$ |
1,237,909 |
$ |
978,706 |
$ |
2,336,940 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-53% |
-58% |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Net Income (Loss) (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and six-month periods ended June 30, 2016 and 2015 reported Net Income (Loss) (GAAP) to Earnings Before Net Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from (payments for) settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) (gains) losses from these transactions and to eliminate the net losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Net Income (Loss) (GAAP) to add back Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
Three Months Ended |
Six Months Ended | ||||||||||
June 30, |
June 30, | ||||||||||
2016 |
2015 |
2016 |
2015 | ||||||||
Net Income (Loss) (GAAP) |
$ |
(292,558) |
$ |
5,268 |
$ |
(764,334) |
$ |
(164,480) | |||
Adjustments: |
|||||||||||
Interest Expense, Net |
71,108 |
60,484 |
139,498 |
113,829 | |||||||
Income Tax Benefit |
(87,719) |
(16,746) |
(326,911) |
(83,329) | |||||||
Depreciation, Depletion and Amortization |
862,491 |
909,227 |
1,791,382 |
1,822,015 | |||||||
Exploration Costs |
30,559 |
43,755 |
60,388 |
83,204 | |||||||
Dry Hole Costs |
(172) |
(551) |
74 |
14,119 | |||||||
Impairments |
72,714 |
68,519 |
144,331 |
137,955 | |||||||
EBITDAX (Non-GAAP) |
656,423 |
1,069,956 |
1,044,428 |
1,923,313 | |||||||
Total (Gains) Losses on MTM Commodity Derivative Contracts |
44,373 |
48,493 |
38,938 |
(27,715) | |||||||
Net Cash Received from (Payments for) Settlements of Commodity |
|||||||||||
Derivative Contracts |
(14,835) |
193,435 |
2,852 |
561,142 | |||||||
Losses on Asset Dispositions, Net |
15,550 |
5,564 |
6,403 |
3,957 | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
701,511 |
$ |
1,317,448 |
$ |
1,092,621 |
$ |
2,460,697 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-47% |
-56% |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
June 30, |
December 31, | ||||
2016 |
2015 | ||||
Total Stockholders' Equity - (a) |
$ |
12,057 |
$ |
12,943 | |
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,655 | |||
Less: Cash |
(780) |
(719) | |||
Net Debt (Non-GAAP) - (c) |
6,206 |
5,936 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
19,043 |
$ |
19,598 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
18,263 |
$ |
18,879 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
37% |
34% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
34% |
31% |
EOG RESOURCES, INC. | |||||||||||
Natural Gas Financial | |||||||||||
Commodity Derivative Contracts | |||||||||||
Presented below is a comprehensive summary of EOG's natural gas derivative contracts at August 4, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||||||||
Natural Gas Option Contracts | |||||||||||
Call Options Sold |
Put Options Purchased | ||||||||||
Weighted |
Weighted | ||||||||||
Volume |
Average Price |
Volume |
Average Price | ||||||||
(MMBtud) |
($/MMBtu) |
(MMBtud) |
($/MMBtu) | ||||||||
2016 |
|||||||||||
September 1, 2016 through November 30, 2016 |
43,750 |
$ 3.45 |
- |
$ - | |||||||
2017 |
|||||||||||
March 1, 2017 through November 30, 2017 |
43,750 |
$ 3.45 |
35,000 |
$ 2.90 | |||||||
2018 |
|||||||||||
March 1, 2018 through November 30, 2018 |
12,500 |
$ 3.32 |
10,000 |
$ 2.90 | |||||||
Definitions |
|||||||||||
MMBtud Million British thermal units per day |
|||||||||||
$/MMBtu Dollars per million British thermal units |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. | |||||||||||
2015 |
2014 |
2013 |
2012 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
237 |
$ |
201 |
$ |
235 |
|||||
Tax Benefit Imputed (based on 35%) |
(83) |
(70) |
(82) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
154 |
$ |
131 |
$ |
153 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
|||||
Adjustments to Net Income (Loss), Net of Tax (See Accompanying Schedules) |
4,559 |
(a) |
(199) |
(b) |
49 |
(c) |
|||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
34 |
$ |
2,716 |
$ |
2,246 |
|||||
Total Stockholders' Equity - (d) |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
$ |
13,285 | |||
Average Total Stockholders' Equity * - (e) |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,660 |
$ |
5,910 |
$ |
5,913 |
$ |
6,312 | |||
Less: Cash |
(719) |
(2,087) |
(1,318) |
(876) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,941 |
$ |
3,823 |
$ |
4,595 |
$ |
5,436 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,603 |
$ |
23,623 |
$ |
21,331 |
$ |
19,597 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,884 |
$ |
21,536 |
$ |
20,013 |
$ |
18,721 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,210 |
$ |
20,775 |
$ |
19,367 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-21.6% |
14.7% |
12.1% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
0.9% |
13.7% |
12.4% |
||||||||
Return on Equity (ROE) (Non-GAAP) |
|||||||||||
ROE (GAAP Net Income) - (b) / (e) |
-29.5% |
17.6% |
15.3% |
||||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
0.2% |
16.4% |
15.6% |
||||||||
* Average for the current and immediately preceding year |
|||||||||||
Adjustments to Net Income (Loss) (GAAP) |
|||||||||||
(a) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2015: |
|||||||||||
Year Ended December 31, 2015 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
668 |
$ |
(238) |
$ |
430 |
|||||
Add: Impairments of Certain Assets |
6,308 |
(2,183) |
4,125 |
||||||||
Less: Texas Margin Tax Rate Reduction |
(20) |
- |
(20) |
||||||||
Add: Legal Settlement - Early Leasehold Termination |
19 |
(6) |
13 |
||||||||
Add: Severance Costs |
9 |
(3) |
6 |
||||||||
Add: Net Losses on Asset Dispositions |
9 |
(4) |
5 |
||||||||
Total |
$ |
6,993 |
$ |
(2,434) |
$ |
4,559 |
|||||
(b) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2014: |
|||||||||||
Year Ended December 31, 2014 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Less: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
(800) |
$ |
285 |
$ |
(515) |
|||||
Add: Impairments of Certain Assets |
824 |
(271) |
553 |
||||||||
Less: Net Gains on Asset Dispositions |
(508) |
21 |
(487) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
250 |
- |
250 |
||||||||
Total |
$ |
(234) |
$ |
35 |
$ |
(199) |
|||||
(c) See below schedule for detail of adjustments to Net Income (Loss) (GAAP) in 2013: |
|||||||||||
Year Ended December 31, 2013 |
|||||||||||
Before |
Income Tax |
After |
|||||||||
Tax |
Impact |
Tax |
|||||||||
Adjustments: |
|||||||||||
Add: Mark-to-Market Commodity Derivative Contracts Impact |
$ |
283 |
$ |
(101) |
$ |
182 |
|||||
Add: Impairments of Certain Assets |
7 |
(3) |
4 |
||||||||
Less: Net Gains on Asset Dispositions |
(198) |
61 |
(137) |
||||||||
Total |
$ |
92 |
$ |
(43) |
$ |
49 |
EOG RESOURCES, INC. | |||||||||||
Third Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Third Quarter and Full Year 2016 Forecast |
|||||||||||
The forecast items for the third quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing |
|||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
3Q 2016 |
Full Year 2016 | ||||||||||
Daily Production |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
264.0 |
- |
272.0 |
266.0 |
- |
270.0 | |||||
Trinidad |
0.4 |
- |
0.8 |
0.6 |
- |
0.8 | |||||
Other International |
4.0 |
- |
8.0 |
3.0 |
- |
5.0 | |||||
Total |
268.4 |
- |
280.8 |
269.6 |
- |
275.8 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
75.0 |
- |
79.0 |
76.0 |
- |
80.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
740 |
- |
760 |
775 |
- |
795 | |||||
Trinidad |
325 |
- |
355 |
330 |
- |
355 | |||||
Other International |
20 |
- |
24 |
22 |
- |
24 | |||||
Total |
1,085 |
- |
1,139 |
1,127 |
- |
1,174 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
462.3 |
- |
477.7 |
471.2 |
- |
482.5 | |||||
Trinidad |
54.6 |
- |
60.0 |
55.6 |
- |
60.0 | |||||
Other International |
7.3 |
- |
12.0 |
6.7 |
- |
9.0 | |||||
Total |
524.2 |
- |
549.7 |
533.5 |
- |
551.5 | |||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
4.50 |
- |
$ |
5.00 |
$ |
4.50 |
- |
$ |
5.00 | |
Transportation Costs |
$ |
3.75 |
- |
$ |
4.25 |
$ |
3.70 |
- |
$ |
4.00 | |
Depreciation, Depletion and Amortization |
$ |
17.45 |
- |
$ |
17.85 |
$ |
17.65 |
- |
$ |
18.00 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
105 |
- |
$ |
125 |
$ |
415 |
- |
$ |
460 | |
General and Administrative |
$ |
85 |
- |
$ |
95 |
$ |
320 |
- |
$ |
340 | |
Gathering and Processing |
$ |
28 |
- |
$ |
32 |
$ |
112 |
- |
$ |
122 | |
Capitalized Interest |
$ |
6 |
- |
$ |
8 |
$ |
30 |
- |
$ |
33 | |
Net Interest |
$ |
69 |
- |
$ |
71 |
$ |
277 |
- |
$ |
283 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.3% |
- |
6.7% |
6.4% |
- |
6.6% | |||||
Income Taxes |
|||||||||||
Effective Rate |
28% |
- |
33% |
28% |
- |
33% | |||||
Current Taxes ($MM) |
$ |
(15) |
- |
$ |
0 |
$ |
50 |
- |
$ |
70 | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
1,925 |
- |
$ |
2,025 | ||||||
Exploration and Development Facilities |
$ |
350 |
- |
$ |
400 | ||||||
Gathering, Processing and Other |
$ |
125 |
- |
$ |
175 | ||||||
Pricing - (Refer toBenchmark Commodity Pricingin text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(3.00) |
- |
$ |
(1.00) |
$ |
(2.65) |
- |
$ |
(1.65) | |
Trinidad - above (below) WTI |
$ |
(10.50) |
- |
$ |
(9.50) |
$ |
(10.80) |
- |
$ |
(10.30) | |
Other International - above (below) WTI |
$ |
(5.00) |
- |
$ |
(3.00) |
$ |
(5.15) |
- |
$ |
(4.15) | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
30% |
- |
34% |
31% |
- |
33% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.15) |
- |
$ |
(0.50) |
$ |
(0.90) |
- |
$ |
(0.70) | |
Realizations |
|||||||||||
Trinidad |
$ |
1.70 |
- |
$ |
2.30 |
$ |
1.85 |
- |
$ |
2.20 | |
Other International |
$ |
3.00 |
- |
$ |
4.25 |
$ |
3.30 |
- |
$ |
3.80 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, June 28, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss second quarter 2016 results on Friday, August 5, 2016, at 9 a.m. Central time (10 a.m. Eastern time). Please visit the Investors Overview section of EOG's website, http://investors.eogresources.com/overview, to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available following the call until Friday, August 19, 2016, and can be accessed from http://investors.eogresources.com/overview.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
Media | |
K Leonard | |
(713) 571-3870 |
SOURCE EOG Resources, Inc.
HOUSTON, May 26, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) is scheduled to present at the Bernstein Strategic Decisions Conference at 8 a.m. Central time (9 a.m. Eastern time) on Wednesday, June 1. William R. "Bill" Thomas, Chairman and Chief Executive Officer, will present on behalf of EOG. A replay of the webcast will be available until July 7.
Thomas is also scheduled to present at the Wells Fargo West Coast Energy Conference at 11 a.m. Central time (9 a.m. Pacific time) on Tuesday, June 21. A replay of the webcast will be available until July 21.
In addition, EOG is scheduled to present at the J.P. Morgan Inaugural Energy Equity Investor Conference at 7 a.m. Central time (8 a.m. Eastern time) on Wednesday, June 29. Lloyd W. "Billy" Helms, Jr., Executive Vice President, Exploration and Production, will present on behalf of EOG. A replay of the webcast will be available until July 29.
Live webcasts of the presentations, as well as accompanying slides, will be available in the Investors Overview section of EOG's website, http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG." To learn more about EOG, visit the website at www.eogresources.com.
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
David J. Streit | |
(713) 571-4902 | |
Media | |
K Leonard | |
(713) 571-3870 |
SOURCE EOG Resources, Inc.
HOUSTON, May 5, 2016 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a first quarter 2016 net loss of $471.8 million, or $0.86 per share. This compares to a first quarter 2015 net loss of $169.7 million, or $0.31 per share.
Adjusted non-GAAP net loss for the first quarter 2016 was $455.4 million, or $0.83 per share, compared to adjusted non-GAAP net income of $16.8 million, or $0.03 per share, for the same prior year period. Adjusted non-GAAP net income (loss) is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Lower commodity prices more than offset significant well productivity improvements and cost reductions, resulting in decreases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the first quarter 2016 compared to the first quarter 2015. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Operational Highlights
In the first quarter 2016, EOG implemented its previously announced strategy to focus capital in areas which generate premium rates of return. This move significantly improved average well performance and contributed to EOG's strong production in the first quarter 2016. U.S. crude oil volumes exceeded the high end of the company's forecast in the first quarter 2016.
In addition, EOG continued to reduce costs across its operations. During the first quarter of 2016, lease and well expenses decreased 29 percent and transportation costs decreased 12 percent compared to the same prior year period, both on a per-unit basis. Total general and administrative expenses decreased 7 percent compared to the first quarter 2015, excluding expenses related to a voluntary retirement program.
EOG's East Irish Sea Conwy project in the United Kingdom achieved first production in March 2016.
EOG also continued to improve capital efficiency. For the first quarter 2016, exploration and development expenditures (excluding property acquisitions) decreased 61 percent, while total crude oil and condensate production declined by only 10 percent, compared to the first quarter 2015. Total natural gas production for the first quarter 2016 decreased 3 percent versus the prior year period.
"Our premium drilling strategy is extending EOG's performance leadership in the upstream industry," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "Excellent well performance and cost reductions drove tremendous capital efficiency gains and gave EOG a great start on another successful year. EOG is steadily approaching its goal of becoming one of the lowest cost global oil producers through its sustainable advantages in asset quality, technology, cost reductions and operational execution."
Enhanced Oil Recovery (EOR)
EOG confirmed success of its internally developed EOR process in the Eagle Ford following more than three years of testing in four successful pilot projects with 15 producing wells. These four pilot projects, located across the field, demonstrated consistent reservoir responses from a group of mature producing wells. The pilots generated significant increases in crude oil production with relatively low capital cost. One additional EOR pilot project that encompasses 32 producing wells is planned for 2016.
EOG anticipates many benefits from the application of this new technology, including high incremental net present value and rates of return on investment, low finding and operating costs, reduced severance tax rates, lower production decline rates and increased reservoir recoveries. EOG's Eagle Ford shale acreage position possesses unique geologic properties ideally suited for the company's proprietary EOR techniques. These methods require very strong geologic containment that may not exist in most horizontal oil plays.
"Today's introduction of EOG's enhanced oil recovery potential for the Eagle Ford shale is another technical breakthrough to further enhance the value of EOG's Eagle Ford assets," Thomas said. "Our proprietary EOR capabilities and first-mover advantages uniquely position the company to create substantial incremental shareholder value through this long-life project."
South Texas Austin Chalk
EOG expanded its inventory of high rate of return crude oil plays with successful drilling results in the South Texas Austin Chalk, which sits on top of the South Texas Eagle Ford shale. The initial test well, the Leonard AC Unit 101H, came online with average 30-day initial production rates of 2,100 barrels of oil per day (Bopd) with 295 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.9 million cubic feet per day (MMcfd) of natural gas. A second Austin Chalk well, the Denali Unit 101H, was brought online in April 2016, with average 20-day initial production rates of 2,265 Bopd with 415 Bpd of NGLs and 2.7 MMcfd of natural gas. EOG intends to drill seven additional Austin Chalk wells in 2016 to further delineate the formation's potential.
"EOG continues to demonstrate its organic growth capabilities by discovering a new geologic concept in an existing play," Thomas said. "Although the industry has known about the Austin Chalk for many years, it took a new approach to turn it into a high rate of return play which competes with EOG's top-tier assets. We expect the Austin Chalk to make a meaningful contribution to our future success."
South Texas Eagle Ford
EOG continued to achieve strong well performance and capital efficiencies in the Eagle Ford during the first quarter 2016. In Gonzales County, EOG completed the Stills Unit 2H with average 30-day initial production rates of 2,775 Bopd, 345 Bpd of NGLs and 2.2 MMcfd of natural gas and the Neets Unit 9H with average 30-day initial production rates of 2,355 Bopd, 255 Bpd of NGLs and 1.7 MMcfd of natural gas. Also in Gonzales County, EOG completed the Fleetwood Unit 5H-8H wells in a four-well pattern with average 30-day initial production rates per well of 2,330 Bopd, 320 Bpd of NGLs and 2.1 MMcfd of natural gas. In Lavaca County, EOG completed the Boedeker 18H with average 30-day initial production rates of 2,305 Bopd, 220 Bpd of NGLs and 1.4 MMcfd of natural gas.
Delaware Basin
EOG's advancements in precision targeting and completions technology continue to drive superior well results and rates of return in the Delaware Basin. In the Delaware Basin Wolfcamp in Lea County, N.M., EOG completed the Rattlesnake 21 Fed Com #701H and #702H with average 20-day initial production rates of 2,670 and 2,870 Bopd, 450 and 480 Bpd of NGLs and 3.7 and 4.0 MMcfd of natural gas, respectively. Also in the Delaware Basin Wolfcamp in Lea County, N.M., EOG completed the Lomas Rojas 26 State Com #701H - #704H in a four-well pattern with average 30-day initial production rates per well of 1,910 Bopd, 300 Bpd of NGLs and 2.4 MMcfd of natural gas.
EOG continues to improve well and completion designs in the Delaware Basin, which led to increased well productivity in the first quarter 2016.
Hedging Activity
For the period April 12 through April 30, 2016, EOG had crude oil financial price swap contracts in place for 90,000 Bopd at a weighted average price of $42.30 per barrel. For the period May 1 through June 30, 2016, EOG has crude oil financial price swap contracts in place for 128,000 Bopd at a weighted average price of $42.56 per barrel.
For the period March 1 through May 31, 2016, EOG had natural gas financial price swap contracts in place for 60,000 million British thermal units (MMBtu) per day at a weighted average price of $2.49 per MMBtu. For the period June 1 through August 31, 2016, EOG has natural gas financial price swap contracts in place for 60,000 MMBtu per day at a weighted average price of $2.49 per MMBtu.
A comprehensive summary of crude oil and natural gas derivative contracts is provided in the attached tables.
Capital Structure
At March 31, 2016, EOG's total debt outstanding was $7.0 billion with a debt-to-total capitalization ratio of 36 percent. Taking into account cash on the balance sheet of $668 million at the end of the first quarter, EOG's net debt was $6.3 billion with a net debt-to-total capitalization ratio of 34 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.
Conference Call May 6, 2016
EOG's first quarter 2016 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, May 6, 2016. To listen, log on to the Investors Overview page on the EOG website at http://investors.eogresources.com/overview. The webcast will be archived on EOG's website through May 20, 2016.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Kimberly M. Ehmer
(713) 571-4676
Media
K Leonard
(713) 571-3870
EOG RESOURCES, INC. | |||||
Financial Report | |||||
(Unaudited; in millions, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Net Operating Revenues |
$ |
1,354.3 |
$ |
2,318.5 | |
Net Loss |
$ |
(471.8) |
$ |
(169.7) | |
Net Loss Per Share |
|||||
Basic |
$ |
(0.86) |
$ |
(0.31) | |
Diluted |
$ |
(0.86) |
$ |
(0.31) | |
Average Number of Common Shares |
|||||
Basic |
546.7 |
545.0 | |||
Diluted |
546.7 |
545.0 | |||
Summary Income Statements | |||||
(Unaudited; in thousands, except per share data) | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Net Operating Revenues |
|||||
Crude Oil and Condensate |
$ |
753,711 |
$ |
1,260,244 | |
Natural Gas Liquids |
75,319 |
111,990 | |||
Natural Gas |
165,503 |
287,782 | |||
Gains on Mark-to-Market Commodity Derivative Contracts |
5,435 |
76,208 | |||
Gathering, Processing and Marketing |
333,953 |
570,270 | |||
Gains on Asset Dispositions, Net |
9,147 |
1,607 | |||
Other, Net |
11,281 |
10,437 | |||
Total |
1,354,349 |
2,318,538 | |||
Operating Expenses |
|||||
Lease and Well |
240,865 |
361,481 | |||
Transportation Costs |
190,454 |
228,312 | |||
Gathering and Processing Costs |
28,524 |
36,009 | |||
Exploration Costs |
29,829 |
39,449 | |||
Dry Hole Costs |
246 |
14,670 | |||
Impairments |
71,617 |
69,436 | |||
Marketing Costs |
340,854 |
638,662 | |||
Depreciation, Depletion and Amortization |
928,891 |
912,788 | |||
General and Administrative |
100,531 |
84,297 | |||
Taxes Other Than Income |
60,679 |
106,429 | |||
Total |
1,992,490 |
2,491,533 | |||
Operating Loss |
(638,141) |
(172,995) | |||
Other Expense, Net |
(4,437) |
(9,991) | |||
Loss Before Interest Expense and Income Taxes |
(642,578) |
(182,986) | |||
Interest Expense, Net |
68,390 |
53,345 | |||
Loss Before Income Taxes |
(710,968) |
(236,331) | |||
Income Tax Benefit |
(239,192) |
(66,583) | |||
Net Loss |
$ |
(471,776) |
$ |
(169,748) | |
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 | |
EOG RESOURCES, INC. | |||||
Operating Highlights | |||||
(Unaudited) | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Wellhead Volumes and Prices |
|||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||
United States |
265.8 |
298.6 | |||
Trinidad |
0.7 |
1.0 | |||
Other International (B) |
1.4 |
0.1 | |||
Total |
267.9 |
299.7 | |||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||
United States |
$ |
30.87 |
$ |
46.71 | |
Trinidad |
22.78 |
39.78 | |||
Other International (B) |
32.33 |
43.06 | |||
Composite |
30.85 |
46.68 | |||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||
United States |
79.4 |
77.4 | |||
Other International (B) |
- |
0.1 | |||
Total |
79.4 |
77.5 | |||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||
United States |
$ |
10.41 |
$ |
16.10 | |
Other International (B) |
- |
2.46 | |||
Composite |
10.41 |
16.08 | |||
Natural Gas Volumes (MMcfd) (A) |
|||||
United States |
829 |
905 | |||
Trinidad |
361 |
337 | |||
Other International (B) |
25 |
31 | |||
Total |
1,215 |
1,273 | |||
Average Natural Gas Prices ($/Mcf) (C) |
|||||
United States |
$ |
1.27 |
$ |
2.27 | |
Trinidad |
1.88 |
3.09 | |||
Other International (B) |
3.63 |
3.28 | |||
Composite |
1.50 |
2.51 | |||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||
United States |
483.6 |
527.1 | |||
Trinidad |
60.8 |
57.1 | |||
Other International (B) |
5.5 |
5.3 | |||
Total |
549.9 |
589.5 | |||
Total MMBoe (D) |
50.0 |
53.1 | |||
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. | |||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. | |||||
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
March 31, |
December 31, | ||||
2016 |
2015 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
668,481 |
$ |
718,506 | |
Accounts Receivable, Net |
780,625 |
930,610 | |||
Inventories |
538,926 |
598,935 | |||
Assets from Price Risk Management Activities |
4,070 |
- | |||
Income Taxes Receivable |
39,045 |
40,704 | |||
Deferred Income Taxes |
177,057 |
147,812 | |||
Other |
157,608 |
155,677 | |||
Total |
2,365,812 |
2,592,244 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
51,159,332 |
50,613,241 | |||
Other Property, Plant and Equipment |
4,004,310 |
3,986,610 | |||
Total Property, Plant and Equipment |
55,163,642 |
54,599,851 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(31,362,209) |
(30,389,130) | |||
Total Property, Plant and Equipment, Net |
23,801,433 |
24,210,721 | |||
Other Assets |
171,178 |
167,505 | |||
Total Assets |
$ |
26,338,423 |
$ |
26,970,470 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,182,025 |
$ |
1,471,953 | |
Accrued Taxes Payable |
93,077 |
93,618 | |||
Dividends Payable |
91,569 |
91,546 | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
174,722 |
155,591 | |||
Total |
1,547,972 |
1,819,287 | |||
Long-Term Debt |
6,979,029 |
6,648,911 | |||
Other Liabilities |
985,713 |
971,335 | |||
Deferred Income Taxes |
4,420,221 |
4,587,902 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and 550,576,063Shares Issued at March 31, 2016 and 550,150,823 Shares Issued at December 31, 2015 |
205,506 |
205,502 | |||
Additional Paid in Capital |
2,951,861 |
2,923,461 | |||
Accumulated Other Comprehensive Loss |
(31,131) |
(33,338) | |||
Retained Earnings |
9,308,463 |
9,870,816 | |||
Common Stock Held in Treasury, 383,609 Shares at March 31, 2016 and 292,179 Shares at December 31, 2015 |
(29,211) |
(23,406) | |||
Total Stockholders' Equity |
12,405,488 |
12,943,035 | |||
Total Liabilities and Stockholders' Equity |
$ |
26,338,423 |
$ |
26,970,470 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Loss to Net Cash Provided by Operating Activities: |
|||||
Net Loss |
$ |
(471,776) |
$ |
(169,748) | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
928,891 |
912,788 | |||
Impairments |
71,617 |
69,436 | |||
Stock-Based Compensation Expenses |
32,380 |
33,052 | |||
Deferred Income Taxes |
(196,696) |
(97,241) | |||
Gains on Asset Dispositions, Net |
(9,147) |
(1,607) | |||
Other, Net |
5,442 |
12,469 | |||
Dry Hole Costs |
246 |
14,670 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total Gains |
(5,435) |
(76,208) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
17,687 |
367,707 | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
(8,858) | |||
Other, Net |
1,407 |
1,616 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
132,398 |
353,100 | |||
Inventories |
57,578 |
(62,172) | |||
Accounts Payable |
(289,627) |
(677,875) | |||
Accrued Taxes Payable |
2,460 |
2,105 | |||
Other Assets |
3,946 |
59,176 | |||
Other Liabilities |
7,992 |
(31,855) | |||
Changes in Components of Working Capital Associated with Investing and Financing Activities |
2,228 |
259,992 | |||
Net Cash Provided by Operating Activities |
291,591 |
960,547 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(547,399) |
(1,428,733) | |||
Additions to Other Property, Plant and Equipment |
(25,792) |
(116,866) | |||
Proceeds from Sales of Assets |
6,667 |
1,118 | |||
Changes in Components of Working Capital Associated with Investing Activities |
(2,228) |
(259,741) | |||
Net Cash Used in Investing Activities |
(568,752) |
(1,804,222) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Repayments |
(259,718) |
- | |||
Long-Term Debt Borrowings |
991,097 |
990,225 | |||
Long-Term Debt Repayments |
(400,000) |
- | |||
Dividends Paid |
(92,170) |
(91,661) | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
8,858 | |||
Treasury Stock Purchased |
(12,672) |
(15,459) | |||
Proceeds from Stock Options Exercised |
2,688 |
3,984 | |||
Debt Issuance Costs |
(1,592) |
(1,603) | |||
Repayment of Capital Lease Obligation |
(1,569) |
(1,521) | |||
Other, Net |
- |
(251) | |||
Net Cash Provided by Financing Activities |
226,064 |
892,572 | |||
Effect of Exchange Rate Changes on Cash |
1,072 |
(8,691) | |||
(Decrease) Increase in Cash and Cash Equivalents |
(50,025) |
40,206 | |||
Cash and Cash Equivalents at Beginning of Period |
718,506 |
2,087,213 | |||
Cash and Cash Equivalents at End of Period |
$ |
668,481 |
$ |
2,127,419 | |
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||
to Net Loss (GAAP) | |||||
(Unaudited; in thousands, except per share data) | |||||
The following chart adjusts the three-month periods ended March 31, 2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net gains on asset dispositions in 2015 and 2016 and to add back certain voluntary retirement expense in 2016. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Reported Net Loss (GAAP) |
$ |
(471,776) |
$ |
(169,748) | |
Commodity Derivative Contracts Impact |
|||||
Gains on Mark-to-Market Commodity Derivative Contracts |
(5,435) |
(76,208) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
17,687 |
367,707 | |||
Pre-tax MTM Impact |
12,252 |
291,499 | |||
After-Tax MTM Impact |
7,884 |
187,580 | |||
Less: Net Gains on Asset Dispositions, Net of Tax (Pre-tax $9,147 and $1,607, respectively) |
(5,937) |
(1,011) | |||
Add: Voluntary Retirement Expense, Net of Tax (Pre-tax $22,391) |
14,409 |
- | |||
Adjusted Net Income (Loss) (Non-GAAP) |
$ |
(455,420) |
$ |
16,821 | |
Net Loss Per Share (GAAP) |
|||||
Basic |
$ |
(0.86) |
$ |
(0.31) | |
Diluted |
$ |
(0.86) |
$ |
(0.31) | |
Adjusted Net Income (Loss) Per Share (Non-GAAP) |
|||||
Basic |
$ |
(0.83) |
$ |
0.03 | |
Diluted |
$ |
(0.83) |
$ |
0.03 | |
Adjusted Net Income (Loss) Per Diluted Share (Non-GAAP) - Percentage Decrease |
-2,867% |
||||
Average Number of Common Shares (GAAP) |
|||||
Basic |
546,715 |
544,998 | |||
Diluted |
546,715 |
544,998 | |||
Average Number of Common Shares (Non-GAAP) |
|||||
Basic |
546,715 |
544,998 | |||
Diluted |
546,715 |
549,401 | |||
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | |||||
to Net Cash Provided By Operating Activities (GAAP) | |||||
(Unaudited; in thousands) | |||||
The following chart reconciles the three-month periods ended March 31, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
291,591 |
$ |
960,547 | |
Adjustments: |
|||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
23,357 |
32,097 | |||
Excess Tax Benefits from Stock-Based Compensation |
- |
8,858 | |||
Changes in Components of Working Capital and Other Assets |
|||||
and Liabilities |
|||||
Accounts Receivable |
(132,398) |
(353,100) | |||
Inventories |
(57,578) |
62,172 | |||
Accounts Payable |
289,627 |
677,875 | |||
Accrued Taxes Payable |
(2,460) |
(2,105) | |||
Other Assets |
(3,946) |
(59,176) | |||
Other Liabilities |
(7,992) |
31,855 | |||
Changes in Components of Working Capital Associated with |
|||||
Investing and Financing Activities |
(2,228) |
(259,992) | |||
Discretionary Cash Flow (Non-GAAP) |
$ |
397,973 |
$ |
1,099,031 | |
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-64% |
||||
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, | |||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||
(Non-GAAP) to Loss Before Interest Expense and Income Taxes (GAAP) | |||||
(Unaudited; in thousands) | |||||
The following chart adjusts the three-month periods ended March 31, 2016 and 2015 reported Loss Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net gains on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Loss Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. | |||||
Three Months Ended | |||||
March 31, | |||||
2016 |
2015 | ||||
Loss Before Interest Expense and Income Taxes (GAAP) |
$ |
(642,578) |
$ |
(182,986) | |
Adjustments: |
|||||
Depreciation, Depletion and Amortization |
928,891 |
912,788 | |||
Exploration Costs |
29,829 |
39,449 | |||
Dry Hole Costs |
246 |
14,670 | |||
Impairments |
71,617 |
69,436 | |||
EBITDAX (Non-GAAP) |
388,005 |
853,357 | |||
Total Gains on MTM Commodity Derivative Contracts |
(5,435) |
(76,208) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
17,687 |
367,707 | |||
Gains on Asset Dispositions, Net |
(9,147) |
(1,607) | |||
Adjusted EBITDAX (Non-GAAP) |
$ |
391,110 |
$ |
1,143,249 | |
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-66% |
||||
EOG RESOURCES, INC. | |||||
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total | |||||
Capitalization (Non-GAAP) as Used in the Calculation of | |||||
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to | |||||
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) | |||||
(Unaudited; in millions, except ratio data) | |||||
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. | |||||
At |
At | ||||
March 31, |
December 31, | ||||
2016 |
2015 | ||||
Total Stockholders' Equity - (a) |
$ |
12,405 |
12,943 | ||
Current and Long-Term Debt (GAAP) - (b) |
6,986 |
6,655 | |||
Less: Cash |
(668) |
(719) | |||
Net Debt (Non-GAAP) - (c) |
6,318 |
5,936 | |||
Total Capitalization (GAAP) - (a) + (b) |
$ |
19,391 |
$ |
19,598 | |
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
18,723 |
$ |
18,879 | |
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
36% |
34% | |||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
34% |
31% | |||
EOG RESOURCES, INC. | |||
Crude Oil and Natural Gas Financial | |||
Commodity Derivative Contracts | |||
Presented below is a comprehensive summary of EOG's crude oil and natural gas derivative contracts at May 5, 2016, with notional volumes expressed in Bbld and MMBtud and prices expressed in $/Bbl and $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||
Crude Oil Derivative Contracts | |||
Weighted | |||
Volume |
Average Price | ||
(Bbld) |
($/Bbl) | ||
2016 |
|||
April 12, 2016 through April 30, 2016 (closed) |
90,000 |
$ 42.30 | |
May 1, 2016 through June 30, 2016 |
128,000 |
42.56 | |
Natural Gas Derivative Contracts | |||
Weighted | |||
Volume |
Average Price | ||
(MMBtud) |
($/MMBtu) | ||
2016 |
|||
March 1, 2016 through May 31, 2016 (closed) |
60,000 |
$ 2.49 | |
June 1, 2016 through August 31, 2016 |
60,000 |
2.49 | |
$/Bbl Dollars per barrel |
|||
$/MMBtu Dollars per million British thermal units |
|||
Bbld Barrels per day |
|||
MMBtu Million British thermal units |
|||
MMBtud Million British thermal units per day |
|||
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry. | |||||||||||
2015 |
2014 |
2013 |
2012 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
237 |
$ |
201 |
$ |
235 |
|||||
Tax Benefit Imputed (based on 35%) |
(83) |
(70) |
(82) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
154 |
$ |
131 |
$ |
153 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
|||||
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact |
430 |
(515) |
182 |
||||||||
Add: Impairments of Certain Assets, Net of Tax |
4,125 |
553 |
4 |
||||||||
Less: Texas Margin Tax Rate Reduction |
(20) |
- |
- |
||||||||
Add: Legal Settlement - Early Leasehold Termination, Net of Tax |
13 |
- |
- |
||||||||
Add: Severance Costs, Net of Tax |
6 |
- |
- |
||||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax |
5 |
(487) |
(137) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated Foreign Earnings in Future Years |
- |
250 |
- |
||||||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
34 |
$ |
2,716 |
$ |
2,246 |
|||||
Total Stockholders' Equity - (d) |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
$ |
13,285 | |||
Average Total Stockholders' Equity * - (e) |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,660 |
$ |
5,910 |
$ |
5,913 |
$ |
6,312 | |||
Less: Cash |
(719) |
(2,087) |
(1,318) |
(876) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,941 |
$ |
3,823 |
$ |
4,595 |
$ |
5,436 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,603 |
$ |
23,623 |
$ |
21,331 |
$ |
19,597 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,884 |
$ |
21,536 |
$ |
20,013 |
$ |
18,721 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,210 |
$ |
20,775 |
$ |
19,367 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-21.6% |
14.7% |
12.1% |
||||||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
0.9% |
13.7% |
12.4% |
||||||||
Return on Equity (ROE) (Non-GAAP) |
|||||||||||
ROE (GAAP Net Income) - (b) / (e) |
-29.5% |
17.6% |
15.3% |
||||||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
0.2% |
16.4% |
15.6% |
||||||||
* Average for the current and immediately preceding year |
|||||||||||
EOG RESOURCES, INC. | |||||||||||
Second Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) Second Quarter and Full Year 2016 Forecast | |||||||||||
The forecast items for the second quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
2Q 2016 |
Full Year 2016 | ||||||||||
Daily Production |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
255.0 |
- |
265.0 |
256.0 |
- |
271.0 | |||||
Trinidad |
0.3 |
- |
0.5 |
0.4 |
- |
0.6 | |||||
Other International |
4.0 |
- |
8.0 |
4.0 |
- |
8.0 | |||||
Total |
259.3 |
- |
273.5 |
260.4 |
- |
279.6 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
71.0 |
- |
79.0 |
72.0 |
- |
80.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
785 |
- |
805 |
770 |
- |
800 | |||||
Trinidad |
290 |
- |
340 |
290 |
- |
320 | |||||
Other International |
20 |
- |
26 |
20 |
- |
25 | |||||
Total |
1,095 |
- |
1,171 |
1,080 |
- |
1,145 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
456.8 |
- |
478.2 |
456.3 |
- |
484.3 | |||||
Trinidad |
48.6 |
- |
57.2 |
48.7 |
- |
53.9 | |||||
Other International |
7.3 |
- |
12.3 |
7.3 |
- |
12.2 | |||||
Total |
512.7 |
- |
547.7 |
512.3 |
- |
550.4 | |||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
5.00 |
- |
$ |
5.50 |
$ |
5.00 |
- |
$ |
5.80 | |
Transportation Costs |
$ |
3.70 |
- |
$ |
4.30 |
$ |
3.80 |
- |
$ |
4.30 | |
Depreciation, Depletion and Amortization |
$ |
17.60 |
- |
$ |
18.00 |
$ |
17.90 |
- |
$ |
18.40 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
110 |
- |
$ |
130 |
$ |
425 |
- |
$ |
475 | |
General and Administrative |
$ |
80 |
- |
$ |
90 |
$ |
325 |
- |
$ |
355 | |
Gathering and Processing |
$ |
30 |
- |
$ |
35 |
$ |
115 |
- |
$ |
135 | |
Capitalized Interest |
$ |
7 |
- |
$ |
9 |
$ |
28 |
- |
$ |
32 | |
Net Interest |
$ |
69 |
- |
$ |
71 |
$ |
275 |
- |
$ |
285 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.8% |
- |
7.3% |
6.3% |
- |
6.8% | |||||
Income Taxes |
|||||||||||
Effective Rate |
32% |
- |
37% |
32% |
- |
37% | |||||
Current Taxes ($MM) |
$ |
(50) |
- |
$ |
(35) |
$ |
(180) |
- |
$ |
(160) | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
1,925 |
- |
$ |
2,025 | ||||||
Exploration and Development Facilities |
$ |
350 |
- |
$ |
400 | ||||||
Gathering, Processing and Other |
$ |
125 |
- |
$ |
175 | ||||||
Pricing - (Refer to Benchmark Commodity Pricing in text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(3.50) |
- |
$ |
(1.50) |
$ |
(3.75) |
- |
$ |
(1.75) | |
Trinidad - above (below) WTI |
$ |
(10.75) |
- |
$ |
(9.75) |
$ |
(13.00) |
- |
$ |
(10.00) | |
Other International - above (below) WTI |
$ |
(8.00) |
- |
$ |
(6.00) |
$ |
(5.25) |
- |
$ |
(3.25) | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
29% |
- |
33% |
29% |
- |
33% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.20) |
- |
$ |
(0.50) |
$ |
(1.20) |
- |
$ |
(0.50) | |
Realizations |
|||||||||||
Trinidad |
$ |
1.70 |
- |
$ |
2.30 |
$ |
1.75 |
- |
$ |
2.35 | |
Other International |
$ |
3.00 |
- |
$ |
4.25 |
$ |
3.30 |
- |
$ |
3.90 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
|||||||||||
SOURCE EOG Resources, Inc.
HOUSTON, April 27, 2016 /PRNewswire/ -- The Board of Directors of EOG Resources, Inc. (NYSE: EOG) (EOG) has declared a dividend of $0.1675 per share on EOG's Common Stock, payable July 29, 2016, to stockholders of record as of July 15, 2016. The indicated annual rate is $0.67.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
David J. Streit | |
(713) 571-4902 | |
Media | |
K Leonard | |
(713) 571-3870 |
SOURCE EOG Resources, Inc.
HOUSTON, April 5, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss first quarter 2016 results on Friday, May 6, 2016, at 9 a.m. Central time (10 a.m. Eastern time). Please visit EOG's website at http://investors.eogresources.com/overview to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available following the call until Friday, May 20, 2016, and can be accessed from http://investors.eogresources.com/overview.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
Media | |
K Leonard | |
(713) 571-3870 |
Logo - http://photos.prnewswire.com/prnh/20160405/351712LOGO
SOURCE EOG Resources, Inc.
HOUSTON, Feb. 25, 2016 /PRNewswire/ --
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share. This compares to fourth quarter 2014 net income of $444.6 million, or $0.81 per share. For the full year 2015, EOG reported a net loss of $4.5 billion, or $8.29 per share, compared to net income of $2.9 billion, or $5.32 per share, for the full year 2014.
Adjusted non-GAAP net loss for the fourth quarter 2015 was $149.5 million, or $0.27 per share, compared to adjusted non-GAAP net income of $431.9 million, or $0.79 per share, for the same prior year period. Adjusted non-GAAP net income for the full year 2015 was $33.9 million, or $0.06 per share, compared to non-GAAP net income of $2.7 billion, or $4.95 per share, for the full year 2014. Adjusted non-GAAP net income (loss) is calculated by matching realizations to settlement months and making certain other adjustments in order to exclude one-time items. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
Significant reductions in operating expenses were more than offset by lower commodity prices, resulting in decreases to adjusted non-GAAP net income, discretionary cash flow and EBITDAX during the fourth quarter and full year 2015 compared to the same periods in 2014. (Please refer to the attached tables for the reconciliation of non-GAAP measures to GAAP measures.)
"EOG's performance was resilient in 2015 as oil and natural gas prices declined sharply," said William R. "Bill" Thomas, Chairman and Chief Executive Officer. "We achieved significant reductions in our finding and operating costs and substantially increased the size and the quality of our inventory, which further enhances our unique ability to create long-term shareholder value."
Operational Highlights
For the full year 2015, while exploration and development expenditures (excluding acquisitions) decreased 42 percent, U.S. crude oil and condensate production remained flat, and overall total company production decreased just 4 percent compared to 2014. Total worldwide liquids production decreased 2 percent, and total worldwide natural gas production decreased 7 percent versus the prior year.
EOG restrained capital expenditures in the fourth quarter 2015 in response to the lower commodity price environment. Total exploration and development expenditures decreased 56 percent compared to the same prior year period. EOG's U.S. crude oil and condensate production and total overall company production both decreased by 7 percent in the fourth quarter of 2015 compared to the same prior year period.
EOG continued to enhance operating efficiencies and leverage prior investments in infrastructure, resulting in cost reductions across its operations. During the fourth quarter of 2015, lease and well expenses decreased 30 percent and transportation costs decreased 8 percent compared to the same prior year period, both on a per-unit basis. Total general and administrative expenses decreased 17 percent compared to the fourth quarter 2014.
"EOG remained focused on returns and capital discipline in 2015," Thomas said. "Our team raised the bar with record-setting operational achievements, technical advances and organic growth additions. These sustainable improvements uniquely position EOG for long-term success in any commodity price environment."
2016 Capital Plan
EOG's 2016 plan is designed to maximize returns, maintain the strong balance sheet and continue to achieve record-setting cost reduction and productivity gains.
Capital expenditures for 2016 are expected to range from $2.4 to $2.6 billion, including production facilities and gathering, processing and other expenditures, and excluding acquisitions. EOG expects to complete approximately 270 net wells in 2016, compared to 470 net wells in 2015, with total company crude oil production expected to decline only 5 percent versus 2015. This 45 to 50 percent year-over-year reduction to capital expenditures reflects the current commodity price environment and further demonstrates EOG's commitment to maintaining a strong balance sheet with disciplined capital spending.
The company is shifting its focus to premium drilling and completions in 2016. Driven by continued efficiencies, technical advancements and geoscience breakthroughs, the company has identified over 3,200 premium drilling locations capable of delivering solid rates of return at low commodity prices. Premium drilling is a step change to EOG's long-term strategy that will enable it to expand its leadership in investment returns and well performance. The company is now positioned to return to high investment rates of return as oil prices experience even a modest recovery.
"EOG has now identified more than 2 billion barrels of oil equivalent (BnBoe) of estimated net resource potential and a decade of premium drilling inventory that can earn superior returns in a low commodity price environment," Thomas said. "Breakthroughs of this magnitude are unique and will enable EOG to extend its lead as the low-cost U.S. horizontal oil producer. We are confident our organic growth machine will continue to increase both the size and quality of our premium drilling inventory and allow EOG to enjoy a strong competitive advantage in the world oil market."
South Texas Eagle Ford
The South Texas Eagle Ford continues to showcase EOG's technological advances in lateral placement and completion design. During 2015, the company expanded the use of precision lateral targeting and high-density completions across the Eagle Ford. EOG's other plays benefit from these industry-leading breakthroughs by quickly adapting these new technologies to each unique environment.
During the fourth quarter of 2015, the Eagle Ford once again delivered outstanding well performance across the play. In the eastern Eagle Ford in Karnes County, the Lightfoot Unit 5H through 8H four-well pattern had average 30-day initial production rates per well of 2,425 barrels of oil per day (Bopd), 285 barrels per day (Bpd) of natural gas liquids (NGLs) and 1.9 million cubic feet per day (MMcfd) of natural gas. In Gonzales County, the Lepori Unit 4H had 30-day initial production rates of 2,915 Bopd, 370 Bpd of NGLs and 2.4 MMcfd of natural gas. In the western Eagle Ford in McMullen County, the Naylor Jones Unit 31-1H had 30-day initial production rates of 1,780 Bopd, 165 Bpd of NGLs and 1.1 MMcfd of natural gas.
In 2016, EOG plans to complete approximately 150 net wells in the Eagle Ford, compared to 329 net wells completed in 2015.
Delaware Basin
2015 was an important year for EOG in the Delaware Basin where EOG increased its estimated net resource potential by 1.0 BnBoe. With approximately 2.35 BnBoe in total estimated net resource potential, EOG possesses a premier position in the Permian's best horizontal oil basin. EOG made significant advances in the basin in 2015 by expanding its technical understanding and improving returns by increasing well productivity and reducing costs.
In the Delaware Basin Wolfcamp, EOG completed a dozen wells in the fourth quarter 2015 with average 30-day initial production rates per well of 1,495 Bopd, 300 Bpd of NGLs and 2.5 MMcfd of natural gas.
EOG's 2016 plans for the Delaware Basin include completing approximately 75 net wells versus 74 net wells completed in 2015.
North Dakota Bakken and Rockies
EOG continues to advance its high-potential Rockies oil plays. In 2015, EOG added 600 million barrels of oil equivalent (MMBoe) to its Bakken net resource potential estimate, bringing EOG's total net resource potential estimate to approximately 1.0 BnBoe. EOG has decades of drilling inventory in this world-class oil basin.
During 2015, EOG continued to delineate its Powder River Basin and DJ Basin oil plays. In the fourth quarter 2015, EOG completed several wells in the Powder River Basin Turner oil play. The Blade 202-2116H and the Flatbow 602-1621H had 30-day initial production rates of 1,300 Bopd, 120 Bpd of NGLs and 1.4 MMcfd of natural gas, and 1,280 Bopd, 145 Bpd of NGLs and 1.7 MMcfd of natural gas, respectively.
In 2016, EOG plans to complete approximately 35 net wells in these plays, compared to 48 net wells in 2015.
Reserves
At year-end, total company net proved reserves were 2,118 MMBoe, comprised of 52 percent crude oil and condensate, 18 percent NGLs and 30 percent natural gas. Net proved reserve additions, excluding revisions due to price, replaced 192 percent of EOG's 2015 production at a finding and development cost of $11.91 per barrel of oil equivalent. Revisions due to price reduced net proved reserves by 574 MMBoe. Driven by declines in commodity prices, total company net proved reserves decreased 15 percent in 2015. (For more reserves detail, including calculation of reserve replacement ratios and reserve replacement costs, please refer to the attached tables.)
For the 28th consecutive year, internal reserve estimates were within 5 percent of estimates independently prepared by DeGolyer and MacNaughton.
Hedging Activity
For the period March 1 through August 31, 2016, EOG has natural gas financial price swap contracts in place for 60,000 million British thermal units (MMBtu) per day at a weighted average price of $2.49 per MMBtu. EOG has no crude oil financial price contracts in place. A comprehensive summary of natural gas derivative contracts is provided in the attached tables.
Capital Structure
At December 31, 2015, EOG's total debt outstanding was $6.7 billion with a debt-to-total capitalization ratio of 34 percent. Taking into account cash on the balance sheet of $719 million at year-end, EOG's net debt was $5.9 billion with a net debt-to-total capitalization ratio of 31 percent. A reconciliation of non-GAAP measures to GAAP measures is provided in the attached tables.
Dividend
The board of directors declared a dividend of $0.1675 per share on EOG's Common Stock, payable April 29, 2016, to stockholders of record as of April 15, 2016. The indicated annual rate is $0.67 per share.
Conference Call February 26, 2016
EOG's fourth quarter 2015 results conference call will be available via live audio webcast at 9 a.m. Central time (10 a.m. Eastern time) on Friday, February 26, 2016. To listen, log on to www.eogresources.com. The webcast will be archived on EOG's website through March 11, 2016.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, returns, budgets, reserves, levels of production and costs, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "goal," "may," "will," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, reduce or otherwise control operating and capital costs, generate income or cash flows or pay dividends are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur, and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration and extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only "proved" reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also "probable" reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as "possible" reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include "potential" reserves and/or other estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2015, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov. In addition, reconciliation and calculation schedules for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
Investors
Cedric W. Burgher
(713) 571-4658
David J. Streit
(713) 571-4902
Kimberly M. Ehmer
(713) 571-4676
Media
K Leonard
(713) 571-3870
EOG RESOURCES, INC. | |||||||||||
Financial Report | |||||||||||
(Unaudited; in millions, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2014 |
2015 |
2014 | ||||||||
Net Operating Revenues |
$ |
1,796.8 |
$ |
4,645.5 |
$ |
8,757.4 |
$ |
18,035.3 | |||
Net Income (Loss) |
$ |
(284.3) |
$ |
444.6 |
$ |
(4,524.5) |
$ |
2,915.5 | |||
Net Income (Loss) Per Share |
|||||||||||
Basic |
$ |
(0.52) |
$ |
0.82 |
$ |
(8.29) |
$ |
5.36 | |||
Diluted |
$ |
(0.52) |
$ |
0.81 |
$ |
(8.29) |
$ |
5.32 | |||
Average Number of Common Shares |
|||||||||||
Basic |
546.4 |
544.6 |
545.7 |
543.4 | |||||||
Diluted |
546.4 |
549.2 |
545.7 |
548.5 | |||||||
Summary Income Statements | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2014 |
2015 |
2014 | ||||||||
Net Operating Revenues |
|||||||||||
Crude Oil and Condensate |
$ |
1,040,470 |
$ |
2,054,901 |
$ |
4,934,562 |
$ |
9,742,480 | |||
Natural Gas Liquids |
96,521 |
180,916 |
407,658 |
934,051 | |||||||
Natural Gas |
217,381 |
407,494 |
1,061,038 |
1,916,386 | |||||||
Gains on Mark-to-Market Commodity |
4,970 |
750,154 |
61,924 |
834,273 | |||||||
Gathering, Processing and Marketing |
432,292 |
806,177 |
2,253,135 |
4,046,316 | |||||||
Gains (Losses) on Asset Dispositions, Net |
(3,656) |
431,890 |
(8,798) |
507,590 | |||||||
Other, Net |
8,783 |
13,965 |
47,909 |
54,244 | |||||||
Total |
1,796,761 |
4,645,497 |
8,757,428 |
18,035,340 | |||||||
Operating Expenses |
|||||||||||
Lease and Well |
247,916 |
380,781 |
1,182,282 |
1,416,413 | |||||||
Transportation Costs |
207,580 |
242,293 |
849,319 |
972,176 | |||||||
Gathering and Processing Costs |
39,653 |
37,785 |
146,156 |
145,800 | |||||||
Exploration Costs |
34,946 |
45,167 |
149,494 |
184,388 | |||||||
Dry Hole Costs |
429 |
18,225 |
14,746 |
48,490 | |||||||
Impairments |
168,171 |
535,637 |
6,613,546 |
743,575 | |||||||
Marketing Costs |
461,848 |
862,589 |
2,385,982 |
4,126,060 | |||||||
Depreciation, Depletion and Amortization |
769,457 |
1,013,930 |
3,313,644 |
3,997,041 | |||||||
General and Administrative |
109,014 |
131,285 |
366,594 |
402,010 | |||||||
Taxes Other Than Income |
87,500 |
151,153 |
421,744 |
757,564 | |||||||
Total |
2,126,514 |
3,418,845 |
15,443,507 |
12,793,517 | |||||||
Operating Income (Loss) |
(329,753) |
1,226,652 |
(6,686,079) |
5,241,823 | |||||||
Other Income (Expense), Net |
(6,080) |
(28,324) |
1,916 |
(45,050) | |||||||
Income (Loss) Before Interest Expense and Income Taxes |
(335,833) |
1,198,328 |
(6,684,163) |
5,196,773 | |||||||
Interest Expense, Net |
62,993 |
49,735 |
237,393 |
201,458 | |||||||
Income (Loss) Before Income Taxes |
(398,826) |
1,148,593 |
(6,921,556) |
4,995,315 | |||||||
Income Tax Provision (Benefit) |
(114,530) |
704,005 |
(2,397,041) |
2,079,828 | |||||||
Net Income (Loss) |
$ |
(284,296) |
$ |
444,588 |
$ |
(4,524,515) |
$ |
2,915,487 | |||
Dividends Declared per Common Share |
$ |
0.1675 |
$ |
0.1675 |
$ |
0.6700 |
$ |
0.5850 | |||
EOG RESOURCES, INC. | |||||||||||
Operating Highlights | |||||||||||
(Unaudited) | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2014 |
2015 |
2014 | ||||||||
Wellhead Volumes and Prices |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) (A) |
|||||||||||
United States |
279.9 |
301.5 |
283.3 |
282.0 | |||||||
Trinidad |
0.9 |
0.9 |
0.9 |
1.0 | |||||||
Other International (B) |
0.2 |
5.3 |
0.2 |
5.9 | |||||||
Total |
281.0 |
307.7 |
284.4 |
288.9 | |||||||
Average Crude Oil and Condensate Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
40.34 |
$ |
72.76 |
$ |
47.55 |
$ |
92.73 | |||
Trinidad |
32.38 |
63.65 |
39.51 |
84.63 | |||||||
Other International (B) |
53.28 |
72.91 |
57.32 |
86.75 | |||||||
Composite |
40.32 |
72.74 |
47.53 |
92.58 | |||||||
Natural Gas Liquids Volumes (MBbld) (A) |
|||||||||||
United States |
79.1 |
83.1 |
76.9 |
79.7 | |||||||
Other International (B) |
- |
0.5 |
0.1 |
0.6 | |||||||
Total |
79.1 |
83.6 |
77.0 |
80.3 | |||||||
Average Natural Gas Liquids Prices ($/Bbl) (C) |
|||||||||||
United States |
$ |
13.25 |
$ |
23.48 |
$ |
14.50 |
$ |
31.84 | |||
Other International (B) |
- |
31.42 |
4.61 |
40.73 | |||||||
Composite |
13.25 |
23.53 |
14.49 |
31.91 | |||||||
Natural Gas Volumes (MMcfd) (A) |
|||||||||||
United States |
860 |
921 |
886 |
920 | |||||||
Trinidad |
370 |
329 |
349 |
363 | |||||||
Other International (B) |
27 |
60 |
30 |
70 | |||||||
Total |
1,257 |
1,310 |
1,265 |
1,353 | |||||||
Average Natural Gas Prices ($/Mcf) (C) |
|||||||||||
United States |
$ |
1.44 |
$ |
3.21 |
$ |
1.97 |
$ |
3.93 | |||
Trinidad |
2.57 |
3.77 |
2.89 |
3.65 | |||||||
Other International (B) |
6.51 |
3.85 |
5.05 |
4.40 | |||||||
Composite |
1.88 |
3.38 |
2.30 |
3.88 | |||||||
Crude Oil Equivalent Volumes (MBoed) (D) |
|||||||||||
United States |
502.2 |
538.3 |
507.9 |
515.0 | |||||||
Trinidad |
62.7 |
55.7 |
59.1 |
61.5 | |||||||
Other International (B) |
4.6 |
15.6 |
5.2 |
18.2 | |||||||
Total |
569.5 |
609.6 |
572.2 |
594.7 | |||||||
Total MMBoe (D) |
52.4 |
56.1 |
208.9 |
217.1 |
(A) Thousand barrels per day or million cubic feet per day, as applicable. | |||||||||||
(B) Other International includes EOG's United Kingdom, China, Canada and Argentina operations. | |||||||||||
(C) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments. | |||||||||||
(D) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, natural gas liquids and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or natural gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
EOG RESOURCES, INC. | |||||
Summary Balance Sheets | |||||
(Unaudited; in thousands, except share data) | |||||
December 31, |
December 31, | ||||
2015 |
2014 | ||||
ASSETS | |||||
Current Assets |
|||||
Cash and Cash Equivalents |
$ |
718,506 |
$ |
2,087,213 | |
Accounts Receivable, Net |
930,610 |
1,779,311 | |||
Inventories |
598,935 |
706,597 | |||
Assets from Price Risk Management Activities |
- |
465,128 | |||
Income Taxes Receivable |
40,704 |
71,621 | |||
Deferred Income Taxes |
147,812 |
19,618 | |||
Other |
155,677 |
286,533 | |||
Total |
2,592,244 |
5,416,021 | |||
Property, Plant and Equipment |
|||||
Oil and Gas Properties (Successful Efforts Method) |
50,613,241 |
46,503,532 | |||
Other Property, Plant and Equipment |
3,986,610 |
3,750,958 | |||
Total Property, Plant and Equipment |
54,599,851 |
50,254,490 | |||
Less: Accumulated Depreciation, Depletion and Amortization |
(30,389,130) |
(21,081,846) | |||
Total Property, Plant and Equipment, Net |
24,210,721 |
29,172,644 | |||
Other Assets |
172,279 |
174,022 | |||
Total Assets |
$ |
26,975,244 |
$ |
34,762,687 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current Liabilities |
|||||
Accounts Payable |
$ |
1,471,953 |
$ |
2,860,548 | |
Accrued Taxes Payable |
93,618 |
140,098 | |||
Dividends Payable |
91,546 |
91,594 | |||
Deferred Income Taxes |
- |
110,743 | |||
Current Portion of Long-Term Debt |
6,579 |
6,579 | |||
Other |
155,591 |
174,746 | |||
Total |
1,819,287 |
3,384,308 | |||
Long-Term Debt |
6,653,685 |
5,903,354 | |||
Other Liabilities |
971,335 |
939,497 | |||
Deferred Income Taxes |
4,587,902 |
6,822,946 | |||
Commitments and Contingencies |
|||||
Stockholders' Equity |
|||||
Common Stock, $0.01 Par, 640,000,000 Shares Authorized and |
205,502 |
205,492 | |||
Additional Paid in Capital |
2,923,461 |
2,837,150 | |||
Accumulated Other Comprehensive Loss |
(33,338) |
(23,056) | |||
Retained Earnings |
9,870,816 |
14,763,098 | |||
Common Stock Held in Treasury, 292,179 Shares and 733,517 Shares at |
(23,406) |
(70,102) | |||
Total Stockholders' Equity |
12,943,035 |
17,712,582 | |||
Total Liabilities and Stockholders' Equity |
$ |
26,975,244 |
$ |
34,762,687 | |
EOG RESOURCES, INC. | |||||
Summary Statements of Cash Flows | |||||
(Unaudited; in thousands) | |||||
Twelve Months Ended | |||||
December 31, | |||||
2015 |
2014 | ||||
Cash Flows from Operating Activities |
|||||
Reconciliation of Net Income (Loss) to Net Cash Provided by Operating Activities: |
|||||
Net Income (Loss) |
$ |
(4,524,515) |
$ |
2,915,487 | |
Items Not Requiring (Providing) Cash |
|||||
Depreciation, Depletion and Amortization |
3,313,644 |
3,997,041 | |||
Impairments |
6,613,546 |
743,575 | |||
Stock-Based Compensation Expenses |
130,577 |
145,086 | |||
Deferred Income Taxes |
(2,482,307) |
1,704,946 | |||
(Gains) Losses on Asset Dispositions, Net |
8,798 |
(507,590) | |||
Other, Net |
11,896 |
48,138 | |||
Dry Hole Costs |
14,746 |
48,490 | |||
Mark-to-Market Commodity Derivative Contracts |
|||||
Total Gains |
(61,924) |
(834,273) | |||
Net Cash Received from Settlements of Commodity Derivative Contracts |
730,114 |
34,007 | |||
Excess Tax Benefits from Stock-Based Compensation |
(26,058) |
(99,459) | |||
Other, Net |
12,532 |
13,009 | |||
Changes in Components of Working Capital and Other Assets and Liabilities |
|||||
Accounts Receivable |
641,412 |
84,982 | |||
Inventories |
58,450 |
(161,958) | |||
Accounts Payable |
(1,409,197) |
543,630 | |||
Accrued Taxes Payable |
11,798 |
16,486 | |||
Other Assets |
118,143 |
(14,448) | |||
Other Liabilities |
(66,257) |
75,420 | |||
Changes in Components of Working Capital Associated with Investing and Financing |
499,767 |
(103,414) | |||
Net Cash Provided by Operating Activities |
3,595,165 |
8,649,155 | |||
Investing Cash Flows |
|||||
Additions to Oil and Gas Properties |
(4,725,150) |
(7,519,667) | |||
Additions to Other Property, Plant and Equipment |
(288,013) |
(727,138) | |||
Proceeds from Sales of Assets |
192,807 |
569,332 | |||
Changes in Restricted Cash |
- |
60,385 | |||
Changes in Components of Working Capital Associated with Investing Activities |
(499,900) |
103,523 | |||
Net Cash Used in Investing Activities |
(5,320,256) |
(7,513,565) | |||
Financing Cash Flows |
|||||
Net Commercial Paper Borrowings |
259,718 |
- | |||
Long-Term Debt Borrowings |
990,225 |
496,220 | |||
Long-Term Debt Repayments |
(500,000) |
(500,000) | |||
Settlement of Foreign Currency Swap |
- |
(31,573) | |||
Dividends Paid |
(367,005) |
(279,695) | |||
Excess Tax Benefits from Stock-Based Compensation |
26,058 |
99,459 | |||
Treasury Stock Purchased |
(48,791) |
(127,424) | |||
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
22,690 |
22,249 | |||
Debt Issuance Costs |
(5,951) |
(895) | |||
Repayment of Capital Lease Obligation |
(6,156) |
(5,966) | |||
Other, Net |
133 |
(109) | |||
Net Cash Provided by (Used in) Financing Activities |
370,921 |
(327,734) | |||
Effect of Exchange Rate Changes on Cash |
(14,537) |
(38,852) | |||
Increase (Decrease) in Cash and Cash Equivalents |
(1,368,707) |
769,004 | |||
Cash and Cash Equivalents at Beginning of Period |
2,087,213 |
1,318,209 | |||
Cash and Cash Equivalents at End of Period |
$ |
718,506 |
$ |
2,087,213 |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Net Income (Loss) (Non-GAAP) | |||||||||||
to Net Income (Loss) (GAAP) | |||||||||||
(Unaudited; in thousands, except per share data) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2015 and 2014 reported Net Income (Loss) (GAAP) to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market gains from these transactions, to eliminate the net (gains) losses on asset dispositions, to eliminate the impact of the Texas margin tax rate reduction in 2015, to add back impairment charges related to certain of EOG's assets, to add back an early leasehold termination payment as the result of a legal settlement in 2015, to add back severance costs associated with EOG's North American operations in 2015 and to add back the tax expense related to the anticipated repatriation of accumulated foreign earnings in future years in 2014. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2014 |
2015 |
2014 | ||||||||
Reported Net Income (Loss) (GAAP) |
$ |
(284,296) |
$ |
444,588 |
$ |
(4,524,515) |
$ |
2,915,487 | |||
Commodity Derivative Contracts Impact |
|||||||||||
Gains on Mark-to-Market Commodity Derivative Contracts |
(4,970) |
(750,154) |
(61,924) |
(834,273) | |||||||
Net Cash Received from Settlements of Commodity |
69,093 |
222,944 |
730,114 |
34,007 | |||||||
Subtotal |
64,123 |
(527,210) |
668,190 |
(800,266) | |||||||
After-Tax MTM Impact |
41,263 |
(339,792) |
429,980 |
(514,971) | |||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax |
2,921 |
(439,834) |
4,615 |
(487,260) | |||||||
Less: Texas Margin Tax Rate Reduction |
- |
- |
(19,500) |
- | |||||||
Add: Impairments of Certain Assets, Net of Tax |
78,149 |
517,041 |
4,125,372 |
553,099 | |||||||
Add: Legal Settlement - Early Leasehold Termination, Net of Tax |
12,455 |
- |
12,455 |
- | |||||||
Add: Severance Costs, Net of Tax |
- |
- |
5,473 |
- | |||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
|||||||||||
Foreign Earnings in Future Years |
- |
249,861 |
- |
249,861 | |||||||
Adjusted Net Income (Loss) (Non-GAAP) |
$ |
(149,508) |
$ |
431,864 |
$ |
33,880 |
$ |
2,716,216 | |||
Net Income (Loss) Per Share (GAAP) |
|||||||||||
Basic |
$ |
(0.52) |
$ |
0.82 |
$ |
(8.29) |
$ |
5.36 | |||
Diluted |
$ |
(0.52) |
$ |
0.81 |
$ |
(8.29) |
$ |
5.32 | |||
Adjusted Net Income (Loss) Per Share (Non-GAAP) |
|||||||||||
Basic |
$ |
(0.27) |
$ |
0.79 |
$ |
0.06 |
$ |
5.00 | |||
Diluted |
$ |
(0.27) |
$ |
0.79 |
$ |
0.06 |
$ |
4.95 | |||
Adjusted Net Income (Loss) Per Diluted Share (Non-GAAP) - |
-134 |
% |
-99 |
% |
|||||||
Average Number of Common Shares (GAAP) |
|||||||||||
Basic |
546,432 |
544,579 |
545,697 |
543,443 | |||||||
Diluted |
546,432 |
549,153 |
545,697 |
548,539 | |||||||
Average Number of Common Shares (Non-GAAP) |
|||||||||||
Basic |
546,432 |
544,579 |
545,697 |
543,443 | |||||||
Diluted |
546,432 |
549,153 |
549,610 |
548,539 |
EOG RESOURCES, INC. | ||||||||||||
Quantitative Reconciliation of Discretionary Cash Flow (Non-GAAP) | ||||||||||||
to Net Cash Provided By Operating Activities (GAAP) | ||||||||||||
(Unaudited; in thousands) | ||||||||||||
The following chart reconciles the three-month and twelve-month periods ended December 31, 2015 and 2014 Net Cash Provided by Operating Activities (GAAP) to Discretionary Cash Flow (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Exploration Costs (excluding Stock-Based Compensation Expenses), Excess Tax Benefits from Stock-Based Compensation, Changes in Components of Working Capital and Other Assets and Liabilities, and Changes in Components of Working Capital Associated with Investing and Financing Activities. EOG management uses this information for comparative purposes within the industry. | ||||||||||||
Three Months Ended |
Twelve Months Ended | |||||||||||
December 31, |
December 31, | |||||||||||
2015 |
2014 |
2015 |
2014 | |||||||||
Net Cash Provided by Operating Activities (GAAP) |
$ |
615,813 |
$ |
2,110,438 |
$ |
3,595,165 |
$ |
8,649,155 | ||||
Adjustments: |
||||||||||||
Exploration Costs (excluding Stock-Based Compensation Expenses) |
28,758 |
38,450 |
124,011 |
157,453 | ||||||||
Excess Tax Benefits from Stock-Based Compensation |
1,839 |
11,632 |
26,058 |
99,459 | ||||||||
Changes in Components of Working Capital and Other Assets |
||||||||||||
and Liabilities |
||||||||||||
Accounts Receivable |
(193,101) |
(426,025) |
(641,412) |
(84,982) | ||||||||
Inventories |
(31,443) |
42,792 |
(58,450) |
161,958 | ||||||||
Accounts Payable |
98,986 |
23,123 |
1,409,197 |
(543,630) | ||||||||
Accrued Taxes Payable |
65,777 |
159,926 |
(11,798) |
(16,486) | ||||||||
Other Assets |
28,822 |
(47,518) |
(118,143) |
14,448 | ||||||||
Other Liabilities |
50,574 |
(8,802) |
66,257 |
(75,420) | ||||||||
Changes in Components of Working Capital Associated with |
||||||||||||
Investing and Financing Activities |
19,436 |
(5,154) |
(499,767) |
103,414 | ||||||||
Discretionary Cash Flow (Non-GAAP) |
$ |
685,461 |
$ |
1,898,862 |
$ |
3,891,118 |
$ |
8,465,369 | ||||
Discretionary Cash Flow (Non-GAAP) - Percentage Decrease |
-64 |
% |
-54 |
% |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of Adjusted Earnings Before Interest Expense, | |||||||||||
Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, | |||||||||||
Dry Hole Costs, Impairments and Additional Items (Adjusted EBITDAX) | |||||||||||
(Non-GAAP) to Income (Loss) Before Interest Expense and Income Taxes (GAAP) | |||||||||||
(Unaudited; in thousands) | |||||||||||
The following chart adjusts the three-month and twelve-month periods ended December 31, 2015 and 2014 reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to Earnings Before Interest Expense, Income Taxes, Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments (EBITDAX) (Non-GAAP) and further adjusts such amount to reflect actual net cash received from settlements of commodity derivative contracts by eliminating the unrealized mark-to-market (MTM) gains from these transactions and to eliminate the net (gains) losses on asset dispositions. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported Income (Loss) Before Interest Expense and Income Taxes (GAAP) to add back Depreciation, Depletion and Amortization, Exploration Costs, Dry Hole Costs and Impairments and further adjust such amount to match realizations to production settlement months and make certain other adjustments to exclude non-recurring items. EOG management uses this information for comparative purposes within the industry. | |||||||||||
Three Months Ended |
Twelve Months Ended | ||||||||||
December 31, |
December 31, | ||||||||||
2015 |
2014 |
2015 |
2014 | ||||||||
Income (Loss) Before Interest Expense and Income Taxes (GAAP) |
$ |
(335,833) |
$ |
1,198,328 |
$ |
(6,684,163) |
$ |
5,196,773 | |||
Adjustments: |
|||||||||||
Depreciation, Depletion and Amortization |
769,457 |
1,013,930 |
3,313,644 |
3,997,041 | |||||||
Exploration Costs |
34,946 |
45,167 |
149,494 |
184,388 | |||||||
Dry Hole Costs |
429 |
18,225 |
14,746 |
48,490 | |||||||
Impairments |
168,171 |
535,637 |
6,613,546 |
743,575 | |||||||
EBITDAX (Non-GAAP) |
637,170 |
2,811,287 |
3,407,267 |
10,170,267 | |||||||
Total Gains on MTM Commodity Derivative Contracts |
(4,970) |
(750,154) |
(61,924) |
(834,273) | |||||||
Net Cash Received from Settlements of Commodity |
69,093 |
222,944 |
730,114 |
34,007 | |||||||
(Gains) Losses on Asset Dispositions, Net |
3,656 |
(431,890) |
8,798 |
(507,590) | |||||||
Adjusted EBITDAX (Non-GAAP) |
$ |
704,949 |
$ |
1,852,187 |
$ |
4,084,255 |
$ |
8,862,411 | |||
Adjusted EBITDAX (Non-GAAP) - Percentage Decrease |
-62 |
% |
-54 |
% |
EOG RESOURCES, INC. |
Quantitative Reconciliation of Net Debt (Non-GAAP) and Total |
Capitalization (Non-GAAP) as Used in the Calculation of |
the Net Debt-to-Total Capitalization Ratio (Non-GAAP) to |
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) |
(Unaudited; in millions, except ratio data) |
The following chart reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. |
At |
At |
|||||
December 31, |
December 31, |
|||||
2015 |
2014 |
|||||
Total Stockholders' Equity - (a) |
$ |
12,943 |
$ |
17,713 |
||
Current and Long-Term Debt (GAAP) - (b) |
6,660 |
5,910 |
||||
Less: Cash |
(719) |
(2,087) |
||||
Net Debt (Non-GAAP) - (c) |
5,941 |
3,823 |
||||
Total Capitalization (GAAP) - (a) + (b) |
$ |
19,603 |
$ |
23,623 |
||
Total Capitalization (Non-GAAP) - (a) + (c) |
$ |
18,884 |
$ |
21,536 |
||
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] |
34 |
% |
25 |
% | ||
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] |
31 |
% |
18 |
% |
EOG RESOURCES, INC. | ||||||||
Reserves Supplemental Data | ||||||||
(Unaudited) | ||||||||
2015 NET PROVED RESERVES RECONCILIATION SUMMARY |
||||||||
United |
Other |
|||||||
States |
Trinidad |
Int'l |
Total |
|||||
CRUDE OIL & CONDENSATE (MMBbl) |
||||||||
Beginning Reserves |
1,129.8 |
1.3 |
8.7 |
1,139.8 |
||||
Revisions |
(115.0) |
- |
- |
(115.0) |
||||
Purchases in place |
35.9 |
- |
- |
35.9 |
||||
Extensions, discoveries and other additions |
141.3 |
0.1 |
- |
141.4 |
||||
Sales in place |
(0.7) |
- |
- |
(0.7) |
||||
Production |
(103.4) |
(0.3) |
(0.1) |
(103.8) |
||||
Ending Reserves |
1,087.9 |
1.1 |
8.6 |
1,097.6 |
||||
NATURAL GAS LIQUIDS (MMBbl) |
||||||||
Beginning Reserves |
467.0 |
- |
0.1 |
467.1 |
||||
Revisions |
(113.3) |
- |
0.1 |
(113.2) |
||||
Purchases in place |
8.3 |
- |
- |
8.3 |
||||
Extensions, discoveries and other additions |
49.1 |
- |
- |
49.1 |
||||
Sales in place |
(0.1) |
- |
(0.2) |
(0.3) |
||||
Production |
(28.1) |
- |
- |
(28.1) |
||||
Ending Reserves |
382.9 |
- |
- |
382.9 |
||||
NATURAL GAS (Bcf) |
||||||||
Beginning Reserves |
4,905.5 |
405.6 |
31.5 |
5,342.6 |
||||
Revisions |
(1,453.1) |
16.8 |
5.6 |
(1,430.7) |
||||
Purchases in place |
72.3 |
- |
- |
72.3 |
||||
Extensions, discoveries and other additions |
306.3 |
21.7 |
4.4 |
332.4 |
||||
Sales in place |
(3.9) |
- |
(11.1) |
(15.0) |
||||
Production |
(337.3) |
(127.5) |
(10.9) |
(475.7) |
||||
Ending Reserves |
3,489.8 |
316.6 |
19.5 |
3,825.9 |
||||
OIL EQUIVALENTS (MMBoe) |
||||||||
Beginning Reserves |
2,414.2 |
69.0 |
14.1 |
2,497.3 |
||||
Revisions |
(470.4) |
2.8 |
1.0 |
(466.6) |
||||
Purchases in place |
56.2 |
- |
- |
56.2 |
||||
Extensions, discoveries and other additions |
241.5 |
3.6 |
0.8 |
245.9 |
||||
Sales in place |
(1.5) |
- |
(2.0) |
(3.5) |
||||
Production |
(187.7) |
(21.6) |
(1.9) |
(211.2) |
||||
Ending Reserves |
2,052.3 |
53.8 |
12.0 |
2,118.1 |
||||
Net Proved Developed Reserves (MMBoe) |
||||||||
At December 31, 2014 |
1,275.4 |
67.5 |
5.0 |
1,347.9 |
||||
At December 31, 2015 |
1,018.5 |
50.7 |
3.3 |
1,072.5 |
||||
2015 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ Millions) |
||||||||
United |
Other |
|||||||
States |
Trinidad |
Int'l |
Total |
|||||
Acquisition Cost of Unproved Properties |
$ 133.8 |
$ - |
$ 0.1 |
$ 133.9 |
||||
Exploration Costs |
206.9 |
22.8 |
23.0 |
252.7 |
||||
Development Costs |
3,815.4 |
87.2 |
105.0 |
4,007.6 |
||||
Total Drilling |
4,156.1 |
110.0 |
128.1 |
4,394.2 |
||||
Acquisition Cost of Proved Properties |
480.6 |
- |
- |
480.6 |
||||
Total Exploration & Development Expenditures |
4,636.7 |
110.0 |
128.1 |
4,874.8 |
||||
Gathering, Processing and Other |
287.4 |
0.3 |
0.4 |
288.1 |
||||
Asset Retirement Costs |
32.4 |
15.5 |
5.6 |
53.5 |
||||
Total Expenditures |
4,956.5 |
125.8 |
134.1 |
5,216.4 |
||||
Proceeds from Sales in Place |
(170.9) |
- |
(21.9) |
(192.8) |
||||
Net Expenditures |
$4,785.6 |
$ 125.8 |
$ 112.2 |
$5,023.6 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) * |
||||||||
Total Drilling, Before Revisions |
$ 17.21 |
$ 30.56 |
$160.13 |
$ 17.87 |
||||
All-in Total, Net of Revisions |
$ (26.85) |
$ 17.19 |
$ 71.17 |
$ (29.63) |
||||
All-in Total, Excluding Revisions Due to Price |
$ 11.56 |
$ 17.19 |
$ 71.17 |
$ 11.91 |
||||
RESERVE REPLACEMENT * |
||||||||
Drilling Only |
129 |
% |
17 |
% |
42 |
% |
116 |
% |
All-in Total, Net of Revisions & Dispositions |
-93 |
% |
30 |
% |
-11 |
% |
-80 |
% |
All-in Total, Excluding Revisions Due to Price |
213 |
% |
30 |
% |
-11 |
% |
192 |
% |
All-in Total, Liquids |
4 |
% |
33 |
% |
-100 |
% |
4 |
% |
* See attached reconciliation schedule for calculation methodology |
EOG RESOURCES, INC. | ||||||||
Quantitative Reconciliation of Total Exploration and Development Expenditures | ||||||||
for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP) | ||||||||
as Used in the Calculation of Reserve Replacement Costs ($ / BOE) | ||||||||
to Total Costs Incurred in Exploration and Development Activities (GAAP) | ||||||||
(Unaudited; in millions, except ratio information) | ||||||||
The following chart reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including "Drilling Only" and "All-In", which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three- or five-year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. | ||||||||
United |
Other |
|||||||
States |
Trinidad |
Int'l |
Total |
|||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$4,669.1 |
$ 125.5 |
$ 133.7 |
$4,928.3 |
||||
Less: Asset Retirement Costs |
(32.4) |
(15.5) |
(5.6) |
(53.5) |
||||
Acquisition Cost of Proved Properties |
(480.6) |
- |
- |
(480.6) |
||||
Total Exploration & Development Expenditures for Drilling Only (Non-GAAP) (a) |
$4,156.1 |
$ 110.0 |
$ 128.1 |
$4,394.2 |
||||
Total Costs Incurred in Exploration and Development Activities (GAAP) |
$4,669.1 |
$ 125.5 |
$ 133.7 |
$4,928.3 |
||||
Less: Asset Retirement Costs |
(32.4) |
(15.5) |
(5.6) |
(53.5) |
||||
Total Exploration & Development Expenditures (Non-GAAP) (b) |
$4,636.7 |
$ 110.0 |
$ 128.1 |
$4,874.8 |
||||
Total Expenditures (GAAP) |
$4,956.5 |
$ 125.8 |
$ 134.1 |
$5,216.4 |
||||
Less: Asset Retirement Costs |
(32.4) |
(15.5) |
(5.6) |
(53.5) |
||||
Non-Cash Acquisition Costs of Unproved Properties |
- |
- |
- |
- |
||||
Total Cash Expenditures (Non-GAAP) |
$4,924.1 |
$ 110.3 |
$ 128.5 |
$5,162.9 |
||||
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe) |
||||||||
Revisions due to price (c) |
(573.8) |
- |
- |
(573.8) |
||||
Revisions other than price |
103.4 |
2.8 |
1.0 |
107.2 |
||||
Purchases in place |
56.2 |
- |
- |
56.2 |
||||
Extensions, discoveries and other additions (d) |
241.5 |
3.6 |
0.8 |
245.9 |
||||
Total Proved Reserve Additions (e) |
(172.7) |
6.4 |
1.8 |
(164.5) |
||||
Sales in place |
(1.5) |
- |
(2.0) |
(3.5) |
||||
Net Proved Reserve Additions From All Sources (f) |
(174.2) |
6.4 |
(0.2) |
(168.0) |
||||
Production (g) |
187.7 |
21.6 |
1.9 |
211.2 |
||||
RESERVE REPLACEMENT COSTS ($ / Boe) |
||||||||
Total Drilling, Before Revisions (a / d) |
$ 17.21 |
$ 30.56 |
$160.13 |
$ 17.87 |
||||
All-in Total, Net of Revisions (b / e) |
$ (26.85) |
$ 17.19 |
$ 71.17 |
$ (29.63) |
||||
All-in Total, Excluding Revisions Due to Price (b / (e - c)) |
$ 11.56 |
$ 17.19 |
$ 71.17 |
$ 11.91 |
||||
RESERVE REPLACEMENT |
||||||||
Drilling Only (d / g) |
129 |
% |
17 |
% |
42 |
% |
116 |
% |
All-in Total, Net of Revisions & Dispositions (f / g) |
-93 |
% |
30 |
% |
-11 |
% |
-80 |
% |
All-in Total, Excluding Revisions Due to Price ((f - c) / g) |
213 |
% |
30 |
% |
-11 |
% |
192 |
% |
Net Proved Reserve Additions From All Sources - Liquids (MMBbl) |
||||||||
Revisions |
(228.3) |
- |
0.1 |
(228.2) |
||||
Purchases in place |
44.2 |
- |
- |
44.2 |
||||
Extensions, discoveries and other additions (h) |
190.4 |
0.1 |
- |
190.5 |
||||
Total Proved Reserve Additions |
6.3 |
0.1 |
0.1 |
6.5 |
||||
Sales in place |
(0.8) |
- |
(0.2) |
(1.0) |
||||
Net Proved Reserve Additions From All Sources (i) |
5.5 |
0.1 |
(0.1) |
5.5 |
||||
Production (j) |
131.5 |
0.3 |
0.1 |
131.9 |
||||
RESERVE REPLACEMENT - LIQUIDS |
||||||||
Drilling Only (h / j) |
145 |
% |
33 |
% |
0 |
% |
144 |
% |
All-in Total, Net of Revisions & Dispositions (i / j) |
4 |
% |
33 |
% |
-100 |
% |
4 |
% |
EOG RESOURCES, INC. | |||||
Natural Gas Financial | |||||
Commodity Derivative Contracts | |||||
Presented below is a comprehensive summary of EOG's natural gas derivative contracts at February 25, 2016, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu. EOG accounts for financial commodity derivative contracts using the mark-to-market accounting method. | |||||
Natural Gas Price Swap Contracts | |||||
Weighted | |||||
Volume |
Average Price | ||||
(MMBtud) |
($/MMBtu) | ||||
2016 |
|||||
March 1, 2016 through August 31, 2016 |
60,000 |
$ |
2.49 | ||
$/MMBtu Dollars per million British thermal units |
|||||
MMBtud Million British thermal units per day |
EOG RESOURCES, INC. |
Direct After-Tax Rate of Return (ATROR) |
The calculation of our direct after-tax rate of return (ATROR) with respect to our capital expenditure program for a particular play or well is based on the estimated proved reserves ("net" to EOG's interest) for all wells in such play or such well (as the case may be), the estimated net present value (NPV) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs) and our direct net costs incurred in drilling or acquiring (as the case may be) such wells or well (as the case may be). As such, our direct ATROR with respect to our capital expenditures for a particular play or well cannot be calculated from our consolidated financial statements. |
Direct ATROR |
Based on Cash Flow and Time Value of Money |
- Estimated future commodity prices and operating costs |
- Costs incurred to drill, complete and equip a well, including facilities |
Excludes Indirect Capital |
- Gathering and Processing and other Midstream |
- Land, Seismic, Geological and Geophysical |
Payback ~12 Months on 100% Direct ATROR Wells |
First Five Years ~1/2 Estimated Ultimate Recovery Produced but ~3/4 of NPV Captured |
Return on Equity / Return on Capital Employed |
Based on GAAP Accrual Accounting |
Includes All Indirect Capital and Growth Capital for Infrastructure |
- Eagle Ford, Bakken, Permian Facilities |
- Gathering and Processing |
Includes Legacy Gas Capital and Capital from Mature Wells |
EOG RESOURCES, INC. | |||||||||||
Quantitative Reconciliation of After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income | |||||||||||
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the Calculations of | |||||||||||
Return on Capital Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest Expense (GAAP), | |||||||||||
Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP), Respectively | |||||||||||
(Unaudited; in millions, except ratio data) | |||||||||||
The following chart reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP) to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income (Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization (Non-GAAP), respectively, as used in the Return on Capital Employed (ROCE) and Return on Equity (ROE) calculations. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize After-Tax Net Interest Expense, Adjusted Net Income, Net Debt and Total Capitalization (Non-GAAP) in their ROCE and ROE calculations. EOG management uses this information for comparative purposes within the industry. | |||||||||||
2015 |
2014 |
2013 |
2012 | ||||||||
Return on Capital Employed (ROCE) (Non-GAAP) |
|||||||||||
Net Interest Expense (GAAP) |
$ |
237 |
$ |
201 |
$ |
235 |
|||||
Tax Benefit Imputed (based on 35%) |
(83) |
(70) |
(82) |
||||||||
After-Tax Net Interest Expense (Non-GAAP) - (a) |
$ |
154 |
$ |
131 |
$ |
153 |
|||||
Net Income (Loss) (GAAP) - (b) |
$ |
(4,525) |
$ |
2,915 |
$ |
2,197 |
|||||
Add: After-Tax Mark-to-Market Commodity Derivative Contracts Impact |
430 |
(515) |
182 |
||||||||
Add: Impairments of Certain Assets, Net of Tax |
4,125 |
553 |
4 |
||||||||
Less: Texas Margin Tax Rate Reduction |
(20) |
- |
- |
||||||||
Add: Legal Settlement - Early Leasehold Termination, Net of Tax |
13 |
- |
- |
||||||||
Add: Severance Costs, Net of Tax |
6 |
- |
- |
||||||||
Less: Net (Gains) Losses on Asset Dispositions, Net of Tax |
5 |
(487) |
(137) |
||||||||
Add: Tax Expense Related to the Repatriation of Accumulated |
- |
250 |
- |
||||||||
Adjusted Net Income (Non-GAAP) - (c) |
$ |
34 |
$ |
2,716 |
$ |
2,246 |
|||||
Total Stockholders' Equity - (d) |
$ |
12,943 |
$ |
17,713 |
$ |
15,418 |
$ |
13,285 | |||
Average Total Stockholders' Equity * - (e) |
$ |
15,328 |
$ |
16,566 |
$ |
14,352 |
|||||
Current and Long-Term Debt (GAAP) - (f) |
$ |
6,660 |
$ |
5,910 |
$ |
5,913 |
$ |
6,312 | |||
Less: Cash |
(719) |
(2,087) |
(1,318) |
(876) | |||||||
Net Debt (Non-GAAP) - (g) |
$ |
5,941 |
$ |
3,823 |
$ |
4,595 |
$ |
5,436 | |||
Total Capitalization (GAAP) - (d) + (f) |
$ |
19,603 |
$ |
23,623 |
$ |
21,331 |
$ |
19,597 | |||
Total Capitalization (Non-GAAP) - (d) + (g) |
$ |
18,884 |
$ |
21,536 |
$ |
20,013 |
$ |
18,721 | |||
Average Total Capitalization (Non-GAAP) * - (h) |
$ |
20,210 |
$ |
20,775 |
$ |
19,367 |
|||||
ROCE (GAAP Net Income) - [(a) + (b)] / (h) |
-21.6 |
% |
14.7 |
% |
12.1 |
% |
|||||
ROCE (Non-GAAP Adjusted Net Income) - [(a) + (c)] / (h) |
0.9 |
% |
13.7 |
% |
12.4 |
% |
|||||
Return on Equity (ROE) (Non-GAAP) |
|||||||||||
ROE (GAAP Net Income) - (b) / (e) |
-29.5 |
% |
17.6 |
% |
15.3 |
% |
|||||
ROE (Non-GAAP Adjusted Net Income) - (c) / (e) |
0.2 |
% |
16.4 |
% |
15.6 |
% |
|||||
* Average for the current and immediately preceding year |
EOG RESOURCES, INC. | |||||||||||
First Quarter and Full Year 2016 Forecast and Benchmark Commodity Pricing | |||||||||||
(a) First Quarter and Full Year 2016 Forecast | |||||||||||
The forecast items for the first quarter and full year 2016 set forth below for EOG Resources, Inc. (EOG) are based on current available information and expectations as of the date of the accompanying press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with the accompanying press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. | |||||||||||
(b) Benchmark Commodity Pricing | |||||||||||
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | |||||||||||
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the simple average of the NYMEX settlement prices for the last three trading days of the applicable month. | |||||||||||
Estimated Ranges | |||||||||||
(Unaudited) | |||||||||||
1Q 2016 |
Full Year 2016 | ||||||||||
Daily Production |
|||||||||||
Crude Oil and Condensate Volumes (MBbld) |
|||||||||||
United States |
255.0 |
- |
265.0 |
250.0 |
- |
265.0 | |||||
Trinidad |
0.3 |
- |
0.5 |
0.3 |
- |
0.5 | |||||
Other International |
0.0 |
- |
6.0 |
9.7 |
- |
14.5 | |||||
Total |
255.3 |
- |
271.5 |
260.0 |
- |
280.0 | |||||
Natural Gas Liquids Volumes (MBbld) |
|||||||||||
Total |
71.0 |
- |
79.0 |
70.0 |
- |
80.0 | |||||
Natural Gas Volumes (MMcfd) |
|||||||||||
United States |
795 |
- |
815 |
770 |
- |
800 | |||||
Trinidad |
340 |
- |
360 |
280 |
- |
310 | |||||
Other International |
22 |
- |
28 |
20 |
- |
25 | |||||
Total |
1,157 |
- |
1,203 |
1,070 |
- |
1,135 | |||||
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||
United States |
458.5 |
- |
479.8 |
448.3 |
- |
478.3 | |||||
Trinidad |
57.0 |
- |
60.5 |
47.0 |
- |
52.2 | |||||
Other International |
3.7 |
- |
10.7 |
13.0 |
- |
18.7 | |||||
Total |
519.2 |
- |
551.0 |
508.3 |
- |
549.2 | |||||
Operating Costs |
|||||||||||
Unit Costs ($/Boe) |
|||||||||||
Lease and Well |
$ |
5.25 |
- |
$ |
5.75 |
$ |
5.30 |
- |
$ |
6.10 | |
Transportation Costs |
$ |
3.90 |
- |
$ |
4.50 |
$ |
4.00 |
- |
$ |
4.60 | |
Depreciation, Depletion and Amortization |
$ |
18.55 |
- |
$ |
18.95 |
$ |
17.95 |
- |
$ |
18.55 | |
Expenses ($MM) |
|||||||||||
Exploration, Dry Hole and Impairment |
$ |
100 |
- |
$ |
120 |
$ |
425 |
- |
$ |
475 | |
General and Administrative |
$ |
83 |
- |
$ |
93 |
$ |
335 |
- |
$ |
365 | |
Gathering and Processing |
$ |
35 |
- |
$ |
40 |
$ |
130 |
- |
$ |
150 | |
Capitalized Interest |
$ |
7 |
- |
$ |
9 |
$ |
27 |
- |
$ |
33 | |
Net Interest |
$ |
67 |
- |
$ |
69 |
$ |
275 |
- |
$ |
285 | |
Taxes Other Than Income (% of Wellhead Revenue) |
6.5% |
- |
7.0% |
6.3% |
- |
6.8% | |||||
Income Taxes |
|||||||||||
Effective Rate |
32% |
- |
37% |
32% |
- |
37% | |||||
Current Taxes ($MM) |
$ |
(55) |
- |
$ |
(40) |
$ |
(190) |
- |
$ |
(170) | |
Capital Expenditures (Excluding Acquisitions, $MM) |
|||||||||||
Exploration and Development, Excluding Facilities |
$ |
1,925 |
- |
$ |
2,025 | ||||||
Exploration and Development Facilities |
$ |
350 |
- |
$ |
400 | ||||||
Gathering, Processing and Other |
$ |
125 |
- |
$ |
175 | ||||||
Pricing - (Refer toBenchmark Commodity Pricingin text) |
|||||||||||
Crude Oil and Condensate ($/Bbl) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) WTI |
$ |
(4.00) |
- |
$ |
(2.00) |
$ |
(3.75) |
- |
$ |
(1.75) | |
Trinidad - above (below) WTI |
$ |
(10.50) |
- |
$ |
(9.50) |
$ |
(12.00) |
- |
$ |
(8.00) | |
Natural Gas Liquids |
|||||||||||
Realizations as % of WTI |
31% |
- |
35% |
31% |
- |
35% | |||||
Natural Gas ($/Mcf) |
|||||||||||
Differentials |
|||||||||||
United States - above (below) NYMEX Henry Hub |
$ |
(1.20) |
- |
$ |
(0.50) |
$ |
(1.20) |
- |
$ |
(0.50) | |
Realizations |
|||||||||||
Trinidad |
$ |
2.10 |
- |
$ |
2.90 |
$ |
2.40 |
- |
$ |
2.90 | |
Other International |
$ |
3.00 |
- |
$ |
4.25 |
$ |
3.30 |
- |
$ |
3.90 | |
Definitions |
|||||||||||
$/Bbl U.S. Dollars per barrel |
|||||||||||
$/Boe U.S. Dollars per barrel of oil equivalent |
|||||||||||
$/Mcf U.S. Dollars per thousand cubic feet |
|||||||||||
$MM U.S. Dollars in millions |
|||||||||||
MBbld Thousand barrels per day |
|||||||||||
MBoed Thousand barrels of oil equivalent per day |
|||||||||||
MMcfd Million cubic feet per day |
|||||||||||
NYMEX New York Mercantile Exchange |
|||||||||||
WTI West Texas Intermediate |
SOURCE EOG Resources, Inc.
HOUSTON, Jan. 14, 2016 /PRNewswire/ -- EOG Resources, Inc. (NYSE: EOG) (EOG) will host a conference call to discuss fourth quarter and full year 2015 results on Friday, February 26, 2016, at 9 a.m. Central time (10 a.m. Eastern time). Please visit EOG's website at www.eogresources.com to access a live webcast of the conference call. If you are unable to listen to the live webcast, a replay will be available following the call until Friday, March 11, 2016, and can be accessed from www.eogresources.com.
If you have any questions, please contact Michelle Smith at 713-651-6472.
EOG Resources, Inc. is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States, Canada, Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on the New York Stock Exchange and is traded under the ticker symbol "EOG."
For Further Information Contact: |
Investors |
Cedric W. Burgher | |
(713) 571-4658 | |
David J. Streit | |
(713) 571-4902 | |
Kimberly M. Ehmer | |
(713) 571-4676 | |
Media | |
K Leonard | |
(713) 571-3870 |
SOURCE EOG Resources, Inc.
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