CALGARY, May 16, 2018 /PRNewswire/ - (TSX: PMT) – Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to announce that the nominees listed in the management proxy circular dated April 2, 2018 were elected as directors of Perpetual.  The detailed results of the vote for the election of directors held at its annual meeting of shareholders earlier today in Calgary, Alberta are set out below. 

Election of Directors

On a vote by ballot, each of the following seven nominees proposed by management was elected as a director of Perpetual:

Conference Call and Webcast

The live webcast and presentation from the annual meeting may be replayed at the following link:    https://event.on24.com/wcc/r/1660451/BE0D705418C5D60AC52F5397CB94513A.

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

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SOURCE Perpetual Energy Inc.

CALGARY, May 14, 2018 /PRNewswire/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", or the "Company") is pleased to announce that it has closed the disposition of non-core royalty interests in eastern Alberta for gross proceeds of $10.0 million. The disposed assets were comprised of the 1% gross overriding royalty interest previously retained on 42 net sections (27,722 net acres) of undeveloped oil sands leases in northeast Alberta sold in June 2015 and March 2016. Approximately 5,700 boe of royalty interest reserve volume representing $0.2 million of reserve value was assigned to the royalty lands in the Company's third-party engineering report prepared by McDaniel and Associates Consultants Ltd. ("McDaniel") as at December 31, 2017. The royalty interests sold contributed less than $0.05 million to adjusted funds flow during the first quarter of 2018. The effective date of the transaction is May 1, 2018.

Proceeds from the disposition will be used to reduce the outstanding balance of the Company's reserve-based credit facility. After giving effect to the disposition and the current market value of the Company's Tourmaline Oil Corp. ("TOU") share investment, the Company had available liquidity at March 31, 2018 of approximately $43.2 million.

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

Forward-Looking Information

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, anticipated amounts and allocation of capital spending; statements pertaining to adjusted funds flow levels, statements regarding estimated production and timing thereof; statements pertaining to type curves being exceeded, forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and, in some instances, to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2017 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

Non-GAAP Measures

This news release contains the term "adjusted funds flow" and "available liquidity" which do not have standardized meanings prescribed by GAAP. Management believes that in addition to net income (loss) and net cash flows from operating activities as defined by GAAP, this term is a useful supplemental measure to evaluate operating performance. Users are cautioned however that this measure should not be construed as an alternative to net income (loss) or net cash flows from operating activities determined in accordance with GAAP as an indication of Perpetual's performance and may not be comparable with the calculation of similar measurements by other entities.

For additional reader advisories in regards to non-GAAP financial measures, including Perpetual's method of calculation and reconciliation of these terms to their corresponding GAAP measures, see the section entitled "Non-GAAP Measures" within the Company's MD&A filed on SEDAR.

Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of these items involves a high degree of discretion. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of our operating areas. Expenditures on decommissioning obligations are managed through our capital budgeting process which considers available adjusted funds flow. The Company has also deducted the change in gas over bitumen royalty financing from adjusted funds flow in order to present these payments net of gas over bitumen royalty credits. These payments are indexed to gas over bitumen royalty credits and are recorded as a reduction to the Company's gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with the disposition of the Shallow Gas Properties, which management considers to not be related to cash flow from operating activities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Commencing in the first quarter of 2018, the Company no longer excludes 'exploration and evaluation – geological and geophysical costs' (Q1 2018 and 2017 – nil) from the calculation of adjusted funds flow as these costs are no longer significant to the Company's business. The calculation of adjusted funds flow for comparative periods has been adjusted to give effect to this change. Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating earnings per share. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance with IFRS. Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in a period.

Available Liquidity: Available Liquidity is defined as Perpetual's Credit Facility Borrowing Limit, plus TOU share investment, less borrowings and letters of credit issued under the Credit Facility and TOU share margin loan. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and meet financial obligations.

BOE Equivalents

Perpetual's aggregate proved and probable reserves are reported in barrels of oil equivalent (boe). Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101 a boe conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

The following abbreviations used in this news release have the meanings set forth below:

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SOURCE Perpetual Energy Inc.

CALGARY, May 8, 2018 /PRNewswire/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its first quarter 2018 financial and operating results. A complete copy of Perpetual's unaudited condensed interim consolidated financial statements and related Management Discussion and Analysis ("MD&A") for the three months ended March 31, 2018 can be obtained through the Company's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

FIRST QUARTER 2018 HIGHLIGHTS

• Cash flow from operating activities in the first quarter of 2018 was $11.2 million ($0.19/share) compared to cash flow used in operating activities in the prior year period of $2.3 million. After adjusting for changes in non-cash working capital amounts which are impacted by changes in the timing of collection or payment, cash flow from operating activities increased by 119% over the prior year period.
  
  
• Adjusted funds flow in the first quarter of 2018 was $9.1 million ($0.15/share), up 78% over the prior year period of $5.1 million ($0.09/share) due to increased production and lower cash costs, partially offset by lower revenue per boe. Adjusted funds flow per boe was $7.94/boe in the first quarter of 2018, up 14% over the prior year period.
  
  
• Production averaged 12,742 boe/d in the first quarter of 2018, up 8% over the fourth quarter of 2017 and 56% over the first quarter of 2017 due to the completion and tie-in of the East Edson drilling program during the second half of 2017 and first quarter of 2018.
  
  
• Cash costs were $12.82/boe in the first quarter of 2018, down 31% compared to the prior year period due to diligent cost management combined with the impact of increased production at East Edson on a substantially fixed cost base.
  
  
• Perpetual's exploration and development spending in the first quarter of 2018 totaled $14.8 million. Capital expenditures included drilling 4 (4.0 net) wells, with 1 (1.0 net) horizontal natural gas well at Edson, as well as 3 (3.0 net) horizontal heavy oil wells at Mannville.

Production and Operations

• Spending at East Edson represented 60% of total exploration and development expenditures in the first quarter of 2018. East Edson capital activity included the drilling of one (1.0 net) extended reach horizontal ("ERH") Wilrich horizontal well and frac and tie-in operations of two wells drilled in the fourth quarter of 2017. The two wells that were frac'd and tied-in to production during the first quarter commenced production in February. Frac and tie-in of the one ERH well drilled during the first quarter was deferred to the fourth quarter of 2018 to align high initial production rates with higher anticipated winter natural gas prices.
  
  
• Spending in Eastern Alberta consisted of a three well (3.0 net) multi-lateral horizontal drilling program in the Company's Mannville heavy oil property, one waterflood injector well conversion, one water disposal well conversion and associated facilities. The three oil wells came on production in late March with one infill well producing at type curve expectations and two pool extension wells producing at lower rates than targeted. The disposal facility is working well and the Company expects this to translate into future netback improvements. Pressure response is already apparent from the injector conversion completed in December of 2017, further validating the success of the Mannville waterfloods. Summer drilling plans include the drilling of two (1.3 net) wells, with a third development well planned late in the year if positive pressure response from the new injector continues.
  
  
• First quarter production averaged 12,742 boe/d, up 8% from the fourth quarter of 2017 and 56% from 8,143 boe/d produced in the prior year period, reflecting a 79% increase in natural gas and associated natural gas liquids ("NGL") production at East Edson driven by the 2017 and Q1 2018 capital program. Production at East Edson is expected to decline through the summer months before increasing in the fourth quarter when the well drilled in the first quarter is frac'd and tied-in to production. Heavy oil production at Eastern Alberta was maintained at 2017 first quarter levels as positive waterflood response in several pools restored pressure support and offset production declines. Production increases from wells drilled and tied in were not impactful on the first quarter of 2018 as the wells were brought on production at the end of the quarter.
  
  
• Perpetual's oil and natural gas revenue, before derivatives and marketing contracts, for the three months ended March 31, 2018 of $23.3 million increased 29% from the first quarter of 2017 due to a 56% increase in average daily production, partially offset by lower natural gas prices.
  
  
• Natural gas revenue, before derivatives and marketing contracts, of $15.5 million in the first quarter of 2018 comprised 66% (Q1 2017 - 69%) of total petroleum and natural gas revenue and 86% (Q1 2017 - 83%) of production. Natural gas revenue increased 23% from $12.6 million in 2017 reflecting the impact of the 62% increase in production volumes driven by the 2017 and Q1 2018 East Edson capital program, partially offset by lower AECO natural gas prices. Perpetual's average realized gas price, including derivatives and adjusted for heat content was $2.65/Mcf compared to an AECO Daily Index price of $2.08/Mcf. Perpetual's 35,000 MMBtu/d, five-year term market diversification contract contributed $2.4 million of incremental revenue and increased Perpetual's average realized natural gas price by $0.41/Mcf over the AECO Daily Index price in the quarter. The market diversification contract is priced based on daily index prices at five pricing hubs (Chicago, Malin, Dawn, Michcon and Empress) outside of Alberta that generally track North American NYMEX prices. Commencing April 1, 2018, volumes delivered to the market diversification contract increased to 40,000 MMBtu/d.
  
  
• Oil revenue in the first quarter of $3.5 million represented 15% (Q1 2017 - 19%) of total petroleum and natural gas revenue while oil production was 7% (Q1 2017 - 11%) of total Company production. Perpetual's average realized oil price for the first quarter was $48.31/bbl compared to $31.39/bbl in the first quarter of 2017. Oil revenue was comparable to the same period in 2017 due to similar production levels and WCS average prices, as increases in the WTI US$ benchmark prices were fully offset by the higher WCS differential and a stronger Canadian dollar compared to the prior year period.
  
  
• NGL revenue for the first quarter of 2018 of $4.4 million comprised 19% (Q1 2017 - 12%) of total petroleum and natural gas revenue while NGL production was just 7% (Q1 2017 - 6%) of total Company production. NGL revenue increased by 105% over the prior year period as production increased by 77%, tracking the Company's growth in natural gas production at East Edson, combined with a 16% increase in NGL prices compared to the prior year period, positively correlated to the increase in WTI light oil prices.
  
  
• Royalty expenses for the quarter ended March 31, 2018 were $3.1 million, comparable to the first quarter of 2017, as higher revenue in the current quarter was offset by a decrease in the combined average royalty rate on P&NG revenue from 17.1% in the prior year period to 13.1% in the first quarter of 2018. The decreased royalty rate is primarily due to a lower effective freehold and overriding royalty rate at East Edson, with the East Edson joint venture take-in-kind royalty effectively a fixed volume over the larger production base in the first quarter of 2018.
  
  
• Total production and operating expenses were $4.8 million for the first quarter of 2018, comparable to the prior year period despite the 56% increase in production over the comparable period, primarily from the low-cost East Edson area which averaged $2.05/boe in the first quarter of 2018. The first quarter of 2018 saw higher than average well servicing requirements in the Mannville assets which increased operating costs as well as negatively affected production volumes. Production and operating expenses on a unit-of-production basis were $4.16/boe, a decrease of 34% from the prior year period.
  
  
• Transportation costs in the first quarter of 2018 were $1.4 million, up 42% from the prior year period due to increased production from West Central where transportation costs averaged $1.13/boe compared to $2.10/boe for production from Eastern Alberta. Transportation costs were $1.26/boe in the first quarter, down 9% from the prior year period largely due to a higher percentage of production from West Central properties where pipeline tariffs are less than half of transportation rates in Mannville in Eastern Alberta.
  
  
• Perpetual's operating netback of $14.8 million in the first quarter of 2018 increased 45% from $10.2 million in the comparative period of 2017 driven by higher production. On a unit-of-production basis, operating netbacks per boe decreased 7% to $12.87/boe due to lower realized commodity prices.

Financial Highlights

• Total G&A expense was $2.89/boe in the first quarter of 2018, down 32% from the prior year period due to reductions in office lease costs, staffing levels and diligent expense management, combined with increased production.
  
  
• Total cash interest expense of $2.1 million for the three months ended March 31, 2018 was 11% higher than the prior year period (Q1 2017 – $1.9 million) due to increased debt levels, partially offset by lower interest rates and the initial dividend income of $0.1 million received from the TOU share investment in late March.
  
  
• Net loss for the first quarter of 2018 was $6.5 million ($0.11/share), compared to a net loss of $14.2 million ($0.26/share) in the comparative 2017 period. The improvement from the prior year period reflected stronger operational and capital performance including a 56% increase in production, a 31% reduction in cash costs per boe and a 9% reduction in depletion expense per boe, partially offset by a 19% decrease in realized revenue per boe.
  
  
• At March 31, 2018, Perpetual had total net debt of $115.1 million, up $9.1 million from December 31, 2017. The increase reflects the first quarter capital expenditures and lower market value of the TOU share investment, partially offset by the reduction of the net working capital deficiency.
  
  
• As at March 31, 2018, 55% of net debt outstanding was repayable in 2021 or later. Perpetual's net debt to trailing twelve months adjusted funds flow improved slightly during the first quarter of 2018 to 3.3 times at March 31, 2018 (December 31, 2017 – 3.4 times).

2018 OUTLOOK

Perpetual has lowered its 2018 capital expenditure guidance from a range of $23 to 27 million provided in a press release dated February 7, 2018 ("Prior Guidance") to $21 to 25 million ($6 to 10 million for the remainder of 2018) and reduced its Mannville heavy oil drilling in the second half of 2018 to two wells (1.3 net) from the previous range of six to ten wells. At East Edson, one horizontal well drilled in the first quarter will be completed and tied-in during the fourth quarter of 2018 to align high initial production rates with higher expected winter natural gas prices. Additional development drilling is ready to activate if AECO forward prices normalize above $2.00/Mcf. Capital spending plans at Mannville include $1.5 to $2.0 million to capture anticipated banked oil from waterflood operations. Decommissioning expenditures are budgeted to be $1.0 to $1.5 million for the remainder of 2018. Capital spending during the remainder of 2018 will be funded through adjusted funds flow.

Production for 2018 is expected to be 10,500 boe/d to 11,000 boe/d, down from prior guidance of 11,500 boe/d due to lower natural gas production in the first quarter due to freeze offs and shut-ins and lower heavy oil production anticipated over the balance of the year due to reduced capital spending.

For the April through October period, Perpetual has fixed the price on 20,000 GJ/d at $1.74/GJ AECO with the remainder of its production sold at daily index prices at the Chicago, Dawn, Empress, Malin and Michcon markets through its 40,000 MMBtu/d market diversification contract. If AECO prices temporarily weaken, Perpetual's fixed price AECO position provides the ability to shut-in production and purchase gas to deliver against pre-sold commitments while preserving reserves and future deliverability capability.

Cash costs of $14.00 to $15.00/boe are anticipated compared to prior guidance of $13.00 to $14.00/boe, due to the impact of the forecast decrease in production on unit costs. Royalty costs are estimated to be moderately lower for the balance of 2018 than in the first quarter, consistent with lower AECO forward natural gas prices for the remainder of 2018. Other cash costs for the remainder of 2018 are anticipated to be comparable to first quarter expense levels.

Adjusted funds flow for 2018 is forecast to be in the $25 to $28 million range ($16 to $19 million for the remainder of 2018), down from previous guidance of $34 to $37 million due to lower heavy oil production and modestly lower natural gas prices.

Guidance assumptions are as follows:

Commodity price assumptions are consistent with current market price levels as follows:

Year end 2018 net debt (net of the current market value of the Company's TOU share investment of approximately $40 million) is forecast at $105 - $110 million, consistent with prior guidance, based on the following assumptions:

• Net debt at March 31, 2018 of $115 million
• Adjusted funds flow for the remainder of 2018 of $16 to $19 million
• Capital spending for the remainder of 2018 of $6 to $10 million
• Decommissioning expenditures for the remainder of 2018 of $1.0 to $1.5 million
• Shallow gas property disposition – fixed marketing obligation payment of $7.6 million

On May 7, 2018, the revolving bank debt Borrowing Limit was decreased from $65 million to $60 million with the next Borrowing Limit redetermination scheduled on or prior to November 30, 2018. After giving effect to this Borrowing Limit reduction, Perpetual had available liquidity of $29.6 million. To improve liquidity, Perpetual plans to pursue additional asset sales in 2018 including the potential disposition of TOU shares.

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.com.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

Forward-Looking Information

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, anticipated amounts and allocation of capital spending; statements pertaining to adjusted funds flow levels, statements regarding estimated production and timing thereof; statements pertaining to type curves being exceeded, forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and, in some instances, to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2017 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

Non-GAAP Measures

This news release contains the terms "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "available liquidity", "annualized adjusted funds flow", "cash costs", "net working capital deficiency (surplus)", "net debt and net bank debt", "operating netback" and "realized revenue" which do not have standardized meanings prescribed by GAAP. Management believes that in addition to net income (loss) and net cash flows from operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate operating performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from operating activities determined in accordance with GAAP as an indication of Perpetual's performance and may not be comparable with the calculation of similar measurements by other entities.

For additional reader advisories in regards to non-GAAP financial measures, including Perpetual's method of calculation and reconciliation of these terms to their corresponding GAAP measures, see the section entitled "Non-GAAP Measures" within the Company's MD&A filed on SEDAR.

Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of these items involves a high degree of discretion. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of our operating areas. Expenditures on decommissioning obligations are managed through our capital budgeting process which considers available adjusted funds flow. The Company has also deducted the change in gas over bitumen royalty financing from adjusted funds flow in order to present these payments net of gas over bitumen royalty credits. These payments are indexed to gas over bitumen royalty credits and are recorded as a reduction to the Corporation's gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with the disposition of the Shallow Gas Properties, which management considers to not be related to cash flow from operating activities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Commencing in the first quarter of 2018, the Company no longer excludes 'exploration and evaluation – geological and geophysical costs' (Q1 2018 and 2017 – nil) from the calculation of adjusted funds flow as these costs are no longer significant to the Company's business. The calculation of adjusted funds flow for comparative periods has been adjusted to give effect to this change. Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating earnings per share. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance with IFRS. Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in a period.

Available Liquidity: Available Liquidity is defined as Perpetual's Credit Facility Borrowing Limit, plus TOU share investment, less borrowings and letters of credit issued under the Credit Facility and TOU share margin loan. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and meet financial obligations.

Cash costs: Management believes that cash costs assist management and investors in assessing Perpetual's efficiency and overall cost structure. Cash costs are comprised of royalties, production and operating, transportation, general and administrative and cash interest expense and net income. Cash costs per boe is calculated by dividing cash costs by total production sold in a period.

Net debt and net bank debt: Net bank debt is measured as current and long-term bank indebtedness including net working capital deficiency (surplus). Net debt includes the carrying value of net bank debt, the principal amount of the Term Loan, the principal amount of the TOU share margin loan and the principal amount of Senior Notes reduced for the mark-to-market value of the TOU share investment. Net bank debt and net debt are used by management to analyze borrowing capacity.

Net working capital deficiency (surplus): Net working capital deficiency (surplus) includes total current assets and current liabilities excluding short-term derivative assets and liabilities related to the Corporation's risk management activities, current portion of gas over bitumen royalty financing, TOU share investment, TOU share margin loan and current portion of provisions.

Operating netback: Perpetual considers operating netback an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated by deducting royalties, operating costs, and transportation from realized revenue. Operating netback is also calculated on a per boe basis using production sold for the period. Operating netback on a per boe basis can vary significantly for each of the Company's operating areas.

Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue and realized NGL revenue which includes realized gains (losses) on financial natural gas, crude oil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the disposition of the Shallow Gas Properties. Realized revenue, excluding foreign exchange contracts is used by management to calculate the Corporation's net realized commodity prices, taking into account monthly settlements on financial crude oil and natural gas forward sales, collars and basis differentials. These contracts are put in place to protect Perpetual's adjusted funds flow from potential volatility in commodity prices, and as such, any related realized gains or losses are considered part of the Corporation's realized price.

BOE Equivalents

Perpetual's aggregate proved and probable reserves are reported in barrels of oil equivalent (boe). Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101 a boe conversion ratio for natural gas of 6 Mcf: 1 boe has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

The following abbreviations used in this news release have the meanings set forth below:

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SOURCE Perpetual Energy Inc.

CALGARY, Feb. 23, 2018 /PRNewswire/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its fourth quarter and year-end 2017 financial and operating results. A complete copy of Perpetual's audited consolidated financial statements, Management's Discussion and Analysis ("MD&A") and Annual Information Form for the year ended December 31, 2017 will be available through the Corporation's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

The strategic focusing of our asset base, continued diligence to drive down costs, strengthening of our balance sheet, and steady execution of our growth-oriented capital program delivered attractive results in the fourth quarter and year ended December 31, 2017 as highlighted below:

Fourth Quarter 2017

• Adjusted funds flow of $12.5 million ($0.21/share) in the fourth quarter of 2017 was up 277% (250% on a per share basis) over the comparative period in 2016 and 53% over the third quarter of 2017. Cash flow from operations of $11.0 million in the fourth quarter of 2017 ($0.18/share), increased 131% over the prior year period.
  
  
• Proactive natural gas price hedging and optimization strategies and the November 1^st commencement of delivery to the Company's market diversification contracts effectively augmented revenue and insulated Perpetual from the impact of low and volatile natural gas prices in Alberta through much of the fourth quarter. Perpetual's average realized natural gas price in the fourth quarter of $3.22/Mcf increased 34% from fourth quarter of 2016 compared to a 45% decrease year-over-year in the average AECO Daily Index natural gas price.
   
  
• Additional drivers of strong quarterly performance were the combination of production growth of 45% relative to the fourth quarter of 2016, coupled with a 17% reduction in cash costs per boe.
  
  
• Fourth quarter production and operating expenses were $3.45/boe, 24% lower than the fourth quarter of 2016 after adjusting for non-recurring items in the prior period.

Annual 2017

• Exploration and development capital investment of $73 million in 2017 replaced production by 248% at a proved plus probable finding and development ("F&D") cost of $6.16/boe.
   
  
• Perpetual developed over 11.3 MMboe of new proved producing reserves ("PDP") in 2017 at an F&D cost of $6.44/boe, resulting in a 2.2 times PDP recycle ratio relative to operating netback and 1.3 times relative to adjusted funds flow of $8.64/boe.
  
  
• Operating netbacks of $14.35/boe in 2017 were 120% higher than in 2016 ($6.53/boe), driven by the establishment of a sustainable cost structure following the strategic disposition of high cost, high liability shallow gas assets in eastern Alberta (the "Shallow Gas Properties") on October 1, 2016.
  
  
• Adjusted funds flow for 2017 grew thirty-fold to $31.1 million ($0.54/share) compared to $0.9 million ($0.02/share) in 2016.
  
  
• Improving operational performance led to three borrowing base increases to the Company's reserve based revolving bank debt in 2017 and the syndicate was expanded to include three banks.  On November 20, 2017, S&P upgraded Perpetual's credit rating by two rating notches from CCC- to CCC+ with a stable outlook, based on Perpetual's improved liquidity. The Company's year-end 2017 net debt to fourth quarter 2017 annualized adjusted funds flow ratio was 2.1 times.

FOURTH QUARTER 2017 OPERATING AND FINANCIAL HIGHLIGHTS

Capital Spending, Production and Operations

• Exploration and development spending totaled $19.0 million in the fourth quarter, 93% focused on the development of liquids-rich natural gas in West Central Alberta, a significant increase over prior year spending of $7.0 million. Three (3.0 net) horizontal wells were drilled in the Wilrich formation at East Edson, including a second extended reach horizontal ("ERH") well on the same pad as the first ERH well drilled in the third quarter of 2017. The two ERH wells were completed and tied in during the first quarter of 2018. Compression was added at the 100% owned and operated West Wolf Lake 10-3 plant, to align compression and process capacity at the facility, bringing the plant capacity to 65 MMcf/d, and area capacity to 78 MMcf/d, including the 15% working interest capacity held at a third-party operated facility in Rosevear. The facility expansion was completed in December 2017 for $2.1 million, on budget and three months ahead of schedule, to accommodate the accelerated availability of increased firm transportation on TCPL to 78 MMcf/d from April 1, 2018 to December 17, 2017. The fourth quarter 2017 capital program also included expenditures for heavy oil waterflood operations in the Mannville area. In addition, Perpetual spent $0.9 million on abandonment and reclamation projects during the quarter.
  
  
• Fourth quarter average production of 11,765 boe/d (14% oil and natural gas liquids ("NGL")) was 14% higher than the third quarter and 45% higher than Q4 2016, driven by the focused capital program to develop Wilrich reserves, and more than offset the average 500 boe/d of voluntary shut-ins that the Company opportunistically implemented to maximize value. This price optimization strategy was set up by transportation constraints created by pipeline maintenance activities in Alberta during the third quarter and continued into the fourth quarter.
   
  
• Production growth was focused in West Central Alberta deep basin, which comprised 84% of total production, and increased 19% over the third quarter to 9,894 boe/d. The first ERH well at 4-23-51-16W5 represented the highest deliverability well drilled to date by Perpetual at East Edson with a thirty-day average initial productivity ("IP30") of 15.6 MMcf/d of natural gas plus associated liquids based on field estimates, 75% higher than the length-adjusted type curve contained in the 2017 year-end McDaniel reserve report. The second ERH well, which is still under test and not optimized, appears to be below the length-adjusted type curve. The average deliverability of the two wells is anticipated to exceed McDaniel's proven plus probable expectations. West Central production was somewhat constrained by Perpetual's firm transportation capacity during the quarter until December 17, 2017, when Perpetual took early possession of an additional 20 MMcf/d of firm TCPL capacity to bring area firm transportation capacity to 78 MMcf/d, over three months ahead of the original April 1, 2018 contract start-up date.
   
  
• Total production and operating expenses continued to trend downward to $3.45/boe, 1% lower relative to the third quarter. This quarter-over-quarter decrease reflected reduced chemical costs, third party processing fees and water disposal costs at East Edson and lower property taxes at Mannville driven by abandonment and reclamation activity, more than offsetting the $0.9 million ($0.95/boe) of non-recurring adjustments in the third quarter. Operating costs were 133% higher compared to the fourth quarter of 2016, which included $1.8 million ($2.41/boe) of non-recurring adjustments associated with the Shallow Gas Properties. After adjusting for these non-recurring items, production and operating expenses decreased by 24% from $4.56/boe compared to the prior year period due to lower maintenance and repair costs, purchased energy costs, and processing fees combined with increased production. Operating costs per unit-of-production in West Central Alberta averaged $1.72/boe, as production ramped up on a relatively fixed operating base.

Financial Highlights

• Realized revenue for the fourth quarter of 2017 of $25.5 million was up 23% from $20.7 million in the third quarter and up 86% from the prior year period, reflecting strong production growth and effective commodity price management despite volatile natural gas prices. Natural gas revenue represented 67% of total petroleum and natural gas revenue in the quarter, despite reflecting 86% of average production.
  
  
• Perpetual's average realized natural gas price in the fourth quarter of $3.22/Mcf increased by 4% from third quarter prices (34% increase from fourth quarter of 2016) compared to a 16% increase quarter-over-quarter (45% decrease year-over-year) in the average AECO Daily Index for the same periods. Perpetual's average realized natural gas price was 191% of the AECO Daily Index price during the quarter driven by the higher heat content in the Company's natural gas sales volumes, hedging gains, prompt month price optimization strategies as well as the commencement of market diversification contracts on November 1, 2017. The arrangements effectively shift the sales point of 34.1 MMcf/d to a basket of five North American natural gas hub pricing points increasing to 39.0 MMcf/d on April 1, 2018.
  
  
• Realized oil prices during the fourth quarter of $47.30/bbl were up 10% over the third quarter and 21% over the fourth quarter of 2016, reflecting increased WTI pricing combined with a reduced WCS differential compared to the prior year period. Included in Perpetual's average oil price are deductions for quality adjustments, loss allowance, terminal fees and diluent blending fees. Realized NGL prices increased 39% and 15% over the same periods respectively to $54.17/bbl.
   
  
• Cash costs, comprised of royalties, production and operating, transportation, general and administrative and cash finance expenses ("Cash Costs"), decreased by 7% on a unit-of-production basis in the fourth quarter of 2017 compared to the previous quarter to $11.92/boe (down 17% relative to the prior year period), due to diligent cost management and the impact of increased production across the cost base.
  
  
• Cash flow from operating activities for the fourth quarter of 2017 was $11.0 million, up 131% from $4.7 million in the prior year period, primarily due to higher realized commodity prices, cost reductions and a 45% increase in average daily production.
  
  
• Adjusted funds flow reached $12.5 million ($0.21/share) in the fourth quarter, up 53% over third quarter adjusted funds flow of $8.2 million ($0.14/share) and 277% over the comparable period in 2016 (2016 - $3.3 million). Adjusted funds flow per boe was $11.60/boe, an increase of $2.97/boe (34%) from the third quarter of 2017 and $7.14/boe (160%) relative to the fourth quarter of 2016, as improved production, operating performance, cost management and a 29% ($5.26/boe) increase in realized revenue per boe all contributed to improve results compared to the prior year period.
   
  
• The Company recorded a net loss for the fourth quarter of 2017 of $6.5 million, as improved adjusted funds flow was offset by a non-cash loss of $4.3 million related to the change in fair value of the Company's investment of 1.67 million shares of Tourmaline Oil Corp. (TSX - "TOU") and a booked loss on disposition of $3.9 million (Q4 2016 – $19.5 million gain) associated with the sale of the Shallow Gas Properties in both years.
   
  
• Total net debt at December 31, 2017 was $106.0 million, an increase of 14% from September 30, 2017 of $92.7 million. Approximately $62.9 million, representing 59% of net debt, matures in 2021 or later. Revolving bank debt stood at $31.6 million at year-end 2017. In November, Perpetual's credit facility lenders increased the borrowing limit from $40 million to $65 million. The maturity date of the revolving bank debt is May 31, 2019 and the next semi-annual borrowing base review is scheduled for May 31, 2018.

2017 ANNUAL FINANCIAL AND OPERATING HIGHLIGHTS

Capital Spending, Production and Operations

• Perpetual's exploration and development spending in 2017 totaled $73.0 million, a five-fold increase over 2016 capital spending, adding proved plus probable reserves of 8.9 MMboe, equivalent to 248% of 2017 production, at a finding and development ("F&D") cost of $6.16/boe. Approximately 90% of spending was concentrated on the West Central Alberta deep basin assets. Capital expenditures included drilling 19 wells (17.7 net), with 13 (13.0 net) liquids-rich wells at East Edson, one (0.4 net) well in the Brazeau area of West Central Alberta and four (3.3 net) horizontal heavy oil wells and one (1.0 net) shallow horizontal gas well as Mannville. Capital activity in 2017 also included $2.1 million to expand the processing capacity at the owned and operated West Wolf Lake gas plant in East Edson and heavy oil waterflood activities and a shallow gas recompletion program at Mannville. In addition, modest spending was committed to complete phase one of the Company's strategic low pressure electro-thermally assisted drive ("LEAD") pilot project with cyclic heat stimulation ("CHS") testing of the bitumen extraction opportunity in the Bluesky formation at Panny.
   
  
• Net payments on dispositions were $2.0 million in 2017 and included $2.9 million in net payments associated with the retained marketing arrangements related to the sale of the Shallow Gas Properties in 2016, offset by $0.9 million in net proceeds on the sale of undeveloped land and seismic data.
  
  
• Perpetual spent $2.3 million on decommissioning expenditures during 2017 mainly in Eastern Alberta, down from $3.8 million in 2016 as a result of materially reduced obligations with the disposition of the Shallow Gas Properties.
   
  
• Total production for the year ended December 31, 2017 of 9,876 boe/d was 30% lower than 2016 (14,128 boe/d), reflecting the sale of close to 35.5 MMcf/d (5,900 boe/d) of natural gas with the Shallow Gas Property disposition. Perpetual's natural gas production averaged 49.6 MMcf/d in 2017, 87% concentrated at East Edson. NGL production averaged 655 bbl/d (62% condensate), 7% higher than 614 bbl/d (66% condensate) in 2016. Oil production of 948 bbl/d for 2017 was 10% lower than 2016 (1,058 bbl/d).
  
  
• Total production and operating expenses decreased 53% to $16.3 million ($4.52/boe) for 2017 compared to $35.0 million ($6.77/boe) in 2016, reflecting company-wide cost saving initiatives, concentration of operations to the low-cost East Edson area and the full year impact in 2017 of the sale of the high cost Shallow Gas Properties. Operating costs in West Central Alberta averaged $2.68/boe for 2017 compared to $2.93/boe in 2016.
   
  
• Municipal property taxes of $2.2 million continued to represent a significant portion of fixed operating costs at $0.62/boe (14% of total operating costs) for the year ended December 31, 2017, particularly in the Company's remaining Eastern Alberta properties. The calculation of property taxes for machinery and equipment, pipelines and wells is based on a prescribed formula methodology which results in a tax assessment base that is dramatically misrepresentative of the property value for the Company's remaining mature shallow gas assets. As a result, property taxes for shallow gas assets in Eastern Alberta for 2017 were $1.0 million ($2.84/boe), which represented 46% of operating costs for the shallow gas production and 51% of the pre-municipal tax operating netback for these properties.

Financial Highlights

• Realized revenue of $85.0 million in 2017 was 1% lower than 2016 as the 30% decrease in production was offset by a similar increase in Perpetual's average realized commodity prices, inclusive of the Company's hedging, price optimization and market diversification strategies. Realized revenue per boe was $23.59/boe for 2017, up 42% over the prior year (2016 - $16.65/boe), driven by modestly improved benchmark commodity prices combined with the higher value production sales mix and effective natural gas price optimization strategies.
  
  
• AECO Daily Index prices were essentially flat year over year at $2.04/GJ. Perpetual's average realized gas price, including derivatives, and adjusted for heat content increased 45% to $3.51/Mcf for the year ended December 31, 2017 from $2.42/Mcf in 2016. Perpetual's average realized natural gas price in 2017 was 163% of the AECO Daily Index price as a result of positive hedging gains, prompt month price optimization strategies, and the commencement of the Company's market diversification contracts in the fourth quarter as well as the higher heat content of the natural gas sales stream in the East Edson area.
   
  
• Perpetual's realized oil price of $41.62/bbl, including derivatives, increased 11% compared to 2016, due primarily to the 29% increase in Western Canadian Select ("WCS") pricing. The increase in the average WCS price was primarily driven by higher benchmark WTI prices and lower WCS differentials compared to the prior year. Also included in Perpetual's realized oil price were realized losses of $0.8 million ($2.31/bbl) recorded on financial crude oil derivative contracts for the WCS differential and $0.9 million ($2.60/bbl) of losses realized on crystallizations of contracts before maturity.
   
  
• Perpetual's realized average NGL price increased 31% from the prior year to $46.60/bbl, reflecting an increase in all NGL component prices due to an increase in year-over-year pricing for WTI. As well, propane prices increased due to US inventory levels for propane ending the year at the lowest level since 2013 due to increased exports from the United States to Asia and Europe.
   
  
• Royalty expenses for 2017 were $12.0 million ($3.32/boe), up from $9.4 million ($1.82/boe) in 2016 and representing a 26% increase in the effective combined average royalty rate on P&NG revenue to 14.6% from 11.6% in 2016. Average crown royalty rates increased to 2.5% in 2017 compared to 2.1% in 2016, due primarily to higher Alberta natural gas reference prices and increasing oil prices. Freehold and overriding royalty rates increased from 9.5% in 2016 to 12.1% in 2017 as the East Edson joint venture royalty represented a higher percentage of production and revenue following the Shallow Gas Property sale and other production additions in 2017 were subject to overriding royalties.
  
  
• Operating netbacks of $14.35/boe in 2017 were 120% higher than in 2016 ($6.53/boe), driven by higher realized revenue combined with lower production and operating expenses and transportation costs, offset by higher royalties.
   
  
• Cash interest expense in 2017 decreased 46% to $8.0 million (2016 – $14.7 million) due to the full year effect of the exchange during the second quarter of 2016 of $214.4 million principal amount of 8.75% senior notes for 4.4 million TOU shares owned by Perpetual (the "Security Swap") and asset sales in 2016 contributing to a lower opening debt balance, partially offset by capital expenditures that exceeded adjusted funds flow through 2017.
  
  
• Cash Costs, were $53.3 million in 2017, 37% ($30.9 million) lower than 2016. On a unit-of-production basis, Cash Costs of $14.77/boe in 2017 were 10% lower ($1.56/boe) relative to 2016.
  
  
• Cash flow from operating activities was $19.2 million ($0.33/share), compared to negative $7.1 million ($0.14/share) in 2016. Year-over-year improvements in commodity prices combined with significant cost reductions in 2017 more than offset the impact of the 30% decline in average daily production from 2016 to 2017.
  
  
• Adjusted funds flow was $31.1 million or $0.54/share, compared to $0.9 million or $0.02/share in 2016 driven by the establishment of a sustainable cost structure with the strategic disposition of the Shallow Gas Properties in the fourth quarter of 2016.
  
  
• Perpetual recorded a net loss of $36.0 million ($0.62/share) in 2017, compared to net income of $107.1 million ($2.11/share) for 2016. Change in net income was primarily due to the absence of the 2016 $81.3 million gain on exchange of senior notes for TOU share investment, the $81.6 million year-over-year decrease in the change in fair value of TOU share investment and the $36.5 million year-over-year decrease in gains on disposition. Income (loss) from operating activities in 2017, before impairment losses (reversals), restructuring expense and loss (gain) on dispositions was $3.7 million compared to ($32.1 million) in 2016, representing a $35.8 million improvement due to higher realized commodity prices and cost reductions in 2017, and the sale of the Shallow Gas Properties in 2016.
   
  
• The Company's balance sheet was strengthened during 2017 through the execution of a series of financing transactions. The repayment term of $17.9 million of senior notes that previously were scheduled to mature in 2018 and 2019 was extended to 2022 and $27.1 million of senior notes that were scheduled to mature in 2018 were redeemed. Further, the Company issued a $45 million term loan due in 2021 and raised gross proceeds of $9.0 million through the private placement of 5.1 million common shares and 6.5 million warrants. Finally, three borrowing base increases to the Company's reserve based revolving bank debt during 2017 increased total borrowing capacity to $65 million.

2018 OUTLOOK

In response to recent commodity market changes, Perpetual revised its 2018 capital plan to preserve the value of its East Edson natural gas reserves by deferring 2018 development drilling at East Edson and accelerating spending on highly economic heavy oil projects at Mannville, for a net 32% reduction to the 2018 capital budget to $23 to $27 million from $37 million initially set in November 2017. The revised capital plan is expected to result in the drilling of one (1.0 net) ERH liquids-rich natural gas well in 2018 along with three (3.0 net) completion and fracs at East Edson and up to 13 gross (12.3 net) horizontal heavy oil wells in the Mannville area. The resultant investment split is expected to be evenly distributed between the two core operating areas and natural gas and oil commodities.

With the capital re-allocation strategy to heavy oil, first quarter 2018 continues to expect production to average close to 13,300 boe/d. Natural base production declines are anticipated to reverse in the fourth quarter with the planned late third quarter frac of the ERH well to coincide with expected higher seasonal natural gas prices. Perpetual forecasts year-over-year average annual production growth of 17% to approximately 11,500 boe/d for 2018 and anticipates to exit the year at approximately 10,700 boe/d (17% oil and NGL).

Based on the capital spending plan and production assumptions outlined above, and the current forward market for oil and natural gas prices at market pricing points, Perpetual forecasts 2018 adjusted funds flow of $33 to $37 million ($0.56/share to $0.62/share). Further detailed information regarding the Company's 2018 outlook, including adjusted funds flow guidance assumptions and sensitivities, was released on February 7, 2018 and is available in Perpetual's MD&A for the year ended December 31, 2017.

Changes to Board of Directors

Perpetual also announces the retirement of Mr. Randall E. Johnson from its board of directors effective February 22, 2018. Mr. Johnson has been a valued member of the board of directors since his appointment in 2006. Among his other responsibilities, Mr. Johnson served as the Chair of Perpetual's Compensation and Corporate Governance Committee and as a member of the Audit Committee. In addition, he has provided the board and management with insightful guidance gained through his long career in the oil and gas corporate banking industry. Perpetual wishes to acknowledge and thank Mr. Johnson for his many contributions and dedicated service to the Company and shareholders.

Oil and Gas Advisories

The reserves estimates contained in this news release represent gross reserves as at December 31, 2017 as estimated by McDaniel and Associates Consultants Ltd. ("McDaniel") and are defined under National Instrument 51-101 as interest before deduction of royalties and without including any of royalty interests. The recovery and reserves estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein.

To provide a single unit-of-production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe), using the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

This news release contains metrics commonly used in the oil and natural gas industry, such as "F&D" costs and "pre-municipal tax operating netbacks" These oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this news release to provide readers with additional measures to evaluate Perpetual's performance, however, such measures are not reliable indicators of Perpetual's future performance and future performance may not compare to Perpetual's performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders and investors with measures to compare Perpetual's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

F&D costs are calculated on a per boe basis by dividing the aggregate of the change in future development capital ("FDC") from the prior year for the particular reserve category and the costs incurred on development and exploration activities in the year by the change in reserves from the prior year for the reserve category, including reserves revisions during the year on a per boe basis. The aggregate of the F&D costs incurred in the financial year and changes during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year.

F&D recycle ratio is calculated by dividing the operating netback for the period by the F&D costs per boe for the particular reserve category.

Any references in this news release to IP30 rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.

The length-adjusted type curve information included in this news release, including IP 30, represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. This information is based on McDaniel type curves based on a combination of historical performance of older wells and management's expectation of what might be achieved from future wells. The information represents what McDaniel thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells McDaniel expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. There is no certainty that future wells will generate results to match historic type curves presented herein.

Forward-Looking Information

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, anticipated amounts and allocation of capital spending; statements pertaining to adjusted funds flow levels, statements regarding estimated production and timing thereof; statements pertaining to type curves being exceeded, forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2017 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

Financial Outlook

Also included in this news release are estimates of Perpetual's 2018 adjusted funds flow, which is based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and Perpetual's February 7, 2018 news release. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on February 22, 2018 and is included to provide readers with an understanding of Perpetual's anticipated adjusted funds flow and sensitivities based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

Non-GAAP Measures

This news release contains the terms "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "annualized adjusted funds flow", "cash costs", "net working capital deficiency (surplus)", "net debt and net bank debt", "operating netback", "proved developed producing recycle ratio" and "realized revenue" which do not have standardized meanings prescribed by GAAP. Management believes that in addition to net income (loss) and net cash flows from operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate operating performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from operating activities determined in accordance with GAAP as an indication of Perpetual's performance and may not be comparable with the calculation of similar measurements by other entities.

Management uses adjusted funds flow as a key measure to assess the ability of the Company to generate the funds necessary to finance operating activities and capital expenditures. Adjusted funds flow excludes the change in non-cash working capital and expenditures on decommissioning obligations since Perpetual believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such, may not be useful for evaluating Perpetual's operating performance. To make reported adjusted funds flow more comparable to industry practice, the Company reclassifies certain exploration and evaluation costs from operating to investing activities in the adjusted funds flow reconciliation. These exploration and evaluation costs include dry hole costs in addition to geological and geophysical costs, which are expensed in the period incurred. The Company has also reclassified the change in gas over bitumen royalty financing from financing to operating activities in the calculation of adjusted funds flow, in order to present these payments net of gas over bitumen royalty credits. These payments are indexed to gas over bitumen royalty credits and are recorded as a reduction to the Corporation's gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with the disposition of the Shallow Gas Properties, which management considers to not be related to cash flow from operating activities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating earnings per share. "Net debt to fourth quarter 2017 annualized adjusted funds flow ratio" is fourth quarter adjusted funds flow times four to derive an annualized equivalent net debt to adjusted funds flow ratio. Adjusted funds flow is not intended to represent net cash flows from (used in) operating activities calculated in accordance with IFRS.

Cash costs: Management believes that cash costs assist management and investors in assessing Perpetual's efficiency and overall cost structure. Cash costs are comprised of royalties, production and operating, transportation, general and administrative and cash finance expenses.

Net debt and net bank debt: Net bank debt is measured as current and long-term bank indebtedness including net working capital deficiency (surplus). Net debt includes the carrying value of net bank debt, the principal amount of the Term Loan, the principal amount of TOU share margin loans and the principal amount of Senior Notes reduced for the mark-to-market value of the TOU share investment. Net bank debt and net debt are used by management to analyze borrowing capacity.

Net working capital deficiency (surplus): Net working capital deficiency (surplus) includes total current assets and current liabilities excluding short-term derivative assets and liabilities related to the Corporation's risk management activities, current portion of gas over bitumen royalty financing, TOU (described below) share investment, TOU share margin loans and current portion of provisions.

Operating netback: Perpetual considers operating netback an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated by deducting royalties, operating costs, and transportation from realized revenue. Operating netback is also calculated on a per boe basis using average boe production for the period. Operating netback on a per boe basis can vary significantly for each of the Company's operating areas. Pre-municipal tax operating netback at the Eastern Alberta shallow gas property level is calculated using production revenues assuming AECO Daily Index pricing less royalties, transportation and operating expenditures excluding municipal taxes.

Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue and realized NGL revenue which includes realized gains (losses) on financial natural gas, crude oil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the disposition of the Shallow Gas Properties. Realized revenue, excluding foreign exchange contracts is used by management to calculate the Corporation's net realized commodity prices taking into account monthly settlements on financial crude oil and natural gas forward sales, collars and basis differentials. These contracts are put in place to protect Perpetual's adjusted funds flow from potential volatility in commodity prices, and as such, any related realized gains or losses are considered part of the Corporation's realized price.

For additional reader advisories in regards to non-GAAP financial measures, including Perpetual's method of calculation and reconciliation of these terms to their corresponding GAAP measures, see the section entitled "Non-GAAP Measures" within the Company's MD&A filed on SEDAR.

SOURCE Perpetual Energy Inc.

CALGARY, Feb. 7, 2018 /PRNewswire/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", or the "Company") is pleased to announce its year-end 2017 production exit rate (average for the month of December) of 12,300 boe/d, attaining year-over-year exit rate growth of 54%. The Company invested $19.0 million in exploration and development activities during the fourth quarter of 2017 and grew production 14% quarter-over-quarter. Production and operating costs continued the positive trend established through 2017, averaging $3.45/boe for the fourth quarter and $4.52/boe for 2017, down 33% from full year 2016.

In 2017, Perpetual focused investment in its core producing assets at East Edson and Mannville, adding proved plus probable reserves to replace 248% of annual production and grow the value of proved plus probable reserves year-over-year, as reported by the independent engineering firm McDaniel and Associates Consultants Ltd. ("McDaniel"). The quality of Perpetual's assets and positive momentum to drive operational and execution excellence in its core operating areas are demonstrated by the highlights below:

• Total proved plus probable reserves grew by 9% to 66.6 MMboe, up 5.3 MMboe after 2017 production of 3.6 MMboe. Importantly, the Company grew total proved reserves by 22% to 42.8 MMboe (64% of total proved plus probable reserves) and doubled its proved developed producing reserves to 15.9 MMboe. Proved plus probable developed producing reserves were 20.5 MMboe at December 31, 2017, 44% higher than year-end 2016.
  
  
• Proved plus probable developed producing reserves were 20.5 MMboe at December 31, 2017, 44% higher than year-end 2016.
  
  
• Exploration and development capital spending of $73.0 million in 2017 resulted in finding and development ("F&D") costs of $6.16/boe on a proved plus probable basis, and finding, development and acquisition costs ("FD&A") of $5.98/boe, both including changes in future development capital ("FDC"). Combining with a 2017 operating netback of $14.35/boe, the Company achieved a proved plus probable FD&A recycle ratio of 2.4:1.
  
  
• The net present value ("NPV") of Perpetual's total proved plus probable reserves (discounted at 10%) before income tax, grew by 8% to $409.9 million (2016 - $380.7 million), despite a decrease in McDaniel's forecast for both oil and natural gas prices at year-end 2017.
  
  
• Based on McDaniel's commodity price forecasts, Perpetual's reserve-based net asset value ("NAV") (discounted at 10%) at year-end 2017 is estimated at $336.5 million ($5.68 per share).

Finally, in active management of the recent decline in the forward market for near-term AECO natural gas prices, Perpetual today announces several important steps taken to maximize profitability, preserve the value of its reserves and manage risk:

• Perpetual reduced its exposure to AECO natural gas prices through the market diversification contracts entered into during the third quarter of 2017 and has now secured fixed price forward sales contracts on its remaining expected 2018 AECO natural gas sales volumes, net of royalties.
  
  
• Further, Perpetual's Board of Directors have approved a revised 2018 capital plan totaling $23 to $27 million, a 30% reduction to capital spending from the plan announced on November 10, 2017. The revised plan is designed to prudently defer development of the Company's East Edson natural gas asset to ensure maximum returns from development of the reserves and re-allocate capital to heavy oil prospects in its diversified portfolio of opportunities. At the current forward commodity price market, the revised capital spending plan is expected to result in 2018 adjusted funds flow in excess of capital spending and obligations, allowing for debt repayment and other opportunities.

OPERATIONS UPDATE

During the fourth quarter of 2017, capital spending totaled $19.0 million as previously forecast, more than 90% directed to the Company's liquids-rich gas property at East Edson. An additional $0.9 million was spent on well abandonment and reclamation work to reduce decommissioning obligations.

The single rig drilling program at East Edson continued through the fourth quarter, resulting in the drilling of three (3.0 net) wells, including a second extended reach horizontal ("ERH") well. A third ERH well will be rig released in the first quarter of 2018 to finish the East Edson drilling program. The first two ERH wells were completed and tied in during the fourth quarter while the remaining two wells were completed in January 2018. Completion operations for the third ERH well, originally scheduled for the first quarter of 2018, have been deferred to the fourth quarter of 2018, anticipating stronger future natural gas prices to maximize profitability.

The first ERH well at 4-23-51-16W5 represented the highest deliverability well drilled to date by Perpetual at East Edson with a thirty day average initial productivity ("IP30") of 15.6 MMcf/d of natural gas plus associated liquids based on field estimates, 75% higher than the length-adjusted type curve contained in the 2017 year-end McDaniel reserve report. The second ERH well, which is still under test and not optimized, appears to be below the length-adjusted type curve. The sum of the two wells is anticipated to exceed McDaniel's proven plus probable expectations.

In the fourth quarter of 2017, compression was added at the 100% owned and operated West Wolf Lake 10-3 plant, to align compression and process capacity at the facility, bringing the plant capacity to 65 MMcf/d, and area capacity to 78 MMcf/d, including the 15% working interest capacity held at a third-party operated facility in Rosevear. This expansion was completed in December 2017 for $2.1 million, on budget and three months ahead of schedule, to accommodate the accelerated availability of increased firm transportation on TCPL to 78 MMcf/d from April 1, 2018 to December 17, 2017.

Eleven (11.0 net) of the wells drilled in 2017 had an average 1,700 meters horizontal length and pioneered a new monobore well design. This new design, coupled with lower service costs, reduced the total cost of a typical Edson well to $4.2 million (inclusive of drilling, completion, equipment and tie-in), driving capital efficiencies from an average $11,000 per boe/d during 2014 to 2016 to $8,600 per boe/d based on first 12-month average production as per McDaniel's proved developed producing forecast, despite operational difficulties on one well which had a significantly higher capital efficiency ratio. Two (2.0 net) additional wells drilled in 2017 were designed to test the application of ERH wells for future development of the Wilrich reserves and were successfully drilled to 2,460 meters and 3,489 meters in length, with the third ERH well rig released in the first quarter of 2018 at 2,953 meters. Preliminary results suggest that capital efficiencies will be further reduced through this development approach.

Capital spending on heavy oil projects in Mannville during the fourth quarter of 2017 included waterflood projects and well optimization activities with $1.0 million spent. In January, construction of additional water handling and disposal facilities are underway and the first of a four (4.0 net) well (10 multi-lateral legs) drilling program was spud on January 31, 2018.

Drilling activities in 2017 resulted in production from one new Sparky pool, and increased production in the I2I pool which has been under waterflood since late 2013. 2017 saw a marked reduction in base decline rates in heavy oil production at Mannville from an average of greater than 30% year-over-year declines in 2015 and 2016 to less than 10% through 2017 (excluding the impact of new drilling). This reduction in decline rates is attributable to successful waterflood performance, resulting in higher recovery of oil in place.

Fourth quarter 2017 operating expenses continued to trend downward to $3.45/boe. Reduced costs at both Mannville and East Edson improved area operating netbacks, and operating costs on a unit-of-production basis reached top decile performance at East Edson as production ramped up on a relatively fixed operating base.

2018 OUTLOOK

2018 Capital Spending

In response to material commodity market changes, Perpetual has revised its 2018 capital plan to preserve the value of its East Edson reserves by deferring any additional 2018 Wilrich formation development drilling and accelerate spending on highly economic heavy oil projects at Mannville, for a net reduction to the 2018 capital budget to $23 - $27 million. On November 10, 2017, the Company announced that the Board of Directors approved a capital spending program of $37 million for 2018, close to 75% concentrated in East Edson, developing natural gas reserves with liquids in the Wilrich formation, and 25% in Eastern Alberta, primarily targeting heavy oil development at Mannville. The forward average AECO and WTI prices for Calendar 2018 as of November 9, 2017 were $2.01 per GJ (US$3.09 per MMbtu NYMEX) and US$56.91 per bbl, respectively. The revised capital plan accounts for the wind down of gas focused drilling activities at East Edson and results in a modified capital plan with investment split more evenly between the two core operating areas and natural gas and oil commodities.

Although NYMEX natural gas prices have remained relatively steady as natural gas storage has been depleted through the winter to below historical levels driven by strong demand, the basis differential to Western Canada markets has widened and AECO forward natural gas prices have weakened materially over the same period. Perpetual's five year market diversification contracts that came into effect on November 1, 2017 have substantially mitigated the impact on adjusted funds flow of lower AECO prices, as the contracts appreciate in value with wider differentials to each of the five market price points. However, Perpetual measures economic returns for all new natural gas investments against current unhedged AECO strip pricing, as incremental volumes, net of royalties, would be effectively sold to this market. At the same time, the forward market for West Texas Intermediate oil has strengthened, translating into slightly stronger expected prices for Perpetual's blend of heavy oil, condensate and natural gas liquids ("NGL"). Currently, the forward average AECO and WTI prices for calendar 2018 as of February 6, 2018 are $1.35 per GJ and US$61.25 per bbl, respectively.

Perpetual's two core areas of operation provide a diversified portfolio of investment opportunities. The Company will remain nimble to reallocate spending between natural gas focused projects at East Edson and heavy oil projects depending on where the most profitable economics can be secured. For the first quarter, the one outstanding frac of the third ERH well at East Edson will be postponed until late in the third quarter of 2018. Perpetual will re-direct spending to its heavy oil development project of the Birch General Petroleum A pool in Mannville, including water handling and disposal facilities and a four well multi-lateral horizontal drilling program previously budgeted for the second half of 2018. Assuming continued weakness in AECO natural gas prices, the four-well East Edson drilling program previously planned for the third quarter of 2018 will be deferred pending stronger AECO natural gas prices. Three (2.3 net) development wells at Mannville are expected to proceed as planned in the third quarter, along with three to six (3.0 to 6.0 net) additional wells at Mannville to evaluate the future horizontal development potential of three undeveloped heavy oil pools.

The table below summarizes planned capital spending and drilling activities for the first and second half of 2018.

Exploration and Development Forecast Capital Expenditures

Production Guidance

With the accelerated availability of increased firm transportation on TCPL, coupled with the capital re-allocation strategy to heavy oil, first quarter 2018 production is expected to average close to 13,300 boe/d, approximately 1,100 boe/d higher than previously forecast. Natural declines at East Edson will decrease natural gas and NGL production during the second and third quarters when AECO gas prices are expected to be at their lowest levels for the year. Then production will ramp up again with the planned late third quarter frac of the ERH well waiting on completion. Based on total exploration and development capital spending in 2018 of $23 to $27 million, Perpetual forecasts production to average approximately 11,500 boe/d for 2018 and forecasts to exit the year at approximately 10,700 boe/d (17% oil and NGL) as gas production at East Edson declines and Mannville heavy oil production ramps up driven by increased drilling and waterflood activity. While the growth in average daily production will be diminished from the original budget plan of 32%, year-over-year growth is still expected to be 17%, with a higher proportion of oil and NGL than previously forecast.

Marketing and Hedging Update

Concurrent with the sale of Perpetual's shallow gas properties on October 1, 2016, Perpetual entered into commodity price contracts whereby Perpetual was obligated to provide an AECO floor price of $2.58/GJ on 33,611 GJ/d through August 31, 2018. Perpetual's obligation has now been fixed at a cost of $8.5 million in 2018.

During the third quarter of 2017, Perpetual diversified its natural gas price exposure from AECO by entering into arrangements to effectively shift the sales point of 34.1 MMcf/d to a basket of five North American natural gas hub pricing points for a five year period commencing November 1, 2017, increasing to 39.0 MMcf/d commencing April 1, 2018. Based on current futures prices, these market diversification contracts will provide a significant premium over AECO prices in 2018 and provide significant diversification to Perpetual's natural gas pricing point exposure (net of royalties) as detailed below:

Perpetual has in place a number of commodity hedges to increase certainty of 2018 adjusted funds flow by mitigating the effects of commodity price volatility.

Natural Gas

The following table provides a summary of natural gas physical and financial forward sales positions (net of related financial natural gas purchase contracts) in place as at February 6, 2018:

Crude Oil

The following tables provide a summary of crude oil contracts in place as at February 6, 2018:

Adjusted Funds Flow and Sensitivities

The following revised 2018 guidance assumptions, based on settled and forward 2018 market prices as at January 25, 2018 and operations assumptions as outlined above, have been used:

• Exploration and development capital spending of $23 to $27 million;
• 2018 average daily production of 11,500 boe/d (17% oil and NGL);
• Calendar 2018 average NYMEX gas price of US$2.98 per MMbtu;
• Calendar 2018 average West Texas Intermediate ("WTI") oil price of US$63.54 per bbl;
• Calendar 2018 average Western Canadian Select ("WCS") differential of (US$23.83) per bbl;
• Calendar 2018 average NYMEX to AECO basis differential of (US$1.77) per MMbtu;
• Calendar 2018 average CAD/USD exchange rate of 1.235; and
• 2018 cash costs, including royalties, of $13.00 to $14.00 per boe, increased slightly from previous outlook due to the impact of lower forecast production volumes on a mainly fixed cost structure.

Based on the capital spending plan and production assumptions outlined above, and the current forward market for oil and natural gas prices at market pricing points, Perpetual forecasts 2018 adjusted funds flow of $33 to $37 million ($0.56/share to $0.62/share) down from $35 to $40 million previously forecast in its news release dated November 10, 2017 due to lower forecast production and natural gas pricing.

Over the past year, natural gas prices at AECO have become disconnected from the North American market as resource development in the Western Canadian Sedimentary Basin has outpaced market access and market demand. Perpetual's market diversification contracts were put in place to mitigate the risk of lower AECO pricing due to widening of the basis differentials relative to various other markets and enable price participation in NYMEX-based markets. Incorporating the assumptions outlined above, and presuming NYMEX and AECO basis differentials remain constant to each of the diversified natural gas pricing points, Perpetual's estimated adjusted funds flow sensitivity to various commodity prices is as follows:

The following additional sensitivities can be applied to estimate additional changes to projected 2018 adjusted funds flow:

• For every $0.25 USD/MMbtu widening or increase (narrowing or decrease) in the Calendar 2018 NYMEX to AECO basis differential, adjusted funds flow increases (decreases) by $4.4 million;
  
  
• For every $5.00 USD/bbl widening or increase (narrowing or decrease) in the Calendar 2018 WCS differential, adjusted funds flow decreases (increases) by $1.6 million; and
  
  
• For every $0.01 increase (decrease) in the Calendar 2018 CAD/USD exchange rate, adjusted funds flow increases (decreases) by $0.9 million.

At the current forward market for natural gas and oil prices, 2018 adjusted funds flow is expected to exceed capital spending and other obligations. Year-end 2018 debt, net of the current market value of the Company's investment in shares of Tourmaline Oil Corp. ("TOU" – TSX) of close to $35 million, is forecast at $105 to $110 million, with a corresponding estimated net debt to trailing twelve months adjusted funds flow ratio of approximately 3.2 times.

2017 YEAR-END RESERVES

Year-end 2017 Reserve Highlights

• Total proved plus probable reserves were 66.6 MMboe at December 31, 2017, up 5.3 MMboe (9%) from year-end 2016 after production of 3.6 MMboe.
  
  
• Total proved producing reserves were 15.9 MMboe at December 31, 2017, up 99% from year-end 2016 and proved plus probable producing reserves were 20.5 MMboe at December 31, 2017, up 44% from year-end 2016.
  
  
• Despite a decrease in McDaniel's forecast for both oil and natural gas prices, the NPV (discounted at 10%) ("NPV10") of the proved plus probable reserves increased by 8% at year-end 2017 to $409.9 million, highlighting the value growth created through demonstrated material operating cost reductions and enhanced capital efficiencies. The increase in value of the proved plus probable reserves was driven by strong well performance at both East Edson and Mannville and a 5% reduction to forecast future development capital ("FDC").
  
  
• East Edson represented 92% (2016 – 93%) of total proved plus probable reserves at year-end 2017. The drilling of 13 (13.0 net) wells in 2017 more than compensated for production of close to 2.9 MMboe, increasing proved plus probable producing reserves by 49%. The plant expansion at East Edson completed in late 2017 provides company-owned infrastructure capacity and firm transportation alignment at 78 MMcfd. A revised development plan including the new ERH well design and higher production capacity, resulted in an overall reduction of future development capital while growing total proved plus probable reserves by 8%.
  
  
• Production from heavy oil wells at Mannville of 0.4 MMboe was offset by upward technical revisions to proved plus probable reserves related to the positive impact of waterflood implementation during 2017. Total proved plus probable reserves were 3.3 MMboe at December 31, 2017, up 0.5 MMboe from year-end 2016. While Mannville heavy oil reserves account for just 5% of Perpetual's total proved plus probable reserves, this core area accounts for 9% of Perpetual's total proved developed producing reserves and 10% of total proved plus probable developed producing reserves.
  
  
• On a commodity basis, oil and natural gas liquids ("NGL") represent 12% (11% at year-end 2016) of Perpetual's total proved plus probable reserves and 11% (11% at year-end 2016) of total proved reserves at December 31, 2017.
  
  
• Positive technical proved reserve revisions in both East Edson and Mannville heavy oil assets offset total Company annual production of 3.6 MMboe by 284%, highlighting strong operational performance and drilling results from the Company's core assets.
  
  
• Perpetual's NAV (discounted at 10%) at year-end 2017 was preserved at $336.5 million ($5.68 per share) as compared to $394.8 million ($7.33 per share) at year-end 2016, despite lower forecast commodity prices. See the detailed NAV calculation under the heading "NET ASSET VALUE".

Reserves Disclosure

Working interest reserves included herein refer to working interest reserves before royalty deductions. Reserves information is based on an independent reserves evaluation report prepared by McDaniel's with an effective date of December 31, 2017 (the "McDaniel Report"), and has been prepared in accordance with National Instrument 51-101 ("NI 51-101") using McDaniel's forecast prices and costs. Complete NI 51-101 reserves disclosure including after-tax reserve values, reserves by major property and abandonment costs will be included in Perpetual's Annual Information Form ("AIF"), when filed, and will be available on the Corporation's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com. Perpetual's reserves at December 31, 2017 are summarized below:

Total proved reserves at December 31, 2017 account for 64% (2016 – 57%) of total proved plus probable reserves. Proved producing reserves of 15.9 MMboe comprise 37% (2016 – 23%) of total proved reserves. Proved plus probable developed reserves of 23.4 MMboe represent 35% (2016 – 26%) of total proved plus probable reserves. The material increase in the percentage of producing and developed reserves at year-end 2017 relative to the prior year is primarily due to the impact of drilling at East Edson converting wells from undeveloped to developed, as well as an increased recognition in waterflood reserves in Mannville heavy oil.

Reserves Reconciliation

McDaniel's recorded net positive technical revisions of 6.4 MMboe related to performance on a proved plus probable basis in 2017. Positive technical revisions of 1.5 MMboe were attributed to improved performance of existing wells in both West Central and Eastern areas, and 4.9 MMboe were related to increases in individual reserve assignments in the East Edson area associated with the ERH locations and the reclassification of inventory locations to probable undeveloped reserves in the eight year development window.

The table below summarizes the FDC estimated by McDaniel's by play type to bring non-producing and undeveloped reserves to production.

McDaniel's estimates the FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves, to be $348.4 million at December 31, 2017. Estimated FDC decreased by $19.2 million, down from $367.6 at year-end 2016, and $458.7 million at year-end 2015. On a proved plus probable basis, FDC decreased by $23.4 million related to the future development of reserves at East Edson and increased $4.2 million in the Mannville heavy oil area. Positive adjustments were related to improvements in capital efficiencies in East Edson due to changes in well design. ERH wells (2,000 – 3,500 meters in horizontal length) are modeled at higher total cost, but have improved capital efficiencies as higher production more than makes up for costs on a per meter basis. The increased reservoir coverage and higher per well rates due to the ERH wells utilized in the future development plan in the Wilrich formation at East Edson has reduced the total number of locations in the total proved plus probable eight year development plan to 63.3 net undeveloped locations (2016 – 72.7 net locations). The projects are forecast by McDaniel's to generate annual operating cash flow in excess of the annual FDC, making the projects self-funding.

RESERVE LIFE INDEX

Perpetual's proved plus probable reserves to production ratio, also referred to as reserve life index ("RLI"), was 13.2 years at year-end 2017 while the proved RLI was 9.1 years, based upon the 2018 production estimates in the McDaniel Report. The following table summarizes Perpetual's historical calculated RLI.

NET PRESENT VALUE OF RESERVES SUMMARY

Perpetual's oil, natural gas and NGL reserves were evaluated by McDaniel's using McDaniel's product price forecasts effective January 1, 2018 prior to provision for financial oil and natural gas price hedges, income taxes, interest, debt service charges and general and administrative expenses. The following table summarizes the NPV of funds flows from recognized reserves at January 1, 2018, assuming various discount rates: 

McDaniel's NPV10 estimate of Perpetual's total proved plus probable reserves at year-end 2017 was $409.9 million, up 8% from $380.7 million at year-end 2016. The increase in NPV10 reflected recycle ratios at East Edson driven by better well performance, combined with lower FDC in 2017, which offset the impact of lower forecast commodity prices. At a 10% discount factor, total proved reserves account for 66% (2016 – 55%) of the proved plus probable value. Proved plus probable producing reserves represent 41% (2016 – 26%) of the total proved plus probable value (discounted at 10%).

FAIR MARKET VALUE OF UNDEVELOPED LAND

Perpetual's independent third-party estimate of the fair market value of its undeveloped acreage by region for purposes of the NAV calculation is based on past Crown land sale activity, adjusted for tenure and other considerations. In West Central Alberta, no undeveloped land value was assigned where proved and/or probable undeveloped reserves have been booked.

The fair market value of Perpetual's undeveloped land at year-end 2017, adjusted to remove the value of undeveloped lands with reserves assigned in West Central Alberta, is estimated by an external land consultant at $46.7 million, a decrease of 6% from $49.9 million relative to year-end 2016. The fair market value of undeveloped oil sands leases incorporates the absolute investment to date in the ongoing bitumen extraction pilot project at Panny and the undeveloped land value is also supported by recent land sale activity.

NET ASSET VALUE

The following NAV table shows what is normally referred to as a "produce-out" NAV calculation under which the Corporation's reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the NAV represents the fair market value of Perpetual's shares. The calculations below do not reflect the value of the Corporation's prospect inventory to the extent that the prospects are not recognized within the NI 51-101 compliant reserve assessment, except as they are valued through the estimate of the fair market value of undeveloped land.

The above evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production, as recognized by McDaniel's, that meet the criteria for booking under NI 51-101. Perpetual compiles annually a detailed internal estimate of the Corporation's total future decommissioning obligation based on net ownership interest in all wells, facilities and pipelines, including estimated costs to abandon the wells, facilities and pipelines and reclaim the sites, and the estimated timing of the costs to be incurred in future periods. Costs inclusive in McDaniel's reserve assessment align closely with the Company's estimate of total future decommissioning obligations, net of estimated salvage value of facilities and equipment, therefore no additional future decommissioning obligation adjustment is included. The fair market value of undeveloped land does not reflect the value of the Company's extensive prospect inventory which is anticipated to be converted into reserves and production over time through future capital investment.

FINDING AND DEVELOPMENT COSTS

Under NI 51-101, the methodology to be used to calculate finding and development ("F&D") costs includes incorporating changes in FDC required to bring the proved and probable undeveloped reserves to production. Changes in forecast FDC occur annually as a result of development activities, acquisitions and disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production.

Comparison to prior year is not possible, as in 2016, F&D costs, including changes in FDC, could not be calculated as the change in FDC more than offset 2016 exploration and development spending. Similarly, Perpetual's FD&A costs could not be calculated in 2016 as the change in FDC and impact of dispositions more than offset exploration and development spending.

ADDITIONAL INFORMATION

Perpetual expects to release its 2017 annual audited financial statements and management's discussion and analysis ("MD&A") on or about February 23, 2018.

Oil and Gas Advisories

The reserves estimates contained in this news release represent our gross reserves as at December 31, 2017 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein.

All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and decommissioning obligations and are stated prior to provision for finance and general and administrative expenses. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

To provide a single unit-of-production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe), using the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

This news release contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "finding and development" costs or "F&D" costs, "F&D recycle ratio", "finding development and acquisition" costs or "FD&A" costs, "FD&A recycle ratio", "operating netbacks", "reserve life index" and "net asset value". This news release also refers to capital efficiency which is defined as a type of capital efficiency that measures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Perpetual uses the total actual/projected drill, complete and tie-in capital divided by the total of the well initial twelve-month production rate. Perpetual uses the term "prospect inventory" to refer to projects that do not meet the requirements to be classified as reserves either due to the timing of production, economic requirements or technical risk. These oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this news release to provide readers with additional measures to evaluate Perpetual's performance, however, such measures are not reliable indicators of Perpetual's future performance and future performance may not compare to Perpetual's performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders and investors with measures to compare Perpetual's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.

F&D costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserve category and the costs incurred on development and exploration activities in the year by the change in reserves from the prior year for the reserve category. FD&A costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserve category and the costs incurred on development and exploration activities and property acquisitions (net of dispositions) in the year by the change in reserves from the year for the reserve category. Both F&D costs and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the F&D costs incurred in the financial year and changes during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure.

FD&A recycle ratio is calculated by dividing the operating netback for the period by the FD&A costs per boe for the particular reserve category.

Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures calculated on a per boe basis (see also "Non-GAAP Measures"). Reserve life index is calculated based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by McDaniel.

Our estimated NAV is based on the estimated NPV10 of all future net revenue from our proved plus probable reserves, before tax, as estimated by McDaniel at year-end, with the estimated value of our undeveloped land, and less net debt. Common share values in our NAV per share metric are calculated using common shares outstanding, net of shares held in trust.

Unaudited financial information 

Certain financial and operating information included in this news release for the quarter and year-ended December 31, 2017, such as capital expenditures, FD&A costs, adjusted funds flow and net debt are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under "Forward-Looking Information". These estimated amounts may change upon the completion of audited financial statements for the year-ended December 31, 2017 and changes could be material.

The following abbreviations used in this news release have the meanings set forth below:

Forward-Looking Information 

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking information or statements under applicable securities laws. The forward looking information includes, without limitation, reserve estimates, potential for economic growth for shareholders; anticipated benefits of dispositions, including the shallow gas disposition dated October 1, 2016, anticipated amounts and allocation of capital spending; statements pertaining to adjusted  funds flow levels, future development and capital efficiencies; statements regarding estimated production and timing thereof; forecast average production; completions and development activities; infrastructure expansion and construction; estimated FDC required to convert proved plus probable non-producing and undeveloped reserves to proved producing reserves; anticipated effect of commodity prices on reserves; estimated NAV; prospective oil and natural gas liquids production capability; projected realized natural gas prices and adjusted funds flow; estimated decommissioning obligations; anticipated effect of commodity prices on FDC and reserves; commodity prices and foreign exchange rates; and commodity price management. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release, which assumptions are based on management's analysis of historical trends, experience, current conditions and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this news release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's MD&A for the year-ended December 31, 2016 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law.

Non-GAAP Measures

This news release contains the term "operating netbacks", "cash costs", and "net debt" which do not have standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of similar measures by other companies. Operating netbacks and cash costs are used by Perpetual to analyze operating performance. Perpetual believes these benchmarks are key measures of profitability and overall sustainability. These terms are commonly used in the oil and gas industry.

Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures calculated on a per boe basis. Cash costs are equal to the total of production and operating costs, transportation, royalties, general and administrative, and finance expenses. Net debt includes net working capital deficiency (surplus), revolving bank debt and the principal amount of the TOU share margin loan, Term Loan and Senior Notes reduced for the mark-to-market value of TOU shares held.

SOURCE Perpetual Energy Inc.

CALGARY, Dec. 20, 2017 /PRNewswire/ - Perpetual Energy Inc. ("Perpetual") announces that the common shares of the Company will be voluntarily delisted from the OTCQX effective the close of market December 29^th, 2017. The common shares of the Company will continue to trade on the Toronto Stock Exchange under the symbol "PMT". Perpetual has voluntarily delisted from OTCQX to increase trading volume of its common shares on the TSX.

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.com.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

SOURCE Perpetual Energy Inc.

CALGARY, Nov. 10, 2017 /PRNewswire/ - (TSX:PMT) - Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to announce a 62.5% increase to its reserve-based credit facility (the "Credit Facility") and confirm capital spending plans and expected production and adjusted funds flow growth for 2018. Strategic focusing of the Company's asset base, strengthening of the balance sheet, steady execution of the growth-oriented capital program and the Company's market diversification strategy implemented over the past year have combined to position Perpetual for continued strong growth in 2018. Based on current forward commodity prices, production growth of 30% in 2018 from 2017 levels is anticipated to drive 23% adjusted funds flow growth to $0.59 to $0.67/share, supported by a capital program substantially funded from adjusted funds flow.

Credit Facility

Perpetual Credit Facility lenders have completed their semi-annual borrowing base redetermination and have agreed to increase the borrowing limit from $40 million to $65 million, subject to execution of usual and customary loan documentation. In support of this increase, Perpetual has expanded its Credit Facility lending syndicate to three banks. The maturity date of the Credit Facility is May 31, 2019 and the next semi-annual borrowing base review is scheduled for May 31, 2018. The increased borrowing limit is expected to provide sufficient liquidity to execute the Company's 2018 business plan and retain the optionality and incremental liquidity related to the Company's 1.67 million share investment in Tourmaline Oil Corp. (TSX:"TOU").

2018 Capital Spending and Production Guidance

The Company's Board of Directors has approved a total capital spending program of $39 million for 2018, close to 75% concentrated in East Edson, developing liquids-rich natural gas reserves in the Wilrich formation, and 25% in Eastern Alberta, primarily targeting heavy oil development at Mannville along with abandonment and reclamation work to continue to responsibly address decommissioning obligations.

At East Edson, a single rig drilling program is ongoing with four (4.0 net) wells to be drilled during the fourth quarter of 2017, including two extended reach horizontal ("ERH") wells of varying lateral lengths. One ERH well has been successfully drilled thus far with a 2,460 meter horizontal lateral. The second is currently drilling in the horizontal section and is targeting in excess of 3,400 meters of Wilrich formation. The performance of the two ERH wells is expected to be evaluated following frac operations in late November. The remaining three wells of the 2017 program are budgeted to be frac'd during the first quarter of 2018. Drilling activities are forecast to start up again in the third quarter of 2018 with four (4.0 net) ERH wells planned to reverse forecast declines and ramp up production again to match processing and transportation capacity in time to meet stronger anticipated natural gas demand conditions and pricing in the fourth quarter of 2018. Additional compression is currently being installed at the Company's 100% working interest and operated West Wolf Lake facility for start-up in early January 2018 to increase total processing capacity in the East Edson area by close to 23% to 80 MMcf/d plus associated liquids, closely matching the Corporation's 20 MMcf/d increase to firm natural gas transportation capacity to 78 MMcf/d that is scheduled to take effect on or before April 1, 2018.

Based on the 1,700 meter lateral type curve, adjusted for the expected ERH well performance, average 2018 production at East Edson is forecast to grow over 35% year over year to average close to 10,800 boe/d. The positive impact of this higher production base over a substantially fixed cost base is anticipated to translate into further reduction in operating costs per unit of production at East Edson of close to $2.00/boe.

At Mannville, capital spending during the fourth quarter of 2017 is directed at waterflood infrastructure projects which will continue into the first quarter of 2018 to increase waterflood injection capability to provide additional pressure support to enhance heavy oil recovery as well as to reduce field operating costs. In the third quarter of 2018, up to seven (6.3 net) development wells are budgeted to be drilled to increase heavy oil production by close to 10%. Additionally, up to 20 shallow gas recompletions are planned to partially offset natural gas declines in Eastern Alberta. Decommissioning expenditures will be focused in the Mannville area and are expected to provide lease rental and property tax expense reductions while maintaining regulatory compliance.

The table below summarizes anticipated capital spending and drilling activities for the fourth quarter of 2017 and for the first and second half of 2018.

Exploration and Development Forecast Capital Expenditures

Based on total exploration and development capital spending in 2018 of $37 million, and an April 1, 2018 in-service date for additional firm transportation, Perpetual forecasts production to average close to 13,000 boe/d (85% natural gas) and expects to exit the year at over 14,500 boe/d as production ramps up again driven by the second half capital spending program targeting seasonal natural gas price optimization. This represents growth in average daily production in 2018 of 32% relative to 2017 as well as year over year growth in the average December exit rate of over 15%. Increased production combined with continued diligent cost management in 2018 is anticipated to continue to drive improved per unit cost structure performance with top quartile operating costs forecast of close to $4.00/boe.

Perpetual has taken significant steps to diversify its 2018 commodity and natural gas pricing point exposure (net of royalties) as detailed below:

The Company's market diversification strategy, combined with continued reduction to a forecast all-in cash cost structure, including royalties, of approximately $13.25/boe ($10.40/boe, excluding royalties) is anticipated to deliver further improvements to operating and adjusted funds flow netbacks over 2017, despite the lower current forward market for natural gas prices. 

Based on these capital spending and production assumptions and the current forward market for oil and natural gas prices at market pricing points, Perpetual forecasts 2018 adjusted funds flow of $35 to $40 million ($0.59/share to $0.67/share). Year end 2018 debt, net of the current market value of the Company's TOU share investment of close to $45 million, is forecast at $105 to $110 million, with a corresponding improvement in estimated net debt to trailing twelve months adjusted funds flow to approximately 2.9 times.

Incorporating the assumptions outlined above, and presuming AECO basis differentials remain constant to each of the diversified natural gas pricing points, Perpetual's estimated 2018 adjusted funds flow annualized sensitivity to various commodity prices is as follows.

Projected 2018 Adjusted funds flow

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.com.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.

Forward-Looking Information

Certain information regarding Perpetual in this news release including management's assessment of future plans and operations may constitute forward-looking statements under applicable securities laws. The forward-looking information includes, without limitation, statements regarding capital expenditure levels for the fourth quarter of 2017 and the full year of 2018 and the funding of such capital expenditures; prospective drilling activities; forecast production, forecast levels of debt, production type, operations, adjusted funds flows, and timing thereof; facility construction and pilot project plans and timing thereof; forecast and realized commodity prices; expected cost savings and the impact of cost savings initiatives, expected funding, allocation and timing of capital expenditures; projected use of adjusted funds flow and anticipated adjusted funds flow; planned drilling and development and the results thereof; and commodity prices. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this press release, which assumptions are based on management analysis of historical trends, experience, current conditions, and expected future developments pertaining to Perpetual and the industry in which it operates as well as certain assumptions regarding the matters outlined above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Perpetual and described in the forward-looking information contained in this press release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described under "Risk Factors" in Perpetual's Annual Information Form and MD&A for the year ended December 31, 2016 and those included in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR website (www.sedar.com) and at Perpetual's website (www.perpetualenergyinc.com). Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Perpetual's management at the time the information is released and Perpetual disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities laws.

Also included in this press release are estimates of Perpetual's 2018 adjusted funds flow and adjusted funds flow per share based on 59.3 million shares issued and outstanding, which is based on the various assumptions as to production levels, including estimated average production, capital expenditures, and other assumptions including current forward commodity price assumptions. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on November 6, 2017 and is included to provide readers with an understanding of Perpetual's anticipated adjusted funds flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

Volume Conversions

Barrel of oil equivalent ("boe") may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ("NI 51-101"), a conversion ratio for natural gas of 6 Mcf:1bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion on a 6 Mcf:1 bbl basis may be misleading as an indicator of value as the value ratio between natural gas and crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl.

Non-GAAP Measures

This news release contains financial measures that may not be calculated in accordance with generally accepted accounting principles in Canada ("GAAP"). Readers are referred to advisories and further discussion on non-GAAP measures contained in the "Significant Accounting Policies and non-GAAP Measures" section of the most recent management's discussion and analysis

SOURCE Perpetual Energy Inc.

CALGARY, Nov. 7, 2017 /PRNewswire/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its third quarter 2017 financial and operating results. A complete copy of Perpetual's unaudited condensed interim consolidated financial statements and related Management Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2017 can be obtained through the Company's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

The strategic focusing of our asset base, strengthening of our balance sheet, and steady execution of our growth-oriented capital program delivered attractive results in the third quarter. Adjusted funds flow of $8.2 million ($0.14 per share) was up 56% ($3.0 million) over the second quarter and $8.8 million over the comparative period in 2016. The main drivers of improved performance were a combination of production growth of 12%, despite voluntary shut-ins, and significant cost improvements in all aspects of our business, particularly at East Edson where operating costs were driven down another 22% to $2.42/boe during the third quarter. Furthermore, proactive natural gas price optimization strategies mitigated the impact of extremely low and volatile natural gas prices in Alberta and translated into an average realized natural gas sales price of $3.11/Mcf, more than 50% higher than AECO monthly index prices.

THIRD QUARTER 2017 HIGHLIGHTS

Production and Operations

• Exploration and development spending totaled $25.4 million in the third quarter ($53.9 million year to date), a significant increase over prior year spending of $1.4 million ($7.0 million year to date).
  
  
• Drilling and completion activity was focused in West Central Alberta at East Edson during the third quarter of 2017, and included the drilling of four (4.0 net) Wilrich horizontal wells and the completion of seven (7.0 net) wells, four of which were drilled in the first half of 2017. An additional one (0.4 net) exploration well was rig released in the third quarter in the Columbia/Brazeau area within West Central Alberta, with frac and follow on evaluation activities taking place in October.
  
  
• Third quarter average production of 10,330 boe/d was driven by positive results from the Company's focused capital program to develop Wilrich reserves, and more than offset the average 450 boe/d of voluntary shut-ins that the Company opportunistically implemented to maximize value with minimal impact on adjusted funds flow. This price optimization strategy was set up by transportation constraints created by pipeline maintenance activities in Alberta during the quarter and has continued into the fourth quarter.
  
  
• Production growth was focused in West Central, which comprised 80% of total production, and increased 17% (1,190 boe/d) over the second quarter. New wells are performing at or above projected type curves. West Central production was constrained by Perpetual's firm transportation capacity as well as the voluntary shut-ins implemented through temporary restriction of select wells. Third quarter exit production rates were more than 40% higher than second quarter exit rates.
  
  
• Oil and natural gas liquid ("NGL") production averaged 1,711 bbl/d, virtually flat to the second quarter and representing 16% of total production.
  
  
• Perpetual's average realized natural gas price in the third quarter of $3.11/Mcf decreased by 2% from second quarter prices compared to a 27% decrease in the average AECO Monthly Index for the same period. Key factors contributing to the premium to AECO include:
  
  
• Approximately 50% of third quarter production was sold under contracted physical and financial arrangements at an average price of $3.14/GJ;
  
  
• Price optimization strategies were applied to prompt month physical settlements which included a $0.10/GJ contribution to Perpetual's average realized price associated with the voluntary shut-in of production during the quarter to take advantage of temporary situations when natural gas could be purchased at nominal cost and delivered against pre-sold volume commitments at attractive margins while retaining reserves; and
  
  
• Over 80% of Perpetual's natural gas is produced from East Edson which yields higher heat content gas, (GJ to Mcf ratio of 1.17) translating into higher realized natural gas prices.
  
  
• Realized oil prices during the third quarter of $43.01/bbl were relatively consistent with prices realized during the second quarter of 2017 while NGL prices declined 12% over the same period to $39.06/bbl.
  
  
• Total production and operating expenses decreased 28% relative to the second quarter to $3.3 million ($3.50/boe). This decrease reflected continued diligent cost management, and $0.9 million ($0.95/boe) of non-recurring adjustments associated with third party processing facilities that were sold as part of the Shallow Gas Disposition. When excluding the $0.95/boe impact of non-recurring adjustments, third quarter operating costs on a unit of production basis were $4.45/boe, down 19% from the second quarter of 2017. Operating costs per unit of production at East Edson averaged $2.42/boe and are expected to continue to decrease due to the impact of increased production on a substantially fixed operating cost base.

Financial Highlights

• Realized revenue of $20.7 million was up 4% from $19.9 million in the second quarter, reflecting strong production growth and commodity price management performance despite lower AECO Monthly Index natural gas prices. Natural gas revenue represented 66% of total petroleum and natural gas revenue in the third quarter of 2017 (Q3 2016 – 76%), despite reflecting 84% of average production.
  
  
• Perpetual demonstrated significant improvement in its per unit cost structure in the third quarter. Compared to the second quarter of 2017, royalties, production and operating expenses, and general and administrative expenses decreased by $1.55/boe (36%), $1.07/boe (19%) and $0.74/boe (20%), respectively, due to the impact of increasing production across the high percentage of fixed costs combined with prudent cost control.
  
  
• Adjusted funds flow reached $8.2 million ($0.14/share) in the third quarter, up 56% ($3.0 million) over second quarter adjusted funds flow of $5.2 million ($0.09/share) and $8.8 million over the comparative period in 2016. Adjusted funds flow per boe was $8.62/boe, an increase of $2.38/boe (38%) from the second quarter of 2017 as improved operating performance significantly outpaced the 8% ($1.93/boe) decrease in realized revenue per boe. The 12% quarter over quarter increase in production in the third quarter contributed the remaining increase in adjusted funds flow.
  
  
• The Company recorded a net loss for the third quarter of 2017 of $8.1 million, compared to a net loss of $7.2 million in the previous quarter. Improved quarter over quarter adjusted funds flow was more than offset by additional unrealized losses related to the decline in market value of its investment of 1.67 million shares of Tourmaline Oil Corp. (TSX – "TOU").
  
  
• Perpetual continued to take steps to strengthen its financial position during the third quarter which included the following:
  
  
• On July 4, 2017, the Company announced that it had doubled its borrowing capacity available under its reserve based credit facility (the "Credit Facility") to $40 million and extended its repayment term to two years, at lower borrowing costs.
  
  
• On July 31, 2017, the Company also completed the refinancing of the $36.5 million of margin loans secured by the Company's TOU shares, with $18.7 million of proceeds from a replacement one-year margin loan, and borrowings under its Credit Facility.
  
  
• In mid-July, $1.0 million face value of senior notes due to mature on July 23, 2019 (the "2019 Senior Notes") were re-purchased at 96.75% of face value and retired.
  
  
• On July 7, 2017, Moody's Investor Service upgraded Perpetual's corporate credit rating to Caa1 stable. As at September 30, 2017, 45% of Perpetual's debt matures in 2021 or later.

OUTLOOK

Success in advancing the Company's strategic priorities has established a foundation for strong growth in production and adjusted funds flow in 2017 and 2018. The Company expects to continue to drive capital efficiency improvements and reductions in operating, financing and administrative costs to improve upon the sustainable cost structure achieved through strategic decisions implemented over the past two years.

Based on the total capital spending plan in 2017 of $73 to $78 million, Perpetual continues to expect to exit 2017 at a production rate approaching 13,000 boe/d (85% natural gas). This represents growth in exit rate based on average December production of approximately 60% compared to the prior year.

Capital spending during the remainder of 2017 will be funded through adjusted funds flow generation, the final $10 million drawdown of the Term Loan and borrowings under the Credit Facility. Perpetual is currently in discussions with its Credit Facility lenders regarding the redetermination of its borrowing limit effective November 30, 2017, and anticipates an increase to the Credit Facility borrowing base.

Based on these assumptions and the current forward market for oil and natural gas prices, Perpetual forecasts 2017 adjusted funds flow of approximately $28 to $32 million. Incorporating the current market value of 1.67 million TOU shares, the Company estimates year-end 2017 total net debt of approximately $100 to $105 million, with a corresponding estimated net debt to trailing twelve months adjusted funds flow ratio of approximately 3.4 at year end 2017.

For 2018, Perpetual is planning a capital program that will be funded by adjusted funds flow. Annual production in 2018 is anticipated to increase by approximately 30% over 2017.

The Company will continue to monitor commodity market fundamentals closely over the coming months and adjust activities as required, balancing the positive momentum that is translating into operational excellence in executing our East Edson development program with spending within our means to maintain adequate liquidity and balance sheet strength.

2017 STRATEGIC PRIORITIES

During the third quarter of 2017, significant progress was made to advance Perpetual's top four strategic priorities for 2017 which include:

1. Grow value of Greater Edson liquids-rich gas;
2. Optimize value potential of Eastern Alberta assets;
3. Advance high impact opportunities; and
4. Optimize balance sheet for growth.

Grow value of Greater Edson liquids-rich gas

• Perpetual's single rig drilling program at East Edson has continued through the third quarter with the rig release of four (4.0 net) Wilrich horizontal wells and the completion and frac of seven (7.0 net) wells, four of which were drilled in the first half of 2017. New wells are performing at or above expected type curve.
  
  
• Drilling and completion costs continue to show a 35 to 40% improvement over prior year costs as a result of well design changes. Ten monobore wells with an average 1,700 metre horizontal section have now been drilled, completed and tied-in at an average cost of $4.1 million per well, with the most recent two-well pad coming in at $3.7 million per well, equating to $2,400 per horizontal metre. Going forward, extended reach horizontal ("ERH") wells with horizontal laterals of more than 3,000 metres are expected to further improve costs to $2,000 per horizontal metre and drive capital efficiencies to less than $8,000 per boe/d average for the first year of production.
  
  
• During the fourth quarter of 2017, the Company plans to drill four (4.0 net) wells at East Edson, and evaluate the execution viability and production capability from ERH wells of varying lengths. With the completion and frac of these wells, production capability at East Edson will continue to exceed the company-owned infrastructure capacity and matching firm transportation capacity of 60 to 65 MMcf/d plus associated liquids.
  
  
• Additional compression will be installed at the West Wolf Lake plant during the fourth quarter to increase total East Edson natural gas processing capacity to 78 MMcf/d to match the increase in its firm transportation capacity scheduled on or before April 1, 2018.
  
  
• Third quarter production at East Edson comprised 80% of total production, and increased 17% over the second quarter, driven by the East Edson capital program despite production constraints caused by firm transportation capacity and voluntary shut-ins averaging 450 boe/d in the third quarter as part of Perpetual's price optimization strategy.
  
  
• Perpetual continues to achieve a top quartile operating cost structure at East Edson and further improved to average $2.42/boe (Q3 2016 – $3.20/boe; Q2 2017 – $3.11/boe) as a result of increased production and additional savings realized through diligent cost management. Operating costs per unit of production are expected to continue to decrease due to the impact of increased production at East Edson on a substantially fixed operating cost base.

Optimize value potential of Eastern Alberta assets

• Capital spending in Eastern Alberta was minimal during the third quarter with operations primarily directed to abandonment and reclamation projects. Perpetual has received two reclamation certificates in the third quarter (29 reclamation certificates year-to-date) which enable reduced property tax and surface lease rental costs going forward. Abandonment and reclamation expenditures over the remainder of 2017 of up to $0.8 million supporting continued cost reduction initiatives are anticipated.
  
  
• Crude oil production in eastern Alberta declined 7% quarter over quarter to 956 bbl/d, reflecting minimal capital spending and natural declines. Capital spending is expected to increase in the fourth quarter of 2017 as waterflood optimization resumes with the conversion of two new injectors.
  
  
• Gas production in eastern Alberta was effectively flat at 6.4 MMcf/d quarter over quarter as recompletion and workover activities offset natural declines. Low variable operating costs and synergy with well abandonment programs in the Mannville area result in gas recompletions paying out within 6 to 12 months at current commodity prices. These will continue during the fourth quarter of 2017 with up to ten additional recompletions planned.
  
  
• Production and operating expenses in eastern Alberta were $7.43/boe during the third quarter (Q3 2016 – $10.57/boe; Q2 2017 – $13.28/boe). Lower quarter over quarter costs related to $0.9 million of non-recurring 13 month adjustments associated with third party processing facilities that were sold as part of the Shallow Gas Disposition. The Company continues to prioritize cost reductions on its eastern Alberta assets, including a focus on municipal property taxes which represent a significant portion of fixed operating costs as the tax base assessment is dramatically misrepresentative of the actual tangible property value.

Advance high impact opportunities

• The two horizontal wells drilled during the fourth quarter of 2016 and the first quarter of 2017 to advance the evaluation of the shallow shale gas play in the Viking and Colorado formations are on production at low rates. Fracture stimulation of the Viking gas well has not been fully executed to date and additional spending has been delayed pending further learnings from performance monitoring and stronger natural gas prices.
  
  
• In the Columbia/Brazeau area of West Central Alberta, Perpetual participated for its 40% working interest in a third-party operated exploratory horizontal well targeting the Fahler formation. The well was rig released at the end of the third quarter with frac and follow-on evaluation activities currently underway.
  
  
• Limited spending during the third quarter was allocated to Perpetual's Panny bitumen project. Plans are underway to advance the evaluation of solvent technology in the Bluesky reservoir at Panny, utilizing important learnings from the cyclic heat stimulation pilot project to date. Solvent technology is expected to increase capital efficiencies and at the same time may positively enhance environmental performance through reduced emissions.

Optimize balance sheet for growth

• On July 4, 2017, the Company announced that it had doubled its borrowing capacity available under its reserve based credit facility (the "Credit Facility") to $40 million and extended its repayment term to two years, at lower borrowing costs.
  
  
• On July 31, 2017, Perpetual entered into a new $18.7 million margin loan secured by 1.67 million TOU shares that matures in July 2018. Proceeds from the new margin loan along with borrowings under the Credit Facility were used to repay the TOU share put option margin loans that were scheduled to mature in August and November of 2017. Proceeds of $1.0 million were realized from the sale of underlying put options.
  
  
• In mid-July, $1.0 million face value of 2019 Senior Notes were purchased at 96.75% of face value and retired. This reduction, in addition to the senior note transactions executed during the first half of 2017, contributed to a 46% decrease in senior note principal balance outstanding from year end with the next maturity due in Q3 2019.
  
  
• Total net debt at September 30, 2017 stood at $92.7 million which was an increase of 36% from June 30, 2017 of $68.3 million. Approximately $52.9 million, representing 46% of Perpetual's debt and 57% of net debt, matures in 2021 or later.
  
  
• On October 5, 2017 Perpetual borrowed the remaining $10 million under the Term Loan, increasing the total balance outstanding to $45 million.
  
  
• Incorporating net debt at September 30, 2017, adjusted for the $10 million drawn under the Term Loan in early October 2017, Perpetual has access to draw approximately $16 million under the Credit Facility. Combined with the current market value of the Company's TOU share investment, net of the new margin loan, total current available liquidity is approximately $30 million. Perpetual is currently in discussions with its Credit Facility lenders regarding the redetermination of its borrowing limit effective November 30, 2017, and anticipates an increase to the borrowing limit.
  
  
• In light of the positive financing transactions, in early July, Moody's Investor Service upgraded Perpetual's corporate credit rating to Caa1 stable.
  
  
• In order to protect a base level of adjusted funds flow, Perpetual has commodity price contracts in place for the remainder of 2017 comprised of forward month physical and financial natural gas contracts at AECO hub on a net 27,500 GJ/d to December 2017 at an average price of $3.16/GJ and 12,500 GJ/d for November 2017 through March 2018 at an average price of $2.94/GJ. Perpetual also has oil sales arrangements on 750 bbl/d protecting a WTI floor price of $USD50.00/bbl for the remainder of 2017.
  
  
• During the third quarter, Perpetual diversified its natural gas price exposure from AECO by entering into arrangements to shift the sales point of 34.1 MMcf/d to a basket of five North American natural gas hub pricing points (Chicago, Dawn, Empress, Malin and Mich Con) for a five year period commencing November 1, 2017 (39.0 MMcf/d commencing April 1, 2018). Based on current futures prices, Perpetual expects these gas price diversification contracts will provide a significant premium over AECO prices for the November 2017 to December 2018 time frame.

About Perpetual

Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual operates a diversified asset portfolio, including liquids-rich natural gas assets in the deep basin of west central Alberta, heavy oil and shallow natural gas in eastern Alberta, with longer term opportunities through undeveloped oil sands leases in northern Alberta. Additional information on Perpetual can be accessed at www.sedar.com or from the Corporation's website at www.perpetualenergyinc.com.

The Toronto Stock Exchange has neither approved nor disapproved the information contained herein.