Perpetual Energy Inc. Reports Strong Fourth Quarter and Year-End 2017 Financial and Operating Results

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 1st 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.


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.


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.


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.

Financial and Operating Highlights

Three Months ended

December 31

Year ended

December 31

($Cdn thousands,

except volume and per share amounts)








Oil and natural gas revenue







Net earnings (loss)







Per share - basic(2)







Per share - diluted







Cash flow from (used in) operating activities







Per share(1)(2)







Adjusted funds flow(1)







Per share(2)







Revolving bank debt





Senior Notes, at principal amount







Term Loan, at principal amount





TOU share margin loans, at principal amount







TOU share investment







Net working capital deficiency(1)







Total net debt(1)







Net capital expenditures

Capital expenditures







Geological and geophysical costs






Net payments (proceeds) on acquisitions and







Net capital expenditures







Common shares outstanding (thousands)(3)

End of period(4)







Weighted average - basic







Weighted average - diluted








Average production

Natural gas (MMcf/d)







Oil (bbl/d)







NGL (bbl/d)







Total (boe/d)







Average prices

Realized natural gas price ($/Mcf)







Realized oil price ($/bbl)







Realized NGL price ($/bbl)







Wells drilled

Natural gas – gross (net)

3 (3.0)

3 (3.0)

15 (14.4)

4 (4.0)

Oil – gross (net)

4 (3.3)

Total – gross (net)

3 (3.0)

3 (3.0)

19 (17.7)

4 (4.0)


These are non-GAAP measures. Please refer to "Non-GAAP Measures" below.


Based on weighted average basic common shares outstanding for the period.


Common shares and per share amounts have been retroactively adjusted to reflect the consolidation of outstanding common shares on the basis of 20 common shares to one common share on March 24, 2016. All common shares are net of shares held in trust.


Reduced by shares held in trust (2017 – 447; 2016 – 260). See "Note 15 to the Audited Consolidated Financial Statements".

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.