Perpetual Energy Inc. reports first quarter 2019 financial and operating results

May 8, 2019

CALGARY, May 8, 2019 /CNW/ - (TSX:PMT) – Perpetual Energy Inc. ("Perpetual", the "Corporation" or the "Company") is pleased to release its first quarter 2019 financial and operating results. Highlights from the quarter include:

  • Heavy oil production in Eastern Alberta grew 30% relative to the prior year first quarter, driven by positive results from heavy oil focused drilling and waterflood investment during the second half of 2018.

  • Perpetual's market diversification strategy delivered strong natural gas pricing of $3.54/Mcf.

  • Perpetual's realized operating netback increased 4% to $13.36/boe (Q1 2018 – $12.87/boe), reflecting continued top quartile operating costs at the East Edson liquids-rich gas property in West Central Alberta.

  • Cash flow from operating activities in the first quarter of 2019 was $9.3 million ($0.15/share) and adjusted funds flow was $6.4 million ($0.11/share).

  • On March 27, 2019, the Company's reserve-based credit facility was extended for an additional 1.5 years to November 30, 2020 and the borrowing limit was maintained at $55 million.

  • Net debt declined 9% ($10.2 million) from December 31, 2018 to $102.4 million.

  • On May 7, 2019, Perpetual announced it will early redeem the $14.6 million 2019 Senior Notes due July 23, 2019, effective June 11, 2019. The redemption will be funded by the issuance of $15.7 million 2022 Senior Notes.

A complete copy of Perpetual's unaudited condensed interim consolidated financial statements and related Management's Discussion and Analysis ("MD&A") for the three months ended March 31, 2019 can be obtained through the Company's website at www.perpetualenergyinc.com and SEDAR at www.sedar.com.

Perpetual adopted IFRS 16 "Leases" effective January 1, 2019 using the modified retrospective approach, therefore comparative information has not been restated. The adoption of IFRS 16 had a minimal impact on net loss, and increased cash flow from operating activities and adjusted funds flow by $0.1 million compared to what would have occurred had the new accounting policy not been adopted. Refer to the "recently adopted accounting pronouncements" section of the Q1 2019 MD&A for details.

FIRST QUARTER 2019 HIGHLIGHTS

Capital Spending, Production and Operations

  • Perpetual's 2019 budgeted capital spending program funded by adjusted funds flow, is largely planned for the second half of 2019 with approximately 50% of expenditures targeting heavy oil drilling in Eastern Alberta, and 50% targeting continued development of liquids-rich natural gas at the Company's East Edson property.

  • Exploration and development spending in the first quarter of 2019 was just $1.2 million, 92% lower than the comparative period in 2018, and consistent with guidance released with its 2018 year-end results on March 27, 2019.

    • Spending at the East Edson property in West Central Alberta was $0.7 million, and was directed towards the installation of field compression and a sweetening tower to enable reactivation of several higher liquids ratio wells back to production. The installation of the field compression and sweetening tower was completed in January, resulting in incremental production in Q1 2019 of approximately 300 boe/d.

    • Spending in Eastern Alberta was $0.5 million, 91% lower than the comparative period in 2018. Spending included the installation of automated leak detection monitoring equipment at several well pads.

  • Perpetual also spent $0.3 million (Q1 2018 – $0.6 million) on abandonment and reclamation projects. As part of Perpetual's focus on well and pipeline abandonment and reclamation, four reclamation certificates were received from the Alberta Energy Regulator ("AER") during the first quarter of 2019 (Q1 2018 – eight reclamation certificates) which will result in the cessation of associated property tax and surface lease expenses. The Company's ratio of deemed assets to deemed liabilities as per the AER's Licensee Liability Rating was 4.7 at the end of the first quarter.

  • Production averaged 10,240 boe/d in the first quarter of 2019, down 20% from the comparable period in 2018. The decrease was driven by natural declines resulting from limited capital investment on the Company's natural gas assets during 2018, to preserve value during this period of depressed natural gas pricing in Alberta. Production was 8% higher than the fourth quarter of 2018, as there were no voluntary market related shut-ins of natural gas during the quarter, and the four well pad that was shut-in by the AER until December 2018 was back on production for the entire first quarter.

  • Heavy oil production in Eastern Alberta was up 30% to 1,113 bbl/d (11% of production) relative to the comparative 2018 period (Q1 2018 – 7% of production), as capital spending in the second half of 2018 was focused on heavy oil waterflood and development drilling in the Mannville area where return on capital is anticipated to be significantly higher than expected natural gas focused investment returns that sell into current AECO hub forward market prices. Heavy oil exploration and development activities will recommence once weather permits after spring break-up.  

  • Production and operating expenses were up by $0.5 million relative to the 2018 first quarter, attributable to the increase in Eastern Alberta heavy oil production. West Central production and operating expenses were essentially flat relative to the first quarter of 2018 at $2.0 million, but up on a unit-of-production basis to $2.60/boe (Q1 2018 - $2.05/boe), illustrating the largely fixed cost nature of the East Edson property.

Financial Highlights

  • Realized revenue was $24.24/boe in the first quarter of 2019, 16% higher than the comparative period of 2018 ($20.96/boe). The increase was due largely to the 34% increase in Perpetual's realized natural gas price to $3.54/Mcf and a higher proportion of oil and NGL in the production mix (Q1 2019 – 19%; Q1 2018 – 14%), which more than offset the decline in realized crude oil and NGL prices.

    • Natural gas revenue decreased 4% from $15.5 million in the first quarter of 2018, reflecting the impact of the 24% decrease in natural gas production volumes driven by natural declines following limited capital investment in East Edson during 2018. Higher realized natural gas prices were the result of a 26% increase in the AECO Daily Index, combined with the positive impact of the Company's market diversification contract, which contributed $3.5 million of incremental revenue ($0.77/Mcf) over the AECO Daily Index price in the quarter (Q1 2018 - $2.4 million and $0.41/Mcf). Perpetual's market diversification contract enabled the Company to sell approximately 72% of its natural gas production (adjusted for heat content) to markets priced at five pricing hubs outside of Alberta, and provided a 29% uplift over average AECO Daily Index prices during the first quarter (Q1 2018 – 20%).

    • Oil revenue was 44% higher than the same period in 2018, due to the 25% increase in crude oil production which more than offset a 15% decrease in the realized oil price. Compared to the first quarter of 2018, the Western Canadian Select ("WCS") average price of $56.67/bbl increased by 17%, mainly due to the tightening of the WCS differential by US$11.99/bbl in response to the Alberta government's introduction of production quotas effective January 1, 2019. Perpetual did not fully participate in the improved WCS differential, as hedges were in place protecting a WCS differential of US$25.22/bbl on 750 bbl/d for 2019.

    • NGL revenue decreased by 48% over the prior year period while NGL production decreased only 7%, reflecting the 44% decrease in Perpetual's realized NGL price compared to the prior year period. Propane and butane prices have become disconnected from WTI light oil prices in recent months, reflecting excess supply produced from Western Canada and the United States. This oversupply condition is expected to continue.

  • Perpetual's operating netback of $12.3 million in the first quarter of 2019 decreased 17% from $14.8 million in the comparative period of 2018. This decrease was due to the 20% decrease in production caused by natural declines at East Edson, combined with increased higher cost Eastern Alberta heavy oil production and increased royalties due to higher natural gas prices. On a unit-of-production basis, the operating netback per boe increased 4% to $13.36/boe (Q1 2018 – $12.87/boe), reflecting a 16% increase in realized revenue per boe due to improved natural gas pricing, which more than offset the lower realized crude oil and NGL prices, offset by higher cash costs.

  • Net loss for the first quarter of 2019 was $4.9 million ($0.08/share), compared to a net loss of $6.5 million ($0.11/share) in the comparative period of 2018. The decrease in net loss from the prior year period was due to the change in fair value of the TOU share investment, which increased by $6.1 million in the first quarter of 2019 compared to a decrease of $1.6 million in the comparative period of 2018. This was partially offset by a $5.8 million reduction in the fair value of derivatives compared to the prior year period, attributable to the reduction in future NYMEX natural gas prices and an increase in future oil prices during the first quarter of 2019.

  • Cash flow from operating activities in the first quarter of 2019 was $9.3 million ($0.15/share), down $1.9 million from the prior year period of $11.2 million ($0.19/share) due to the impact of a 20% decrease in production, as the changes in fair value of the TOU share investment and derivatives that impacted net loss did not impact cash flow from operating activities.

  • Adjusted funds flow in the first quarter of 2019 was $6.4 million ($0.11/share), down $2.7 million (30%) from the prior year period of $9.1 million ($0.15/share) due to lower cash flow from operating activities and a $0.4 million change in non-cash working capital. Adjusted funds flow was $6.90/boe in the first quarter of 2019, down 13% from the prior year period of $7.94/boe as the impact of higher production and operating costs, combined with lower production, was only partially offset by a 16% increase in realized revenue per boe.

  • At March 31, 2019, Perpetual had total net debt of $102.4 million, down $10.2 million (9%) from December 31, 2018. The decrease in net debt was mainly attributable to the $6.1 million increase in the fair value of TOU shares during the first quarter of 2019, combined with net cash flow from operations which exceeded capital expenditures during the period.

  • On March 27, 2019, the $55 million reserve-based credit facility borrowing limit (the "Borrowing Limit") was confirmed by the Company's lenders and the maturity was extended to November 30, 2020. The Credit Facility will revolve until May 31, 2020 and may be extended for a further 364-day period subject to approval by the Company's lenders.

  • As at March 31, 2019, 61% of net debt outstanding was repayable in 2021 or later. During the three months ended March 31, 2019, Perpetual's net debt to trailing twelve-months adjusted funds flow was unchanged at 3.7 times (December 31, 2018 – 3.7 times).

  • Perpetual had available liquidity at March 31, 2019 of $31.8 million, comprised of an unutilized revolving bank debt Borrowing Limit of $11.7 million and the market value of its Tourmaline Oil Corp. ("TOU") share investment, net of the principal amount of the associated TOU share margin demand loan, of $20.1 million.

  • Perpetual's Application for Summary Dismissal of the Sequoia litigation was heard during the fourth quarter of 2018. There were no developments during the first quarter of 2019 concerning this litigation. The Court's decision is anticipated to be received in the second quarter of 2019.

EARLY REDEMPTION OF 2019 SENIOR NOTES

On May 7, 2019, Perpetual announced it will early redeem the $14.6 million 8.75% senior unsecured notes due July 23, 2019 (the "2019 Senior Notes"), effective June 11, 2019 for $1,000 for each $1,000 principal amount of 2019 Senior Notes (the "Cash Consideration"), or $1,075 principal amount of 8.75% senior unsecured notes due January 23, 2022 (the "2022 Senior Notes"). A significant shareholder will backstop the Cash Consideration such that the redemption of the $14.6 million 2019 Senior Notes will be fully funded, and result in the issuance of $15.7 million 2022 Senior Notes.

OUTLOOK

Perpetual's 2019 capital expenditure and adjusted funds flow guidance remains unchanged from guidance released with its 2018 year-end results on March 27, 2019.

The Company's Board of Directors has approved a total capital spending program of $21 to $25 million for 2019 to be funded from adjusted funds flow. At least 50% will be spent in Eastern Alberta, primarily targeting heavy oil development at Mannville along with abandonment and reclamation work of up to $2 million to prudently address decommissioning obligations associated with non-producing wells. The remaining expenditures will be concentrated in East Edson, developing liquids-rich natural gas reserves in the Wilrich formation if AECO forward gas prices support investment in the second half of 2019, or alternatively, will be deployed in an expanded heavy oil drilling program.

Forecast capital activity in Eastern Alberta for 2019 includes the drilling of up to 10 (10.0 net) horizontal wells, including several multi-lateral wells, targeting a mix of step outs, exploratory wells, and infill wells in waterflooded pools. Timing for start-up of the 2019 program is dependent on surface lease conditions, but is expected to be in June or early July to take advantage of lower drilling, completion, and equipping costs generally realized in the summer in Eastern Alberta. Decommissioning expenditures will continue to be focused in the Mannville area and are expected to provide future surface lease rental and property tax expense reductions while maintaining regulatory compliance. In Eastern Alberta, production is forecast to increase by 20% to 30% from 2018, to a range of 2,200 to 2,400 boe/d (61% oil) in 2019.

At East Edson, the Company has budgeted a two (2.0 net) well drilling program to come onstream during the fourth quarter of 2019. The two wells will be extended reach horizontal ("ERH") wells, as the performance of the ERH wells drilled in late 2017 and early 2018 indicate improved capital efficiencies over the wells drilled with less than 2,500 meters of lateral length. If AECO forward gas prices normalize above $2.00/Mcf, drilling activities are expected to continue into 2020. Processing capacity at the Company's 100% working interest and operated West Wolf Lake facility is 65 MMcf/d, with an additional 13 MMcf/d of working interest capacity at the non-operated Rosevear plant, plus associated liquids. The planned drilling will not have a material impact on production in 2019, as new wells are forecast to come on stream late in the year. Natural declines and capital spending deferrals to late 2019 result in lower anticipated 2019 production in East Edson with an average of 7,000 to 7,200 boe/d (10% oil and NGL). Despite reduced production in East Edson and a substantially fixed operating cost base, operating costs are forecast to remain low in 2019, at less than $3.25/boe.

The table below summarizes anticipated capital spending and drilling activities for the first and second half of 2019.

2019 Exploration and Development Forecast Capital Expenditures


Q1 2019

($ millions)

# of wells

(gross/net)

Q2 – Q4 2019

($ millions)

# of wells

(gross/net)

West Central liquids-rich gas

0.7

0/0.0

11.3

2/2.0

Eastern Alberta

0.5

0/0.0

10.5

10/10.0

Total(1)

1.2

0/0.0

21.8

12/12.0

(1)      

Excludes budgeted abandonment and reclamation spending of $1.5 to $2.0 million in 2019 (Q1 2019 - $0.3 million).

 

Perpetual expects the 2019 capital program will be funded by adjusted funds flow. Perpetual forecasts average production of 9,200 to 9,600 boe/d, with oil and NGL production growing to represent approximately 20% to 24% of the production mix. This represents an expected reduction in average daily production in 2019 of approximately 11% relative to 2018, but includes a 16% increase in oil and NGL production. The Company expects to exit the year at over 11,500 boe/d as natural gas and NGL production ramps up again driven by the second half capital spending program targeting seasonal natural gas price optimization.

Cash costs of $17.00 to $18.00/boe are forecast for 2019, up approximately 13% to 16% from 2018 due to the impact of lower forecast 2019 production on a substantially fixed operating cost base. Increased oil production in 2019, which is higher cost compared to natural gas cash costs, is also expected to contribute to the increase in 2019 cash costs per boe.

Perpetual has diversified its commodity and natural gas pricing point exposure (net of royalties) away from AECO as detailed below:

Market/Pricing Point

Natural gas

Estimated 2019 Exposure

AECO(1)

AECO - fixed price(2)

11%

Empress

7%

Dawn

14%

Michcon

9%

Chicago

21%

Malin

18%

Total natural gas

80%

Natural gas liquids - Condensate(1)

3%

Natural gas liquids - Other(1)

2%

Crude oil(1)(2)

15%

Total forecast production, net of royalties

100%

(1) 

Net of royalties.

(2)  

See "Commodity price risk management and sales obligations" section of the Q1 2019 MD&A for details.

 

The market diversification contract is expected to continue to provide higher natural gas pricing and enhanced risk management through future periods of volatile natural gas prices in Western Canada related to market access constraints.

Guidance assumptions are as follows:


2019 Annual Guidance

2019 exploration and development expenditures ($ millions)

$21 - $25

2019 cash costs ($/boe)

$17.00 - $18.00

2019 average daily production (boe/d)

9,200 – 9,600

2019 average production mix (%)

20% - 24% oil and NGL

2019 adjusted funds flow ($ millions)

$22 - $27

2019 adjusted funds flow ($/share)

$0.36 - $0.44

 

Commodity price assumptions reflect forward market price levels as follows:

Market Prices(1)

Current Guidance

Prior Guidance

2019 average NYMEX natural gas price (US$/MMBtu)

$2.91

$2.99

2019 average West Texas Intermediate ("WTI") oil price (US$/bbl)

$60.65

$56.56

2019 average Western Canadian Select ("WCS") differential (US$/bbl)

($14.26)

($15.88)

2019 average exchange rate (US$1.00 = Cdn$)

1.33

1.34

(1)

Reflects settled and forward market prices.

 

Year-end 2019 net debt (net of the estimated market value of the Company's TOU share investment of approximately $35 million), is forecast at $107 - $113 million, consistent with prior 2019 guidance issued on March 27, 2019. Current guidance is based on the following assumptions:

  • Net debt at March 31, 2019 of $102.4 million;
  • Forecast adjusted funds flow for the remainder of 2019 of $16 to $21 million;
  • Forecast capital spending for the remainder of 2019 of $20 to $24 million; and
  • Forecast decommissioning expenditures for the remainder of 2019 of $1.2 to $1.7 million.

The following sensitivities can be applied to estimate changes to annualized cash flow from operating activities and adjusted funds flow, assuming no change in differentials to Perpetual's market pricing points:

  • For every US$0.25/MMBtu increase or decrease in the NYMEX Daily Index price, annualized adjusted funds flow increases or decreases by $4.8 million;
  • For every US$2.50/bbl increase or decrease in the WTI light oil price, annualized adjusted funds flow increases or decreases by $1.5 million;
  • For every 2.5 MMcf/d increase or decrease in average natural gas production, annualized adjusted funds flow increases or decreases by $1.6 million;
  • For every 100 bbl/d increase or decrease in average crude oil and NGL production, annualized adjusted funds flow increases or decreases by $1.8 million; and
  • For every $0.05 increase or decrease in the Cdn$/US$ exchange rate, annualized adjusted funds flow increases or decreases by $1.5 million.

Financial and Operating Highlights

Three months ended March 31,

($Cdn thousands except volume and per share amounts)

2019

2018

 Change

Financial




Oil and natural gas revenue

22,199

23,340

(5%)

Net loss

(4,892)

(6,465)

24%

Per share – basic and diluted(2)

(0.08)

(0.11)

27%

Cash flow from operating activities

9,292

11,198

(17%)

Adjusted funds flow(1)

6,362

9,101

(30%)

Per share – basic and diluted(1)(2)

0.11

0.15

(27%)

Total assets

328,495

363,273

(10%)

Revolving bank debt

39,598

46,912

(16%)

Term loan, principal amount

45,000

45,000

TOU share margin demand loan, principal amount

14,100

15,990

(12%)

Senior Notes, principal amount

32,490

32,490

TOU share investment

(34,196)

(36,434)

(6%)

Adjusted working capital deficiency (surplus)(1)

5,364

11,101

(52%)

Net debt(1)

102,356

115,059

(11%)

Capital expenditures

1,238

14,897

(92%)

Net payments on acquisitions and dispositions

926

(100%)

Net capital expenditures

1,238

15,823

(92%)

Common shares (thousands)(3)




End of period

60,037

59,847

Weighted average - basic and diluted

60,111

59,345

1%

Operating




Daily average production




Natural gas (MMcf/d)

50.0

65.9

(24%)

Oil (bbl/d)

1,121

900

25%

NGL (bbl/d)

785

848

(7%)

Total (boe/d)

10,240

12,742

(20%)

Average prices




Realized natural gas price ($/Mcf)

3.54

2.65

34%

Realized oil price ($/bbl)

41.12

48.31

(15%)

Realized NGL price ($/bbl)

32.16

57.61

(44%)

Wells drilled – gross (net)




Natural gas

- (-)

1 (1.0)


Oil

- (-)

3 (3.0)


Total

- (-)

4 (4.0)


(1) 

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

(2) 

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

(3)

All common shares are net of shares held in trust (Q1 2019 – 0.9 million; Q1 2018 – 0.3 million). See "Note 15 to the condensed interim consolidated financial statements".

 

ADDITIONAL INFORMATION

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, 2018 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", "cash costs", "net working capital deficiency (surplus)", "net debt", "net bank debt", "net debt to adjusted funds flow ratio", "operating netback", "realized revenue" and "enterprise value" 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.

Adjusted funds flow: 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 (used in) 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 is variable. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company's operating areas. Expenditures on decommissioning obligations are managed through the 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 received. 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 surplus office lease obligations, which management considers to not be related to cash flow from operating activities.

Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating income (loss) 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 the period.

Available Liquidity: Available Liquidity is defined as Perpetual's Credit Facility Borrowing Limit, plus Tourmaline Oil Corp. ("TOU") share investment, less borrowings and letters of credit issued under the Credit Facility and TOU share margin demand 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 income. Cash costs per boe is calculated by dividing cash costs by total production sold in the period.

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 associated with the disposition of the shallow gas assets on October 1, 2016 (the "Shallow Gas Disposition"). Realized revenue, including foreign exchange and market diversification 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, basis differentials, and forward foreign exchange sales. These contracts are put in place to protect Perpetual's adjusted funds flow from potential volatility in commodity prices and foreign exchange rates, and as such, any related realized gains or losses are considered part of the Corporation's realized price.

Operating netback: Perpetual considers operating netback to be an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated by deducting royalties, production and operating, and transportation costs 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.

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 demand loan, current portion of senior notes, current portion of lease liabilities, revolving bank debt, and current portion of provisions.

Net bank debt, net debt and net debt to adjusted funds flow ratio: Net bank debt is measured as current and long-term revolving bank debt 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 demand loan and the principal amount of senior notes, reduced for the mark-to-market value of the TOU share investment. Net debt, net bank debt and net debt to adjusted funds flow ratios are used by management to assess the Corporation's overall debt position and borrowing capacity. Net debt to adjusted funds flow ratios are calculated on a trailing twelve-month basis.

Enterprise value: Enterprise value is equal to net debt plus the market value of issued equity and is used by management to analyze leverage. Enterprise value is not intended to represent the total funds from equity and debt received by the Corporation upon issuance.

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.

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:

bbls 

barrels

boe

barrels of oil equivalent

Mcf 

thousand cubic feet

MMcf 

million cubic feet

MMBtu

million British Thermal Units

GJ

gigajoules

Financial Outlook

Also included in this news release are estimates of Perpetual's 2019 adjusted funds flow and year-end 2019 net debt, which is based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on May 7, 2019 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.

SOURCE Perpetual Energy Inc.

For further information: Perpetual Energy Inc., Suite 3200, 605 - 5 Avenue SW Calgary, Alberta, Canada, T2P 3H5, Telephone: 403 269-4400, Fax: 403 269-4444, Email: info@perpetualenergyinc.com; Susan L. Riddell Rose, President and Chief Executive Officer; W. Mark Schweitzer, Vice President Finance and Chief Financial Officer