Perpetual Energy : 2020 Q4 Management's Discussion and Analysis

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is management's discussion and analysis ("MD&A") of Perpetual Energy Inc.'s ("Perpetual", the "Company" or the "Corporation") operating and financial results for the year ended December 31, 2020 as well as information and estimates concerning the Corporation's future outlook based on currently available information. This discussion should be read in conjunction with the Corporation's audited consolidated financial statements and accompanying notes for the years ended December 31, 2020 and 2019. The Corporation's consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP") which require publicly accountable enterprises to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Readers are referred to the advisories for additional information regarding forecasts, assumptions and other forward-looking information contained in the "Forward Looking Information and Statements" section of this MD&A. The date of this MD&A is February 24, 2021.

NATURE OF BUSINESS: Perpetual is an oil and natural gas exploration, production and marketing company headquartered in Calgary, Alberta. Perpetual owns a diversified asset portfolio, including liquids-rich conventional natural gas assets in the deep basin of West Central Alberta, heavy crude oil and shallow conventional natural gas in Eastern Alberta, and undeveloped bitumen leases in Northern Alberta. Additional information on Perpetual, including the most recently filed Annual Information Form ("AIF"), can be accessed atwww.sedar.comor from the Corporation's website atwww.perpetualenergyinc.com.

ADVISORIES

NON-GAAP MEASURES: The terms "adjusted funds flow", "adjusted funds flow per share", "adjusted funds flow per boe", "available liquidity", "cash costs", "net working capital deficiency", "net debt", "net bank debt", "net debt to adjusted funds flow ratio", "operating netback", "realized revenue", and "enterprise value" used in this MD&A are not recognized under GAAP. Management believes that in addition to net income (loss) and net cash flows from (used in) operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from (used in) 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: 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 added back non-cash oil and natural gas revenue in-kind, equal to retained East Edson royalty obligation payments taken in-kind, to present the equivalent amount of cash revenue generated. The Company has also deducted payments of the gas over bitumen royalty financing from adjusted funds flow 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 employee downsizing costs, which management considers to not be related to cash flow from (used in) operating activities. 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 per share is calculated using the weighted average number of shares outstanding used in calculating net 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.

The following table reconciles net cash flows from (used in) operating activities to adjusted funds flow:

Three months ended December 31, Years ended December 31,

($ thousands, except per share and per boe amounts)	2020	2019	2020	2019
Net cash flows from (used in) operating activities	(1,104)	(1,290)	(9,533)	17,806
Change in non-cash working capital	1,479	705	(1,015)	(4,602)
Decommissioning obligations settled	95	540	210	1,733
Oil and natural gas revenue in-kind	917	-	2,319	-
Payments of gas over bitumen royalty financing	(197)	(225)	(704)	(1,013)
Payments of restructuring costs	50	610	936	610
Adjusted funds flow	1,240	340	(7,787)	14,534
Adjusted funds flow per share	0.02	0.01	(0.13)	0.24
Adjusted funds flow per boe	2.85	0.46	(4.25)	4.43

Available Liquidity: Available Liquidity is defined as Perpetual's reserve-based credit facility (the "Credit Facility") borrowing limit (the "Borrowing Limit"), less borrowings and letters of credit issued under the Credit Facility. Management uses available liquidity to assess the ability of the Company to finance capital expenditures and expenditures on decommissioning obligations, and to meet its financial obligations.

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

Three months ended December 31,

Years ended December 31,

($ thousands, except per boe amounts)	2020	2019	2020	2019
Royalties	1,831	3,383	6,571	11,260
Production and operating	3,014	3,839	11,634	18,332
Transportation	804	1,551	3,617	6,258
General and administrative	1,994	2,406	7,870	11,660
Cash finance expense	155	2,376	6,587	9,280
Cash costs	7,798	13,555	36,279	56,790
Cash costs per boe	17.92	18.44	19.78	17.31

Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue, and realized natural gas liquids ("NGL") revenue which includes realized gains (losses) on financial natural gas, crude oil, NGL, and foreign exchange contracts. Realized revenue is used by management to calculate the Corporation's net realized commodity prices, taking into account the monthly settlements of 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. Any related realized gains or losses are considered part of the Corporation's realized price.

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

Net working capital deficiency: Net working capital deficiency includes total current assets and current liabilities excluding short-term derivative assets and liabilities related to the Corporation's risk management activities, Tourmaline Oil Corp. ("TOU") share investment, TOU share margin demand loan, revolving bank debt, second lien term loan (the "Term Loan"), current portion of royalty obligations, current portion of lease liabilities, 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. 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.

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 conventional natural gas of 6 Mcf:1 bbl 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 conventional natural gas and heavy crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl. A conversion ratio of 1 bbl of heavy crude oil to 1 bbl of NGL has also been used throughout this MD&A. Refer to the "Production" section of this MD&A for details of constituent product components that comprise Perpetual's boe production.

FOURTH QUARTER 2020 HIGHLIGHTS

Fourth quarter production averaged 4,730 boe/d, down 41% from the comparative period of 2019 (Q4 2019 - 7,991 boe/d). The decrease in production was due to the sale of a 50% working interest in the East Edson property in West Central Alberta to a third-party (the "Purchaser") for consideration including a cash payment of $35 million and the carried interest funding of the drill, complete and tie-in costs for an eight well drilling program (the "East Edson Transaction"). The closing of the East Edson Transaction on April 1, 2020 reduced West Central production by 3,220 boe/d when compared to the fourth quarter of 2019. Compared to the third quarter of 2020, total production increased by 13% or 542 boe/d, as production from the first five (2.5 net) East Edson carried interest wells is now online. In addition, the Company continued to reactivate heavy crude oil production as oil prices recover and stabilize. As of December 31, 2020, Perpetual had restarted all heavy crude oil production with the exception of approximately 185 bbl/d of higher cost production from certain wells at Mannville. Drilling of two (1.0 net) additional East Edson carried interest wells commenced in late January 2021 and are forecast to be on production by the end of March 2021. The final carried interest well is expected to be drilled and on production in the third quarter of 2021.

Realized revenue was $21.73/boe in the fourth quarter of 2020, 11% higher than the comparative period of 2019 (Q4 2019 - $19.50/boe). The increase was due primarily to the 20% improvement in Perpetual's realized oil price to $52.60/bbl, bolstered by financial hedging gains of $2.2 million ($18.92/boe). Compared to the prior year period, realized natural gas prices of $1.46/Mcf were 27% lower, due to realized hedging losses on locked-in AECO-NYMEX basis differential contracts of $2.6 million ($1.46/Mcf) despite the 6% increase in both NYMEX and AECO reference prices over the same period. In the fourth quarter of 2020, the Company reduced its fixed volume obligations under its market diversification contract by 14,600 MMBtu/d for the period commencing November 1, 2021 and ending on October 31, 2022 to align conventional natural gas sales obligations with lower forecast production volumes following the East Edson Transaction. The modification resulted in a realized gain on derivatives of $0.5 million ($1.15/boe) and increased the Company's realized natural gas price by $0.28/Mcf in the fourth quarter of 2020. Compared to the third quarter of 2020, realized revenue of $21.73/boe was up 21% (Q3 2020 - $17.93/boe), reflecting the 13% quarter-over-quarter increase in production combined with higher realized natural gas and NGL prices, partially offset by lower realized heavy crude oil prices.

Cash costs were down 3% on a unit-of-production basis to $17.92/boe (Q4 2019 - $18.44/boe). On an absolute dollar basis, cash costs were $7.8 million, 42% lower than the prior year period (Q4 2019 - $13.6 million) due to the East Edson Transaction, the reduction in work hours and corresponding employee compensation to 80% effective April 1, 2020, and payments received from the Canada Emergency Wage Subsidy

("CEWS") and Canada Emergency Rent Subsidy ("CERS") of $0.3 million. In addition, the semi-annual interest payment of $1.8 million that was payable December 31, 2020, was deferred by the Company's Term Loan lender and added to the principal amount owing as a condition of the Credit Facility lenders agreeing to extend the Credit Facility maturity to March 1, 2021.

Net income for the fourth quarter of 2020 was $14.4 million ($0.24/share), up $46.9 million from the prior year period (Q4 2019 - net loss of $32.5 million and $0.54/share). The increase was due primarily to the non-cash impairment reversal of $18.0 million recognized in the fourth quarter of 2020, compared to an impairment charge of $24.5 million in the fourth quarter of 2019. In addition, the change in fair value of derivatives contributed $0.4 million to net income in the fourth quarter of 2020, $5.3 million higher than the prior year period (Q4 2019 - loss of $4.9 million).

Net cash flows used in operating activities were $1.1 million, comparable to the prior year period of $1.3 million. Changes in non-cash working capital reduced operating cash flows by $1.5 million in the fourth quarter of 2020 compared to a reduction of $0.7 million in the comparative period of 2019. Excluding changes in non-cash working capital, net cash flows from operating activities were $0.4 million, an increase of $1.0 million from the prior year period, due primarily to the deferral of $1.8 million of Term Loan interest, partially offset by the 41% decrease in production.

Adjusted funds flow in the fourth quarter of 2020 was $1.2 million ($0.02/share), $0.9 million higher than the prior year period (Q4 2019 - $0.3 million). The increase was due to the same factors that drove higher cash flows from operating activities before changes in non-cash working capital. Compared to the third quarter of 2020, adjusted funds flow improved by $3.3 million, due to the deferral of $1.8 million of Term Loan interest, combined with the 13% increase in production and significantly higher realized natural gas prices of $1.46/Mcf (Q3 2020 - $0.06/Mcf).

2020 ANNUAL HIGHLIGHTS

Exploration and development spending in 2020 was $6.0 million, down 54% from the prior year (2019 - $12.9 million). Capital investment was focused on the Clearwater play in Eastern Alberta, where total spending of $5.5 million included costs to drill, complete and tie-in four (4.0 net) heavy crude oil wells in the Ukalta area. The program successfully demonstrated enhanced capital efficiency and performance, de-risked additional development drilling inventory, and resulted in finding and development costs ("F&D") of $9.26/boe (2019 - $17.27/boe) on a proved and probable basis, including changes in future development capital ("FDC"). The Clearwater drilling program, combined with better than forecast well performance and farm-in arrangements, contributed to a year-over-year increase in Clearwater proved plus probable reserves of 2.7 million bbls, representing 10% of total Company reserves at December 31, 2020 (2019 - 1%).

In accordance with the terms of the East Edson Transaction, the Purchaser drilled, completed and tied-in five (2.5 net) horizontal Wilrich carried interest wells during the year at the 50% owned East Edson property, with the next two (1.0 net) wells forecast to be on production by the end of March 2021. The final carried interest well is scheduled to be drilled, completed and tied-in during the third quarter of 2021. The East Edson development plan has been revised to reflect increased well spacing, longer extended-reach wells, and reduced capital costs per well related to the Purchaser's scale of operations as demonstrated by the execution of the 2020 carried interest drilling program. After giving effect to the East Edson Transaction, East Edson FDC decreased by 63% or $102.9 million on a proved plus probable basis, while proved reserves have increased by 8% from prior year levels.

Production in 2020 averaged 5,012 boe/d (29% heavy crude oil and NGL), a decrease of 44% from 8,988 boe/d (22% heavy crude oil and NGL) in 2019. The decrease in production was due primarily to the closing of the East Edson Transaction, combined with the temporary shut-in of heavy crude oil production throughout the second quarter in response to the abrupt drop in oil prices experienced due to local and global supply and demand imbalances and the COVID-19 pandemic. As Western Canadian Select ("WCS") prices improved from their April lows, the Company began reactivating certain low-cost heavy crude oil production in mid-May 2020, and has continued to ramp up production as oil prices improve. Approximately 185 bbl/d of higher cost heavy crude oil production remains shut-in at Mannville.

Realized revenue was $30.2 million in 2020, down $43.4 million (59%) from $73.6 million in 2019 due to the combined effect of the 44% decrease in annual production and lower realized revenue per boe. On a unit-of-production basis, realized revenue was $16.46/boe, 27% lower than the prior year period (2019 - $22.43/boe) and due primarily to lower realized natural gas and NGL prices of 69% and 23%, respectively. Compared to the AECO Daily Index price of $2.23/Mcf, realized natural gas prices were negatively impacted by physical and financial hedging losses of $12.0 million ($1.53/Mcf) which were primarily related to AECO-NYMEX basis differentials, and included a net loss of $0.5 million ($0.06/Mcf) related to modifications made to the natural gas market diversification contract. Market diversification contract revenue further reduced the realized natural gas price by $0.7 million or $0.09/Mcf in 2020, compared to an increase of $0.64/Mcf in 2019. For the year ended December 31, 2020, Perpetual's realized oil price was $49.37/bbl, up 10% from $44.87/bbl in 2019. Realized oil prices were improved by $19.05/bbl associated with realized hedging gains during the year (2019 - realized losses of $8.74/bbl).

Cash costs were $36.3 million in 2020, down $20.5 million (36%) from 2019. The decrease was due primarily to lower royalties, production and operating expenses and transportation costs associated with the 44% decrease in production, combined with lower general and administrative expense driven by a 25% reduction in Perpetual's corporate employee head count that was implemented late in the third quarter of 2019, along with the reduction in work hours and corresponding employee compensation to 80%, effective April 1, 2020. In 2020, the Company received total payments of $1.3 million from the CEWS and CERS programs which were recognized as a reduction to general and administrative and production and operating expenses of $1.0 million and $0.3 million, respectively (2019 - nil). The deferral of Term Loan interest also reduced cash finance expense by $1.8 million during the year.

The net loss for 2020 was $61.6 million ($1.01/share), down from $94.0 million in 2019 ($1.56/share). The net loss in 2020 was impacted by aggregate non-cash impairment charges of $42.5 million (2019 - $47.1 million), comprised of $60.5 million of impairment charges booked at March 31, 2020, partially offset by an $18.0 million impairment reversal recorded at December 31, 2020. The net loss also included an unrealized loss of $0.9 million related to the change in fair value of the TOU share investment (2019 - $3.2 million) which was sold in the first quarter of 2020.

Net cash flows used in operating activities were $9.5 million in 2020, down $27.3 million compared to cash flows from operating activities of $17.8 million in 2019. The decrease was due primarily to the $43.4 million reduction in realized revenue, partially offset by a $20.5 million reduction in cash costs.

For the year ended December 31, 2020, adjusted funds flow was negative $7.8 million ($0.13/share), down $22.3 million from $14.5 million ($0.24/share) in 2019 as the impact of the 44% year-over-year decrease in production combined with lower natural gas and NGL prices outweighed the 36% decrease in cash costs.

FUTURE OPERATIONS

Perpetual has a first lien, reserve-based credit facility (the "Credit Facility"). On December 24, 2019, Perpetual's syndicate of lenders completed their semi-annual borrowing base redetermination, reducing the Credit Facility borrowing limit (the "Borrowing Limit") from $55 million to $45 million effective January 22, 2020.

In January 2020, the Company sold its remaining 1,000,000 TOU share investment for net cash proceeds of $14.3 million. Net proceeds were used to repay the outstanding TOU share margin demand loan of $0.1 million, with the balance applied to the Credit Facility. On April 1, 2020, the Company closed the East Edson Transaction. Net proceeds of $34.8 million were used to repay a portion of the Credit Facility. Effective April 1, 2020, Perpetual's syndicate of Credit Facility lenders completed their borrowing base redetermination, incorporating the impact of the East Edson Transaction. The Borrowing Limit was reduced from $45 million to $20 million. As at December 31, 2020, $17.5 million was borrowed and $0.9 million of letters of credit were issued on the Credit Facility. The next Borrowing Limit redetermination is scheduled on or prior to March 1, 2021. If not extended by March 1, 2021, the Credit Facility will cease to revolve, and all outstanding advances will be repayable. The semi-annual interest payment of $1.8 million that was payable December 31, 2020, was deferred by the Company's Term Loan lender and added to the principal amount owing as a condition of the Credit Facility lenders agreeing to extend the Credit Facility maturity to March 1, 2021. The further extension of the Credit Facility repayment term is dependent on the Company's ability to repay or extend the term of the $45 million second lien Term Loan and deferred interest that matures and requires repayment on March 14, 2021. The Company remains dependent on the continued support of its lenders to extend approaching maturities.

During the year ended December 31, 2020, there was a dramatic decline in oil, natural gas, and NGL commodity prices due to local and global supply and demand imbalances and the COVID-19 pandemic. This contributed to a net working capital deficiency of $7.1 million as at December 31, 2020 and a $9.5 million use of cash from operations for the year then ended. The Company will require additional financing to fund the working capital deficiency and future operations, and to refinance the upcoming Credit Facility and Term Loan maturities as the available liquidity and operating cash flows are not anticipated to be sufficient. In January 2021, the Company exchanged it's $33.6 million 8.75% unsecured senior notes due January 23, 2022 for new $33.6 million 8.75% third lien senior notes due January 23, 2025 (the "2025 Senior Notes"). Interest on the 2025 Senior Notes may be paid in-kind at the option of the Company by adding the interest payment to the principal amount owing. On January 23, 2021, the $1.5 million semi-annual interest payment on the 2025 Senior Notes was paid in-kind. Although cash flows from operations are forecast to improve for the next twelve-month period, Perpetual is considering other options including the extension of existing debt maturity dates, alternative financing, and the sale or monetization of additional assets.

Due to the facts and circumstances detailed above, coupled with considerable economic instability and uncertainty in the oil and gas industry which negatively impacts operating cash flows and lender and investor sentiment, there remains considerable risk around the Company's ability to address its liquidity shortfalls and upcoming maturities. In addition, there continues to be some uncertainty regarding the Statement of Claim which may restrict the Company's ability to manage its capital structure. As a result, there is material uncertainty surrounding the Company's ability to continue as a going concern that creates significant doubt as to the ability of the Company to meet its obligations as they come due. Therefore, the Company may be unable to realize its assets and discharge its liabilities in the normal course of business.

Perpetual's financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that the Corporation will be able to realize its assets and discharge its liabilities in the normal course of business. These financial statements do not reflect adjustments that would be necessary if the going concern assumption were not appropriate. If the going concern basis were not appropriate for these financial statements, then adjustments would be necessary in the carrying value of the assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used. These adjustments could be material.

SEQUOIA LITIGATION UPDATE

On January 13, 2020, the Court of Queen's Bench (the "Court") issued its written decision related to the Statement of Claim filed on August 3, 2018 against Perpetual and its President and Chief Executive Officer ("CEO") (the "Sequoia Litigation") with respect to the Company's disposition of shallow conventional natural gas assets in Eastern Alberta to an unrelated third party on October 1, 2016 (the "Sequoia Disposition"). The decision dismissed and struck all claims against the Company's CEO and all but one of the claims filed by PricewaterhouseCoopers Inc. ("PwC") LIT in its capacity as trustee in bankruptcy (the "Trustee") against Perpetual. The Court did not find that the test for summary dismissal relating to whether the asset transaction was an arm's length transfer for purposes of section 96(1) of the Bankruptcy and Insolvency Act (the "BIA") was met, on the balance of probabilities. Accordingly, the BIA claim was not dismissed or struck and only that part of the claim can continue against Perpetual. The Trustee filed a notice of appeal with the Court of Appeal of Alberta, challenging the entire decision, and Perpetual filed a similar notice of appeal contesting the BIA claim portion of the decision (the "First Appeal"). The First Appeal proceedings were heard on December 10, 2020.