Q1 2025 MD&A

For the three months ended March 31, 2025 and 2024

The following management's discussion and analysis ("MD&A") of financial condition and results of operations for Prairie Provident Resources Inc. (the "Company" or "PPR") is dated May 13, 2025 and should be read in conjunction with the Company's unaudited condensed interim consolidated financial statements and related notes for the three months ended March 31, 2025 and 2024 (the "Interim Financial Statements"), the audited consolidated financial statements and related notes for the years ended December 31, 2024 and 2023 (the "Annual Financial Statements"), as well as the Company's annual information form for the year ended December 31, 2024 (the "AIF") that is found on the Company's website at https://www.ppr.ca or on SEDAR+ at https://www.sedarplus.ca. The Interim Financial Statements have been prepared in accordance with IFRS Accounting Standards specifically International Accounting Standard 34, Interim Financial Reporting. International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB") are sometimes referred to in this MD&A as Generally Accepted Accounting Principles ("GAAP").

This MD&A includes references to certain financial and performance measures which do not have standardized meanings prescribed by IFRS ("Non-GAAP"). In addition, this MD&A includes references to certain Non-GAAP financial measures, Non-GAAP financial ratios, capital management measures and supplementary financial measures which are not specified, defined, or determined under IFRS and are therefore considered Non-GAAP and other financial measures. These Non-GAAP and other financial measures might not be comparable to similar financial measures presented by other issuers. For a full description of these Non-GAAP and other financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "Non-GAAP and Other Financial Measures" included in the "Advisories" section in this MD&A.

Readers are cautioned that the MD&A also contains forward-looking statements and should be read in conjunction with PPR's disclosure under "Forward-looking Information" included in this MD&A.

Unless otherwise noted, all financial information provided herein is reported in Canadian dollars. Production volumes are presented on a working-interest basis, before royalties. Certain comparative figures have been reclassified to conform with the presentation adopted in the current period.

Prairie Provident is a Calgary-based company engaged in the exploration and development of crude oil and natural gas properties in Alberta. Additional information regarding PPR is available on SEDAR+ and the Company's website. PPR's Common Shares are listed for trading on the Toronto Stock Exchange under the symbol "PPR".

PPR was incorporated under the laws of the province of Alberta on July 29, 2016. Its principal office is located at #1000, 500 - 4th Ave SW, Calgary, Alberta. In this MD&A, unless otherwise indicated or the context otherwise requires, the terms "we", "us", "our", "PPR", "Prairie Provident" and "the Company" refers to Prairie Provident Resources Inc., as parent corporation, together with its wholly-owned subsidiaries, Prairie Provident Resources Canada Ltd., Lone Pine Resources Inc., Lone Pine Resources (Holdings) Inc., Arsenal Energy USA Inc. and Arsenal Energy Holding Ltd. On May 15, 2023, former Noteholder, PCEP Canadian Holdco, LLC ("PCEP"), acquired a majority interest in PPR following a recapitalization transaction, thereby obtaining control of PPR. PCEP is a subsidiary of Prudential Private Capital, a unit of PGIM, Inc. ("PGIM"), the ultimate parent of PPR.

The following is a list of abbreviations that may be used in this MD&A:

1. Restated. For further information, refer to the "Restatements" section.

2. This is a Non-GAAP and other financial measure. For further information, refer to "Advisories - Non-GAAP and other Financial Measures" below.

3. The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. Per boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel (1 bbl) of crude oil. Refer to "Advisories - Barrels of Oil Equivalent" below.

   FIRST QUARTER 2025 FINANCIAL AND OPERATING HIGHLIGHTS

   Financial and operating highlights for the period include:

   • In February and March of 2025, the Company completed a brokered equity financing raising aggregate gross proceeds of $8.67 million to facilitate further development in the BQ formation at Michichi.

   • In Q1 2025, the Company drilled three gross (3.0 net) new wells in the BQ formation. These wells were completed and brought on production in April 2025.

   • Production averaged 2,221 boe/d (58% liquids) for Q1 2025, which was 16% or 415 boe/d lower than Q1 2024, primarily due to the sale of the Company's former Evi CGU in Q1 2024 and natural production declines.

   • Q1 2025 operating expenses were $29.64 boe/d, a decrease of 17% or $6.15 per boe/d from Q1 2024, principally due to the sale of the Evi CGU and certain Provost properties in Q1 2024 which experienced higher operational costs and partially offset by increases in workover costs.

   • Q1 2025 operating netback1 before the impact of derivatives was $3.7 million ($18.38/boe), and $3.7 million ($18.38/boe) after realized losses on derivatives, a 74% and a 115% increase, respectively, relative to Q1 2024. The increase was a result of slightly higher realized pricing, lower royalties and operating costs and no realized losses on derivatives.

   • Net loss totaled $6.1 million in Q1 2025, a $1.2 million increase compared to Q1 2024. The increase was due to lower petroleum and natural gas sales, higher G&A expenses, impairment expense and finance costs offset by lower operating expenses.

     1 Operating netback is a Non-GAAP financial measure and defined below under "Non-GAAP and Other Financial Measures".

     FINANCIAL REVIEW
     PRODUCTION
     	Q1 2025	Q4 2024	Q1 2024
     Crude oil and condensate (bbl/d)	1,201	1,298	1,495
     Natural gas (Mcf/d)	5,574	6,107	6,498
     Natural gas liquids (bbl/d)	91	69	58
     Total (boe/d)	2,221	2,385	2,636
     % Liquids	58%	57%	59%
     Q1 2025 vs Q4 2024

     • Q1 2025 production was 7% lower due to due to natural production declines.

     Q1 2025 vs Q1 2024

   • Q1 2025 production was 16% lower than prior year due to Q1 2024 Evi disposition and natural production declines offset by new production from the two Basal Quartz wells brought on production in Q4 2024.

     PETROLEUM AND NATURAL GAS SALES
     ($000s, except per unit amounts)	Q1 2025	Q4 2024	Q1 2024
     Petroleum and natural gas sales
     Crude oil and condensate	9,394	9,933	10,987
     Natural gas	1,217	839	1,559
     Natural gas liquids	462	339	450
     Petroleum and natural gas sales	11,073	11,111	12,996
     Realized Prices
     Crude oil and condensate ($/bbl)	86.88	83.16	80.75
     Natural gas ($/Mcf)	2.43	1.49	2.64
     Natural gas liquids ($/bbl)	56.53	53.93	85.21
     Total ($/boe)	55.39	50.65	54.17
     Benchmark Prices
     Crude oil - WTI ($/bbl)	102.46	98.35	103.78
     Crude oil - Canadian Light Sweet ($/bbl)	95.03	92.70	95.47
     Crude oil - WCS ($/bbl)	84.43	81.32	77.80
     Natural gas - AECO 5A ($/Mcf)	1.95	1.32	2.52
     Exchange rate - US$/CDN$	0.70	0.71	0.74

     PPR currently sells its crude oil on a monthly index basis with reference to western Canadian benchmark prices and natural gas production based on AECO prices in Alberta.

     Q1 2025 vs Q4 2024

   • Q1 2025 petroleum and natural gas sales slightly lower due to 7% decrease in production offset by higher commodity prices. PPR realized price in Q1 2025 was 9% higher compared to the prior quarter.

     Q1 2025 vs Q1 2024

   • Q1 2025 petroleum and natural gas sales were 15% lower than prior year due to a 16% decrease in production (mainly due to Q1 2024 Evi and Provost dispositions) offset by incrementally higher realized prices in Q1 2025.

     ROYALTIES
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Royalties	1,472	567	1,871
     Per boe ($)	7.37	2.58	7.80
     Percentage of petroleum and natural gas sales	13.3%	5.1%	14.4%

     The Company pays royalties to respective provincial governments and mineral owners in accordance with established royalty regimes. A large portion of PPR's royalties are paid to the Alberta Crown, which are based on sliding scales that are dependent on incentives, production volumes, realized commodity prices and capital spending.

     Q1 2025 vs Q4 2024

   • Q1 2025 royalties were $0.9 million higher mainly due an adjustment for higher gas cost allowance recovery than previously estimated in Q4 2024. Q1 2025 royalties as a percentage of sales were more in line with historical royalty rates.

     Q1 2025 vs Q1 2024

   • Q1 2025 royalties were 21% lower than the prior year mainly due to a 16% decrease in production as discussed above and the impact of selling the Evi property in Q1 2024 disposition offset by incrementally higher realized prices in Q1 2025.

     GAIN (LOSS) ON DERIVATIVE INSTRUMENTS
     ($000s, except per unit amounts)	Q1 2025	Q4 2024	Q1 2024
     Realized loss on derivative instruments	-	-	(485)
     Per boe ($)	-	-	(2.02)
     Unrealized gain on derivative instruments	-	-	416
     Per boe ($)	-	-	1.73
     Total gain (loss) on derivative instruments	-	-	(69)
     Per boe ($)	-	-	(0.29)

     Realized gains (losses) on derivative instruments represent the cash settlements of outstanding derivative risk management contracts while unrealized gains (losses) on derivative instruments reflect changes in the mark-to-market positions of outstanding derivative risk management contracts in the period. Both realized and unrealized gains (losses) on derivative contracts vary based on fluctuations related to the specific terms of outstanding contracts in the related period including contract types, contract quantities and fluctuations in underlying commodity reference prices.

     Q1 2025 vs Q4 2024 and Q1 2024

   • The Q1 2024 realized loss and unrealized gain on derivative instruments was due to the Company's remaining derivative contracts settled in Q1 2024 and the unwinding of the Company's mark-to-market position as at December 31, 2023.

   • As at March 31, 2025 and December 31, 2024, the Company had no outstanding commodity derivative contracts.

     OPERATING EXPENSES
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Lease operating expense(1)	3,837	4,718	(Restated)(1) 6,287
     Transportation and processing	1,383	1,014	1,435
     Production, property and carbon taxes	704	854	863
     Total operating expenses	5,924	6,586	8,585
     Per boe ($)	29.64	30.02	35.79
     (1) Restated. Refer the "Restatements" section.

     Q1 2025 vs Q4 2024

   • Q1 2025 operating expenses were $0.7 million or 10% lower due to a 7% decrease in production and lower spending with respect to chemicals, regulatory and safety, repairs and maintenance, lease rentals, government taxes and major repair and maintenance costs, however, offset by increases in transportation and processing costs, resulting in operating expenses decreasing by 1% on a per boe basis.

     Q1 2025 vs Q1 2024

   • Q1 2025 operating expenses were $2.7 million or 31% lower relative to the prior year mainly due to a 16% decrease in production (mainly as a result of the Evi and Provost dispositions in Q1 2024) lowering spending with respect to emulsion processing, power costs, labour and vehicle, repairs and maintenance, lease rentals, government taxes and remediation costs, offset by higher workover costs. On a per boe basis, this resulted in a 17% decrease.

1. Operating netback is a Non-GAAP and other financial measure. Refer to "Non-GAAP and other Financial Measures" included in the "Advisories" section.

2. Restated. Refer the "Restatements" section.

1. Refer the "Capital Resources and Liquidity - Shareholders' Equity (Deficit)" section for a breakdown of share-based compensation recognized from the Company's long-term incentive plans.

   The Company's G&A expenses comprises G&A costs, share-based compensation expensed less G&A amounts capitalized to production and development assets and/or E&E assets.

   Capitalized G&A expense varies with the composition and compensation levels of management, technical departments' time attributed to capital projects as well as levels of capital expenditures.

   Q1 2025 vs Q4 2024 and Q1 2024

   • Q4 2024 G&A costs are higher than Q1 2025 and Q1 2024 due to higher professional fees as a result of corporate developments and in preparation for year-end reporting as well as a $0.3 million bad debt expense (Q1 2025 - $0.1 million and Q1 2024 - $nil) due to increasing the allowance for doubtful accounts provision;

   • Q1 2025 includes higher stock-based compensation as a result of a larger grant of Options in late December 2024 to management, directors and employees of PPR; and

   • Capitalized G&A expense increased in Q1 2025 compared to prior quarters as a result of the Company's Basal Quartz drilling program and capital activity.

     DEPLETION AND DEPRECIATION ("D&D")
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Depletion and depreciation of property and equipment	2,367	2,318	2,539
     Depreciation on right-of-use assets	55	75	85
     Total depletion and depreciation expense	2,422	2,393	2,624
     $ per boe	12.12	10.91	10.94

     Depletion and depreciation rates are subject to change based on changes in the carrying amounts of the asset base, changes in future development costs, reserve updates and changes in production by area. Depletion expenses are calculated using depletion rates and production volumes applicable to each depletable asset.

     Q1 2025 vs Q4 2024

   • Q1 2025 D&D is higher mainly due to incremental D&D from the Michichi CGU. Significant reserve additions and additional future development costs from the December 31, 2024 reserve evaluation, together with Q1 2025 capital expenditures on the new Basal Quartz wells, resulted in higher depletion rates and per boe D&D for the Michichi CGU as compared to prior periods.

     Q1 2025 vs Q1 2024

   • Q1 2025 D&D is lower due to a 16% decrease in production (mainly due to Q1 2024 Evi and Provost dispositions), offset by a higher per boe depletion rate for the Michichi CGU in 2025 as described above.

     EXPLORATION AND EVALUATION EXPENSE
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Exploration and evaluation expense	25	19	-
     $ per boe	0.13	0.08	-
     Exploration and evaluation expense is comprised of undeveloped land expiries, derecognized seismic and surrendered leases.
     IMPAIRMENT EXPENSE (IMPAIRMENT REVERSAL)
     ($000s)	Q1 2025	Q4 2024	Q1 2024
     E&E assets impairment (impairment reversal)	894	(2,333)	(51)
     P&D assets impairment	342	7,249	509
     Total impairment expense (impairment reversal)	1,236	4,916	458
     Q1 2025 and as at March 31, 2025

   • E&E assets: At March 31, 2025, the Company had not identified any indicators of impairment or reversal of impairment. In Q1 2025, PPR recognized non-cash E&E impairment expense of $0.9 million for changes in estimates of decommissioning liabilities related to E&E properties that had $nil carrying amount; and

   • P&D assets: At March 31, 2025, the Company had not identified any indicators of impairment or reversal of impairment. In Q1 2025, PPR recognized non-cash property and equipment impairment expense of $0.3 million for changes in estimates of decommissioning liabilities related to P&D properties that had $nil carrying amount.

     FOREIGN EXCHANGE (GAIN) LOSS
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Realized loss (gain) on foreign exchange (gain) loss	(8)	211	(Restated)(1) 522
     Unrealized foreign exchange (gain) loss	-	-	35
     Foreign exchange (gain) loss	(8)	211	557
     $ per boe	(0.04)	0.96	2.32
     (1) Restated. Refer the "Restatements" section.

     Foreign exchange (gain) loss recognized relates mainly to the change in exchange rates on the translation of US dollar denominated borrowings to CAD (see "Capital Resources and Liquidity" section below).

     FINANCE COSTS
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Interest expense and finance costs - Debt	3,553	3,472	2,878
     Interest expense - Lease liabilities	113	126	205
     Interest expense - Other	7	7	8
     Interest expense - Debt modification and warrant liabilities	-	-	23
     Total interest expense	3,673	3,605	3,114
     Interest income	(16)	(53)	-
     Accretion expense - Decommissioning liabilities	602	592	773
     Accretion expense - Other liabilities	15	69	-
     Total finance costs	4,274	4,213	3,887
     $ per boe	21.38	19.20	16.21

     The Company's finance costs include interest expense and accretion expense, net of interest income.

     Q1 2025 vs Q4 2024 and Q1 2024

   • Q1 2025 finance costs higher mainly due to higher principal debt levels in the quarter (see "Debt" section); and

   • Q1 2025 accretion expense of decommissioning liabilities lower than Q1 2024 mainly due to lower decommissioning liabilities as a result of the Q1 2024 Evi and Provost dispositions.

     OTHER EXPENSES (INCOME)
     ($000s, except per boe amounts)	Q1 2025	Q4 2024	Q1 2024
     Other income	-	(23)	-
     Gain on property dispositions	(125)	(138)	(2,302)
     Transaction, restructuring and other costs	(29)	(46)	237
     Gain on extinguishment and settlement of financial liabilities	-	(1)	-
     Gain on debt modification	(246)	-	-

     The gain on property dispositions is discussed in the "Capital Expenditures and Net Capital Expenditures" section.

     Transaction, restructuring and other costs (recoveries) pertain mainly to the Company's business development and costs associated with dispositions.

     The gain on debt modification in Q1 2025 is discussed in the "Capital Resources and Liquidity - Debt" section.

     INCOME TAX

     As of March 31, 2025 and December 31, 2024, the Company did not recognize any deferred tax assets in excess of taxable temporary differences as there was insufficient evidence to indicate that it was probable that future taxable profits, in excess of profits arising from the reversal of existing temporary difference, would be generated to utilize the existing deferred tax assets.

     NET LOSS
     ($000s, except per share amounts)	Q1 2025	Q4 2024	Q1 2024
     			(Restated)(1)
     Net loss(1)	(6,137)	(10,123)	(4,945)
     $ per share - Basic	-	(0.01)	(0.01)
     $ per share - Diluted	-	(0.01)	(0.01)
     (1) Restated. Refer the "Restatements" section.

     Q1 2025 vs Q4 2024

     The Q1 2025 net loss was lower based on the impacts of:

   • Lower royalties in Q4 2024 relating to an adjustment for higher gas cost allowance recovery;

   • Lower operating and G&A expenses in Q1 2025; and

   • Higher impairment expense in Q4 2024. The Q4 2024 impairment expense included $9.7 million impairment of the Wheatland CGU, with the balance due to changes in decommissioning liabilities of certain properties having zero carrying amounts.

     Q1 2025 vs Q1 2024

     The Q1 2025 net loss was greater based on the impacts of:

   • Higher petroleum and natural gas sales in Q1 2024 as a result of higher production in that period (that included partial production from the Evi properties sold in Q1 2024);

   • Higher Q1 2025 G&A expense that includes higher share-based compensation with respect to a larger grant of Options in late December 2024;

   • Higher Q1 2024 gain on disposition from the Evi and Provost properties sold;

   • Higher impairment expense in Q1 2025;

   • Higher finance costs in Q1 2025 on higher average debt levels; and

   • The offset of lower operating expenses in Q1 2025 and higher foreign exchange loss in Q1 2024.

1. Capital expenditures and Net capital expenditures are Non-GAAP and other financial measures. Refer to "Non-GAAP and other Financial Measures" included in the "Advisories" section.

   Q1 2025 vs Q4 2024 and Q1 2024

   • Q1 2025 capital expenditures were primarily associated with the Company's drilling activities with respect to an additional three gross (3.0 net) new wells in the Basal Quartz zone, at Michichi. These wells were completed, tied in and brought on production in Q2 2025;

   • Q4 2024 capital expenditures were primarily associated with the Company's drilling activities with respect to its first two gross (2.0 net) wells in the Basal Quartz zone, at Michichi; and

   • Q1 2024 had no drilling activity and minimal capital activities as PPR focused on its continued recapitalization and restructuring activities, the disposition of Evi and Provost assets and managing its working capital in the process.

     Dispositions and Acquisitions Q1 2025

   • The Company adjusted the purchase price equation for the disposition of certain Provost assets completed in Q1 2024. The adjustments resulted in a $0.06 million reduction in cash consideration, the derecognition of a further $0.18 million in

     decommissioning liabilities and a further $0.12 million gain on disposition; and

   • PPR completed other property acquisitions acquiring $0.03 million of property and equipment in exchange for $0.03 million in cash consideration. In addition, PPR sold $0.01 million of property and equipment in exchange for $0.01 million in cash consideration.

In Q1 2024, the Company completed its dispositions of the Evi CGU and certain Provost assets resulting in net cash proceeds of $24.2 million, after closing adjustments. Of the proceeds received, $20.0 million (US$14.8 million) was used to reduce advances under the First Lien Loan. A gain of $2.3 million was recorded in Q1 2024 related to these dispositions. In Q4 2024, a further gain of $0.1 million was recognized as a result of further adjustments to the purchase price.

PPR's decommissioning liabilities at March 31, 2025 were $73.5 million compared to $71.8 million at December 31, 2024 to provide for future remediation, abandonment and reclamation of PPR's crude oil and natural gas properties. The increase of $1.7 million was due to additions of $0.3 million, accretion expense of $0.6 million and a change in estimate increase of $1.2 million, offset by dispositions of $0.2 million and settlements of decommissioning obligations of $0.2 million.

Changes in estimates result in a corresponding increase or decrease in the carrying amount of the related assets except for certain assets with zero carrying amount, in which case, the amount is immediately recognized in the income statement as an impairment.

At March 31, 2025, the Company estimated the undiscounted and inflated total future liabilities to be approximately $196.1 million (December 31, 2024 - $194.0 million). Liability payments are estimated over the next 55 years with the majority of costs expected to be incurred over the next 35 years, of which $6.2 million is estimated to be spent in the next year.

Decommissioning liabilities at March 31, 2025 were determined using risk-free rates of 3.23% - 3.34% (December 31, 2024 - 3.36% -

3.64%) and an inflation rate of 1.9% (December 31, 2024 - 1.9%).

The Company considers its capital structure to include working capital (deficit), debt and shareholders' equity (deficit).

At March 31, 2025, the Company had an adjusted working capital deficit (as defined in "Advisories" below) of $6.2 million (December 31, 2024 - $7.3 million). The decrease in the adjusted working capital deficit in Q1 2025 resulted from the equity raise in 2025 offset by an increase in capital expenditures related to PPR's Basal Quartz drilling program.

At March 31, 2025, the Company's debt of $58.4 million (December 31, 2024 - $55.6 million) comprises the following:

1. At March 31, 2025, USD-denominated principal debt converted at an exchange rate of US$1.00 to C$1.4376 (December 31, 2024 - US$1.00 to C$1.4389).

2. The Second Lien Notes tranches' principal is subject to deferred interest in kind (whilst the principal remains outstanding) and an overall deferred compensation fee as described below, which are included in the 'Capitalized and accrued PIK interest' as presented. PPR estimates that the principal will be subject to a target multiple of x1.8 on settlement at the maturity date, which is not reflected in the principal debt in the table above.

At March 31, 2025, there was $0.4 million of principal debt accrued interest on the First Lien Loan as a result of the deferral of a portion of cash interest owed under the First Lien Loan and 75% capitalized to outstanding principal as additional principal of all accrued interest amounts through March 31, 2025 as described below.

At December 31, 2024, there was $nil accrued interest on the First Lien Loan as a result of the deferral of a portion of cash interest owed under the First Lien Loan and 100% capitalized to outstanding principal as additional principal of all accrued interest amounts through December 31, 2024 as described below.

Note 14 in the Interim Financial Statements includes a reconciliation of the changes in liabilities arising from the financing activities of the Company's debt.

At March 31, 2025 and December 31, 2024, the Company has a senior secured credit facility ("First Lien Loan") with the Company's ultimate parent comprising US$65 million of senior secured revolving notes.

Borrowings under the First Lien Loan are repayable at the Company's election at par plus accrued interest and any applicable breakage costs. Repayments generally will not affect the aggregate commitment or borrowing base under the First Lien Loan, except in certain extraordinary circumstances where a repayment will reduce the borrowing base. The First Lien Loan is denominated in USD, but accommodates CAD advances.

All notes were issued at par by Prairie Provident Resources Canada Ltd., a wholly-owned subsidiary of PPR, and are guaranteed by PPR and certain of its other subsidiaries and secured by a US$200 million debenture.

The note purchase agreement governing the First Lien Facility also limits the amounts the Company can borrow to a borrowing base amount, determined by the secured noteholder at any time in their sole discretion based on their internal criteria and the estimated value of PPR's petroleum and natural gas properties in accordance with the lender's customary practices for oil and gas loans. Outstanding borrowings in excess of the borrowing base must be repaid with interest.

The Company's lenders have not re-determined the borrowing base following the Company's reserves evaluation as at December 31,

2024. The lenders have sole discretion on the determination of the borrowing base, which is based predominantly on the amount of the Company's proved developed producing oil and natural gas reserves. If a borrowing base deficiency exists because of a re-determination, the lender is required to notify the Company of such shortfall. The Company may repay the shortfall amount by either making one installment within 90 days or six equal consecutive monthly installments beginning within 30 days after the Company's receipt of the borrowing base deficiency notice.

Amounts borrowed under the Revolving Facility bear interest based on reference bank lending rates in effect from time to time, plus an applicable margin. The USD advances bear interest at the Secured Overnight Financing Rate ("SOFR") plus 950 basis points and the CAD advances bear interest at the Canadian Overnight Repo Rate Average ("CORRA") (Canadian Dollar Offered Rate prior to the debt amendment below) plus 950 basis points. Standby fees on any undrawn borrowing capacity are 87.5 basis points per annum.

On September 13, 2024, the maturity date was extended to March 31, 2026 in addition to the following amendments to the First Lien Loan:

• Deferral of a portion of cash interest obligations on amounts owed under the First Lien Loan, through (i) 100% capitalized to outstanding principal as additional principal of all accrued interest amounts through December 31, 2024; and (ii) 25% capitalization of 2025 accrued interest through December 31, 2025 if PPR raises $14.5 million to $16.5 million of equity by March 31, 2025; or (iii) up to 50% of 2025 accrued interest through December 31, 2025 if PPR raises at least $16.5 million of equity by March 31, 2025 as additional principal of all accrued interest amounts;

• In consideration of the debt amendments, a $1.5 million debt amendment fee (the "Amendment Fee") payable to the noteholder at the earliest of (i) the March 31, 2026 maturity date; (ii) the date on which the other obligations of the First Lien Loan are settled; or

  (iii) the date on which an event of default occurs; and

• Adjustment of financial covenants, to replace existing covenants with new measures and thresholds that align with the Company's current expectations for the remaining term to maturity.

  On February 19, 2025, in conjunction with the 2025 Equity Financings as described below, further amendments were made to the First Lien Loan that includes:

• Further deferral of a portion of cash interest obligations on amounts owed under the First Lien Loan, through 75% capitalization of 2025 accrued interest through December 31, 2025 as PPR raised $18.5 million of equity by March 31, 2025; and

• Replacing existing covenants with new measures and thresholds for the remaining term to maturity. The amended covenants are outlined below.

Following the revised capitalization of 2025 accrued interest through December 31, 2025 and the impact on the present value of discounted repayments, the Company recognized a $0.2 million debt modification gain on the First Lien Loan.

As at March 31, 2025, the Company had $nil (December 31, 2024 - $nil) available borrowing capacity under the First Lien Loan. The First Lien Loan is considered fully drawn.

On March 30, 2023, the Company completed a second lien financing of the 2023 PPR recapitalization and issued US$3.6 million of notes (the "Second Lien Notes") with Prudential Capital Energy Partners, L.P., a subsidiary of PPR's ultimate parent.

The Second Lien Notes bear interest at the SOFR plus 1150 basis points. Interest on the Second Lien Notes must be paid in kind while the First Lien Loan remains outstanding. In addition to repayment of the principal balance on maturity, the Second Lien Note purchase agreement requires payment of a deferred compensation fee based on a target multiple of 1.8, capped by a 45% internal rate of return, on the later of maturity or prepayment and the date on which the Revolver is fully repaid.

On May 17, 2024, the Company issued an additional tranche of US$2.3 million of Second Lien Notes with consistent interest, maturity and conditions.

On September 13, 2024, the maturity date of the Second Lien Notes was extended to September 30, 2026 in addition to other amendments to the Second Lien Notes including an adjustment of financial covenants, to replace existing covenants and align with the First Lien Note covenants.

On September 27, 2024, the US$2.3 million second tranche was settled and repaid through a C$3.1 million offset against the proceeds received from a $10 million PCEP Common Share subscription. The Company issued US$0.15 million of additional notes representing accrued indebtedness on the second tranche note (the "Additional Notes") repayable on the extended September 30, 2026 maturity date. The Additional Notes are non-interest bearing, not subject to a target return and not subject to a deferred compensation fee.

On February 19, 2025, in conjunction with the First Lien Loan debt amendments as described above, the Second Lien Note covenants were further revised. The amended covenants are outlined below.

As described above, the amended September 13, 2024 debt agreements of the First Lien Loan and the Second Lien Notes and related parent and subsidiary guarantees now align the various financial and non-financial covenants on the part of the Company and its subsidiaries including covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, capital expenditures, hedging activities, investments, dividends and mergers and acquisitions.

At March 31, 2025, the revised financial covenant thresholds of the Company are as follows:

1. Under the debt agreements, EBITDAX for any period means (a) consolidated net loss for such period plus (b) to the extent deducted in determining consolidated net loss, financing charges, exploration expenses, income taxes, depreciation, depletion, amortization and other non-cash items of expense for such period (including any provision for the reduction in the carrying amount of assets recorded in accordance with Generally Accepted Accounting Practice and including non-cash charges resulting from share-based compensation and write downs on assets and non-cash losses resulting from outstanding risk management derivative contracts for such period, losses attributable to extraordinary and non-recurring losses for such period) minus (c) all non-cash items of income which were included in determining such consolidated net loss (including non-cash gains resulting from the outstanding risk management derivative contracts and earnings attributable to extra-ordinary and non-recurring gains for such period; provided that such EBITDAX shall be subject to pro forma adjustments for material acquisitions and dispositions assuming that such transactions had occurred on the first day of the applicable calculation period.

2. Under the debt agreements, the Total Leverage Ratio means the ratio as of the last day of any fiscal quarter of the Company, the ratio of (i) adjusted indebtedness at such time (including, for clarity, all First Lien Loans and Second Lien Notes), plus current liabilities at such time, less current assets at such time, to (ii) EBITDAX for the period of four fiscal quarters most recently ended. Under the agreements, current assets exclude derivative assets while current liabilities excludes the current portion of long-term debt, lease liabilities, decommissioning obligations, derivative liabilities and non-cash liabilities.

3. Production means an average daily hydrocarbon production volume, measured in barrels of oil equivalent per day (boe/d) (with 6,000 cubic feet of

   natural gas deemed to be one barrel of oil equivalent).

   Subsequent to March 31, 2025, the Company obtained a waiver from the lenders for the financial debt covenant breach as described above. As a result of this breach, debt is classified as current at March 31, 2025.

   SHAREHOLDERS' EQUITY (DEFICIT)

   PPR has the following outstanding instruments as at the date of this report, March 31, 2025 and December 31, 2025:

   (000s)	May 13 2025	March 31 2025	December 31 2024
   Common Shares	1,401,335	1,401,335	1,197,401
   Warrants 2023 Purchase Warrants(1)	44,444	44,444	44,444
   2023 Broker Warrants(2)	3,556	3,556	3,556
   2025 Purchase Warrants(3)	86,267	86,267	-
   2025 Broker Warrants(4)	2,509	2,509	-
   PPR Option Plan Options	63,975	63,975	64,902
   PPR Incentive Security Plan
   DSUs	2,000	2,000	2,000
   RSUs	6,690	6,690	6,690

   1. Each 2023 Purchase Warrant is exercisable for one Common Share at a price of $0.10/share until May 15, 2028.

   2. Each 2023 Broker Warrant is exercisable for one unit at a price of $0.09/unit until May 15, 2028 with each unit comprising one Common Share as well as a warrant entitling the holder to subscribe for another Common Share at a price of $0.10/share until May 15, 2028.

   3. Each 2025 Purchase Warrant is exercisable for one Common Share at a price of $0.05/share until March 5, 2028.

   4. Each 2025 Broker Warrant is exercisable for one unit at a price of $0.0425/unit until March 5, 2028 with each unit comprising one Common Share as well as a warrant entitling the holder to subscribe for another Common Share at a price of $0.05/share until March 5, 2028.

      2025 Equity Financings

      As part of a brokered private placement, PPR raised $8.666 million in gross proceeds through the issuance of Common Shares and Warrants:

      • On February 20, 2025, PPR closed the first tranche of an equity financing for $4.8 million in gross proceeds from its principal and largest shareholder, PCEP, at a price of $0.0425 per Common Share and issued 112,941,176 Common Shares to PCEP; and

      • On March 5, 2025, PPR closed the second and final tranche of the equity financing for additional $3.87 million in gross proceeds through:

        • The issuance of 86,267,672 units at a price of $0.0425 per unit, for gross proceeds of $3.67 million in an offering made pursuant to the 'listed issuer financing exemption' (LIFE) under applicable Canadian securities laws. Each unit comprises one Common Share and one Common Share purchase warrant, with each such purchase warrant exercisable for one Common Share at a price of $0.05 per Common Share until March 5, 2028 (the "2025 Purchase Warrant"). As part of the LIFE offering, PCEP acquired 54,508,872 units in total for $2.3 million in gross proceeds; and

        • A further $0.2 million in gross proceeds from directors and officers at a price of $0.0425 per Common Share, issuing 4,705,883 Common Shares to directors and officers.

In connection with the 2025 Equity Financings, $8.451 million of the gross proceeds was allocated to Common Share capital and the residual $0.215 million was allocated to the 2025 Purchase Warrants, and included in Warrants.

In connection with the brokered private placement, the Company paid deal brokers total cash compensation of $0.35 million and issued them a total of 2,508,704 non-transferable broker warrants (the "2025 Broker Warrants"). Each 2025 Broker Warrant entitles the holder thereof to acquire one unit at a price of $0.0425 per Unit until March 5, 2028.

As part of its long-term incentive plans, PPR's equity compensation arrangements consist of its stock option plan ("Option Plan") and

incentive security plan ("Incentive Security Plan").

The Option Plan provides for the grant from time to time to directors, officers, employees and consultants of the Company of stock options to purchase Common Shares at a specified exercise price determined at the time of grant ("Options"). The Incentive Security Plan provides for the grant from time to time to directors, officers and employees of the Company of "phantom" unit awards in the form of deferred share units ("DSUs"), restricted share units ("RSUs") and performance share units ("PSUs").

In Q1 2025, 18,596 Options were exercised for Common Shares of PPR and 908,822 Options were forfeited upon exit of employees, officers and/or directors.

The Company's long-term incentive plans resulted in the following recognized share-based compensation:

PPR's objective when managing capital is to maintain a flexible capital structure and sufficient liquidity to meet its financial obligations and execute its business plans. The Company considers its capital structure to include shareholders' equity, borrowings under its credit facilities and working capital.

PPR monitors its capital structure using the Total Leverage Ratio to trailing twelve months' EBITDAX, terms as defined in the "Debt" section above. The Total Leverage Ratio provides a measure of the Company's ability to manage its debt levels under current operating conditions. The Company's goal is to manage this ratio within the financial covenants imposed on it under its outstanding debt agreements.

As at March 31, 2025, the Company was in breach of this financial covenant. Refer to the "Debt" section above for additional details.

Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. As outlined in the "Debt" section above, at March 31, 2025, the Company had $nil borrowing capacity under the Second Lien Loan. This, and the information provided in Note 2 (Going Concern), results in material uncertainty that may cast significant doubt on the Company's ability to continue as a going concern.

As at March 31, 2025, PPR had outstanding letters of credit of $4.0 million (December 31, 2024 - $4.0 million). The letters of credit are issued by a financial institution at which PPR posted a cash deposit to cover letters of credit. The related deposit is classified as restricted deposit on the statement of financial position and the balance is invested in short-term market instruments with maturity dates of one year or less when purchased (see Cash, Restricted Cash and Restricted Deposit above).

The following table details the cash flows and contractual maturities of the Company's financial liabilities at March 31, 2025:

(1) Includes interest payments and the principal and deferred amounts payable on maturity on the Company's Revolving Facility and Second Lien Notes. Interest payments are estimated for the Revolving Facility using year-end outstanding borrowing and year-end prime interest rate plus applicable margins for the related borrowing periods. At March 31, 2025, the contractual maturities of the debt is presented as current as the debt covenants were breached.

The Interim Financial Statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which assumes that PPR will be able to realize its assets and discharge its liabilities in the normal course of business.

At March 31, 2025, the Company's total principal debt was $66.5 million (December 31, 2024 - $64.9 million) with the First Lien Loan considered fully drawn. At March 31, 2025, the Company was in breach of its Minimum EBITDAX financial covenant under its Revolving Facility and Second Lien Notes. The covenant breach creates a right for the lenders under each facility to accelerate the maturity of their indebtedness. None of the Company's lenders have delivered a notice of an event of default required to accelerate the maturity of their facilities and as of May 13, 2025, this default has been waived (or the applicable covenants have been adjusted or eliminated such that the Company is in compliance as of March 31, 2025), and the lenders no longer have the right to accelerate the maturities of the facilities, subject to the Company's compliance with the terms of the agreements in future periods. There remains a risk with regards to ongoing compliance with debt covenants.

As described in the "Debt" and "Shareholders' Equity (Deficit)" sections above, and in furtherance of its Basal Quartz development plans, the Company raised $8.67 million in aggregate gross proceeds through equity financings, with the first tranche of $4.8 million closing on February 19, 2025 and the second and final tranche of $3.87 million closing on March 5, 2025 (the "2025 Equity Offerings").

The Company's principal shareholder, PCEP, and certain directors and officers of the Company, participated in the 2025 Equity Offerings for a final aggregate investment of $7.32 million after converting USD-denominated commitments to Canadian dollars, of which $5.0 million was completed under the Private Placement and $2.32 million was completed under the 2025 LIFE Offering.

In conjunction with the 2025 Equity Offerings, on February 19, 2025, the Company agreed to further amendments to its First Lien Loan debt agreements providing further deferral of certain cash interest obligations and adjustment of financial covenants to replace existing covenants with new measures and thresholds that align with the Company's current expectations for the remaining term to maturity. Amendments have also been agreed with respect to the Company's outstanding Second Lien Notes to align the amended covenants under the First Lien Loan.

In the first quarter of 2025, the Company spud a further three Basal Quartz wells which were completed and brought on production in late April 2025. Despite these efforts by the Company and with the Company committed to further development in the Basal Quartz formation, PPR remains in a challenging position with respect to its ability to meet current financial obligations while managing its decommissioning liabilities, debt obligations, and debt-related financial covenants. In the event of default under both the First Lien Loan and the Second Lien Notes, the lenders have the right to demand immediate repayment of all amounts owed under both facilities.

The Company recognizes the significance of PPR's cash flows and continues to actively assess a variety of strategies and options to effectively manage its capital, however there is no guarantee that the Company will be successful in these efforts.

The Company's lenders have not re-determined the borrowing base following the Company's reserves evaluation as at December 31, 2024. The lenders have sole discretion on the determination of the borrowing base, which is based predominantly on the amount of the Company's proved developed producing oil and natural gas reserves. If a borrowing base deficiency exists because of a re-determination, the lender is required to notify the Company of such shortfall. The Company may repay the shortfall amount by either making one installment within 90 days or six equal consecutive monthly installments beginning within 30 days after the Company's receipt of the borrowing base deficiency notice. In the event of such a shortfall, the Company may not have the funds available to repay the amount due.

Due to the above factors, there is a material uncertainty that may cast significant doubt on the Company's ability to continue as a going concern. The Interim Financial Statements do not include adjustments to the recoverability and classification of recorded assets and liabilities and related expenses that might be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than the normal course of business at amounts different from those in the accompanying Interim Financial Statements. Such adjustments could be material.

($000s, except per unit amounts

and as otherwise indicated) Q1 2025 Q4 2024 Q3 2024 Q2 2024 Q1 2024 Q4 2023 Q3 2023 Q2 2023

(Restated)(1)(Restated)(1)(Restated)(1)(Restated)(1)(Restated)(1)(Restated)(1)

(1) Restated. Refer the "Restatements" section.

(2) This is a Non-GAAP and other financial measure. Refer to "Non-GAAP and other Financial Measures" included in the "Advisories" section.

PPR has contractual obligations in the normal course of operations including operating agreements, transportation commitments, royalty obligations, lease rental obligations, physical commodity sales contracts and employee agreements. These obligations are of a recurring, consistent nature and impact PPR's cash flows in an ongoing manner.

The Company operates in a regulatory and commercial environment that exposes it to regulatory, contractual and litigation risks. As a result, PPR is involved in certain disputes and legal proceedings, including litigation, claims, arbitration and regulatory investigations. Such cases are subject to many uncertainties, and the outcomes are often difficult to predict, including the impact on operations or on the financial statements, particularly in the earlier stages of a case. The Company makes provisions for cases brought against it when, in the opinion of management after seeking legal advice, it is probable that a liability exists, and the amount can be reliably estimated. Such claims are not expected to have a material impact on the Company's results of operations or cash flows.

At March 31, 2025, the Company has non-cancellable contractual obligations summarized as follows:

(1) At March 31, 2025, the non-cancellable contractual obligations of the debt is presented as current as the debt covenants were breached at March 31, 2025.

The table above excludes contractual obligations for lease payments which are recorded as lease liabilities on the consolidated statement of financial position.

PPR does not have any off-balance sheet arrangements that would result in a material change to its financial position, performance or funds flow from operations during the reporting periods.

PPR's Interim Financial Statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, using accounting policies consistent with IFRS as issued by the IASB. These financial statements are condensed as they do not include all of the information required by IFRS for annual financial statements and therefore should be read in conjunction with the Company's Annual Financial Statements.

On April 9, 2024, the IASB issued a new standard, International Financial Reporting Standard 18 Presentation and Disclosure in Financial Statements, which introduced new requirements for improved comparability in the statement of profit or loss, enhanced transparency of management-defined performance measures and more useful grouping of information in the financial statements. The standard is effective for annual reporting periods beginning on or after January 1, 2027. The Company is currently evaluating its impact to financial statements.

On May 30, 2024, the IASB issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures that clarify the recognition and derecognition of certain financial assets and liabilities, including an exception for those settled via electronic cash transfer systems. New disclosure requirements are introduced for instruments with terms that can change cash flows and for equity instruments designated at fair value through other comprehensive income. The amendments are effective for reporting periods beginning on or after January 1, 2026. PPR does not anticipate any material impact from these amendments to the financial statements.

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These

estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on PPR's consolidated financial statements. Actual results may differ from these estimates. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances.

Information about significant areas of estimation uncertainty and critical judgments in applying accounting policies are outlined in Note 2 of the Annual Financial Statements. The Company's material accounting policies under IFRS are presented in Note 3 of the Annual Financial Statements. Certain information and disclosures normally required to be included in the notes to the Annual Financial Statements prepared in accordance with IFRS have

There have been no material changes to our critical accounting estimates used in applying accounting policies for the three months ended March 31, 2025.

PCEP Canadian Holdco, LLC is the immediate holding and parent company of PPR. Please see the "Shareholders' Equity (Deficit)" section with regards to PCEP's participation in the equity offerings in February 2025 and March 2025.

The First Lien Loan is held with PGIM, Inc., the ultimate parent of PPR. The First Lien Loan and related transactions are described in the "Debt" section.

The Second Lien Notes are held by Prudential Capital Energy Partners, L.P., a subsidiary of PPR's ultimate parent, PGIM. The Second Lien Notes and related transactions are described in the "Debt" section.

The First Lien Loan debt is held by PGIM, Inc.'s general account (the "Senior Debt") and the Senior Debt is separately managed from the Second Lien Notes and equity held by the PGIM Capital Partners mezzanine fund (held by PCEP). There is a wall separating the management of the Senior Debt and PCEP, and all negotiations with the management of the Senior Debt are conducted at arm's-length, consistent with negotiations with other third parties.

At December 31, 2024 and in the fourth quarter of 2024, the Company made certain corrections to the prior period financial statements as outlined in Note 24 of the Annual Financial Statements. Prior period comparative information has been restated to reflect those adjustments. Note 24 of the Annual Financial Statements also details the impact to affected prior period financial statements, including March 31, 2024 financial statement line items (unaudited), December 31, 2023 financial statement line items (audited) and interim period results for the three months ended March 31, 2024 financial statement line items (unaudited) of those restatements.

PPR is exposed to various market and operational risks. PPR's operations are conducted in the same business environment as most other Canadian oil and gas operators and the business risks are very similar. For a discussion of these risks, please see "Forward-Looking Information" in the "Advisories" section of MD&A and PPR's MD&A and AIF, each for the year ended December 31, 2024 available on SEDAR+ at https://www.sedarplus.ca or on PPR's website at https://www.ppr.ca.

In 2025, the United States government announced significant tariffs on Canadian imports of crude oil and natural gas produced in Canada. These tariffs will impact Canadian production of crude oil and natural gas and pose a risk to the global supply. To date, these tariffs will remain in place and we don't know what impact it will have on prices of Canadian crude oil and natural gas prices in the future.

PPR is required to comply with National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"). The certification of interim filings for the interim period ended March 31, 2025 requires that PPR disclose in the interim MD&A any changes in PPR's internal control over financial reporting ("ICFR") that occurred during the period that have materially affected, or are reasonably likely to materially affect, PPR's ICFR. PPR confirms that no such changes were made to its ICFR during the three months ended March 31, 2025.

The Company uses terms within the MD&A that do not have a standardized prescribed meaning under IFRS and these measurements may not be comparable with the calculation of similar measurements used by other companies. Non-GAAP and other financial measures are provided as supplementary information by which readers may wish to consider the Company's performance but should not be relied upon for comparative or investment purposes. Readers must not consider Non-GAAP and other financial measures in isolation or as a substitute for analysis of the Company's financial results as reported under IFRS. Non-GAAP and other financial measures may include Non-GAAP measures, Non-GAAP ratios, capital management measures, supplementary measures and total of segment measures. The Non-GAAP and other financial measures used in this report are summarized as follows:

Operating netback is a Non-GAAP financial measure commonly used in the oil and gas industry, which the Company believes is a useful measure to assist management and investors to evaluate operating performance. Operating netback included in this report were determined by taking oil and gas revenues less royalties and operating costs. Operating netback, after realized gains (losses) on derivatives, adjusts the operating netback for only the realized portion of gains and losses on derivatives. Operating netback may be expressed in absolute dollar terms or on a per boe basis. Per boe amounts are determined by dividing the absolute value by working interest production. Operating netback per boe and operating netback, after realized gains (losses) on derivatives per boe are Non-GAAP financial ratios.

(1) Restated. Refer the "Restatements" section.

AFF is a Non-GAAP financial measure calculated based on net cash from operating activities before changes in non-cash working capital, transaction costs, restructuring costs and other non-recurring items. The Company believes that AFF provides a useful measure of the Company's operational performance on a continuing basis by eliminating certain non-cash charges and charges that are non-recurring or discretionary. Management utilizes the measure to assess the Company's ability to finance capital expenditures and debt repayments. AFF as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. AFF per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of earnings per share. AFF per share is a Non-GAAP ratio.

The following table reconciles cash flow from operating activities to AFF and AFF excluding decommissioning settlements:

The Company monitors its capital structure and liquidity based on the ratio of Debt to Bank Adjusted EBITDAX, which is a capital management measure, as defined below. The ratio provides a measure of the Company's ability to manage its debt levels under current operating conditions. "Debt" refers to the Company's borrowings under its First Lien Loan and Second Lien Notes. "Bank Adjusted EBITDAX" corresponds to defined terms in the Company's debt agreements and means net income (loss) before financing charges, foreign exchange gain (loss), E&E expense, income taxes, depreciation, depletion, amortization, other non-cash items of expense and non-recurring items, adjusted for major acquisitions and material dispositions assuming that such transactions had occurred on the first day of the applicable calculation period. As transaction costs related to business combinations are non-recurring costs, Bank Adjusted EBITDAX is calculated excluding transaction costs, as a meaningful measure of continuing net income. For purposes of calculating covenants under long-term debt, Bank Adjusted EBITDAX is determined using financial information from the most recent four consecutive fiscal quarters.

The following is a reconciliation of Bank Adjusted EBITDAX to the nearest IFRS measure, income (loss) before income tax:

Capital expenditures and net capital expenditures are Non-GAAP financial measure commonly used in the petroleum and natural gas industry, which the Company believes are useful measures to assist management and investors to assess the Company's investment in its existing asset base. Capital expenditures is calculated as the sum of property and equipment expenditures and exploration and evaluation expenditures from the consolidated statements of cash flows that is most directly comparable to cash flows used in investing activities. Net capital expenditures is calculated as capital expenditures, plus acquisitions from business combinations, which is the outflow cash consideration paid to acquire oil and gas properties, less asset dispositions (net of acquisitions), which is the cash proceeds from the disposition of producing properties and undeveloped lands.

Working capital (deficit), also known as net current assets (liabilities), is a Non-GAAP financial measure, calculated as current assets less current liabilities.

Adjusted working capital (deficit) used in conjunction with debt and the calculation of "Net Debt" below for the purpose of determining Total Leverage Ratio covenant and certain defined terms under the Company's debt agreements (see "Capital Resources and Liquidity -Debt" section above), is a Non-GAAP financial measure. Adjusted working capital (deficit) is calculated as current assets excluding derivative assets and assets-held-for-sale and current liabilities, excluding the current portions of long-term debt, lease liabilities, decommissioning obligations, derivative liabilities, other non-cash liabilities and liabilities held for sale. In addition to measuring covenant compliance, this measure is used to assist management and investors in understanding liquidity at a specific point in time.

Net debt is a Non-GAAP measure, defined as debt, plus working capital (deficit). Net debt is a measure commonly used in the oil and gas industry for assessing the liquidity of a company.

Adjusted net debt is a Non-GAAP measure and used in conjunction with adjusted working capital (deficit) for the purpose of determining Total Leverage Ratio covenant and certain defined terms under the Company's debt agreements (see "Capital Resources and Liquidity -Debt" section above). Adjusted net debt is calculated as debt, plus adjusted working capital (deficit).

(1) Working capital (deficit) and Adjusted working capital (deficit) are Non-GAAP and other financial measures and is determined as defined above.

The petroleum and natural gas industry commonly expresses production volumes and reserves on a "barrel of oil equivalent" basis

("boe") whereby natural gas volumes are converted at the ratio of six thousand cubic feet (6 Mcf) to one barrel (1 bbl) of crude oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants.

Throughout the MD&A, the Company has used the 6:1 boe measure, which is the approximate energy equivalency of the two commodities at the burner tip. Boe does not represent a value equivalency at the wellhead nor at the plant gate, which is where the Company sells its production volumes and therefore may be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion may be misleading as an indication of value.

Certain statements and information in this MD&A may constitute forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company's control. All statements regarding the Company's strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. The words "could," "believe," "anticipate," "intend," "plan," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements with respect to, among other things:

• estimates of the Company's oil and natural gas reserves;

• estimates of the Company's future oil, natural gas and NGL production, including estimates of any increases or decreases in the Company's production;

• estimates of future capital expenditures;

• estimates and judgements related to common share and warrants valuations;

• the Company's future financial condition and results of operations;

• the source of funding for the Company's activities, including development costs;

• the Company's future revenues, cash flows and expenses;

• the Company's access to capital and expectations with respect to liquidity and capital resources;

• the Company's future business strategy and other plans and objectives for future operations;

• the Company's future development opportunities and production mix;

• the Company's outlook on oil, natural gas and NGL prices;

• the anticipated benefits of merger and acquisitions, including prospective operating synergies, G&A cost savings, improved economies of scale, risk of drilling opportunities and marketplace liquidity;

• the anticipated timeframe for the closing of mergers and acquisitions;

• the amount, nature and timing of future capital expenditures, including future development costs;

• the Company's ability to access the capital markets to fund capital and other expenditures;

• the Company's expectations regarding its ability to raise capital and to add reserves and grow production through acquisitions, exploration and development;

• the Company's assessment of the it's counterparty risk and the ability of the Company's counterparties to perform their future obligations; and

• the impact of federal, provincial, territorial and local political, legislative, regulatory and environmental developments in Canada.

  The Company believes the expectations and forecasts reflected in the Company's forward-looking statements are reasonable, but the Company can give no assurance that they will prove to be correct. Readers are cautioned that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for and development, production and sale of oil and natural gas. When considering forward-looking statements, you should keep in mind the assumptions, risk factors and other cautionary statements that include, among other things:

• the volatility of oil, natural gas and NGL prices, and the related differentials between realized prices and benchmark prices;

• a continuation of depressed natural gas prices;

• the availability of capital on economic terms to fund the Company's capital expenditures and potential acquisitions;

• the Company's ability to obtain adequate financing to pursue other business opportunities;

• the Company's ability to reach an agreement with counterparties to new financing arrangements on terms and conditions that are acceptable to the Company or at least as favorable to the Company than those of the existing credit facilities, or will improve the

  Company's liquidity profile;

• the Company's ability to generate sufficient cash flow from operations or obtain adequate financing to fund the Company's capital expenditures and meet working capital needs;

• the Company's ability to replace and sustain production;

• a lack of available drilling and production equipment, and related services and labor;

• increases in costs of drilling, completion and production equipment and related services and labor;

• unsuccessful exploration and development drilling activities;

• regulatory and environmental risks associated with exploration, drilling and production activities;

• declines in the value of the Company's oil and natural gas properties, resulting in impairments;

• the adverse effects of changes in applicable tax, new or additional tariffs, environmental and other regulatory legislation;

• a deterioration in the demand for the Company's products;

• the risks and uncertainties inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and the timing of expenditures;

• intense competition with companies with greater access to capital and staffing resources;

• the risks of conducting operations in Canada and the impact of pricing differentials, fluctuations in foreign currency exchange rates and political developments on the financial results of the Company's operations; and

• the uncertainty related to pending litigation against the Company.

Should one or more of the risks or uncertainties described above or elsewhere in this MD&A occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this MD&A, and the Company undertakes no obligation to update this information to reflect events or circumstances after the delivery of this MD&A. All forward-looking statements, expressed or implied, included in this MD&A are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company may make or persons acting on the Company's behalf may issue.