Subsequent events (notes 10 and 17)

For the periods ended September 30, 2025 and 2024

Baytex Energy Corp. (the “Company” or “Baytex”) is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s common shares are traded on the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

The condensed consolidated interim financial statements ("consolidated financial statements") have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, under International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). These consolidated financial statements do not include all the necessary annual disclosures as prescribed by IFRS and should be read in conjunction with the annual consolidated financial statements as at and for the year ended December 31, 2024 ("2024 annual consolidated financial statements").

The consolidated financial statements were approved by the Board of Directors of Baytex on October 30, 2025.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or when otherwise indicated.

Management makes judgments and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.

In 2025, the U.S. government imposed tariffs on certain goods imported from other countries, including Canada. These tariffs and the Canadian government’s response to them could adversely affect market prices for crude oil and natural gas or demand for the Company’s Canadian production in addition to the cost of goods imported directly or indirectly from the U.S. The impact of these tariffs on the Company’s financial results cannot be quantified at this time.

The accounting policies, critical accounting judgments and significant estimates used in these consolidated financial statements are consistent with those used in the preparation of the 2024 annual consolidated financial statements.

IFRS 18 Presentation and Disclosure in Financial Statements was issued in April 2024 by the IASB and replaces IAS 1 Presentation of Financial Statements. The Standard introduces a defined structure to the statements of income or loss and comprehensive income or loss and specific disclosure requirements related to the same. The Standard is required to be adopted retrospectively and is effective for fiscal years beginning on or after January 1, 2027, with early adoption permitted. The Company is evaluating the impact that this standard will have on the consolidated financial statements.

IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures were amended in May 2024 to clarify the date of recognition and derecognition of financial assets and liabilities. The amendments are effective for fiscal years beginning on or after January 1, 2026, with early adoption permitted. The Company is evaluating the impact that this amendment will have on the consolidated financial statements.

Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:

•Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada;

•U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the Eagle Ford in Texas; and

•Corporate includes corporate activities and items not allocated between operating segments.

			Canada						U.S.						Corporate						Consolidated
Nine Months Ended September 30			2025			2024			2025			2024			2025			2024			2025			2024
Revenue, net of royalties
Petroleum and natural gas sales			$	1,303,092		$	1,407,340		$	1,510,265		$	1,784,598		$	—		$	—		$	2,813,357		$	3,191,938
Royalties			(160,701)			(200,809)			(405,856)			(472,602)			—			—			(566,557)			(673,411)
			1,142,391			1,206,531			1,104,409			1,311,996			—			—			2,246,800			2,518,527
Expenses
Operating			248,609			257,191			220,398			251,068			—			—			469,007			508,259
Transportation			62,383			62,616			36,331			37,416			—			—			98,714			100,032
Blending and other			184,951			183,795			—			—			—			—			184,951			183,795
General and administrative			—			—			—			—			68,562			61,313			68,562			61,313
Transaction costs			—			—			—			—			—			1,539			—			1,539
Exploration and evaluation			691			749			—			—			—			—			691			749
Depletion and depreciation			353,405			358,603			607,332			685,295			10,438			9,724			971,175			1,053,622
Share-based compensation			—			—			—			—			13,055			17,393			13,055			17,393
Financing and interest			—			—			—			—			159,395			211,584			159,395			211,584
Financial derivatives loss (gain)			—			—			—			—			35,995			(4,598)			35,995			(4,598)
Foreign exchange (gain) loss			—			—			—			—			(67,543)			35,440			(67,543)			35,440
(Gain) loss on dispositions			(1,028)			(1,055)			—			5,796			—			—			(1,028)			4,741
Other expense (income)			—			—			—			—			2,457			(7,011)			2,457			(7,011)
			849,011			861,899			864,061			979,575			222,359			325,384			1,935,431			2,166,858
Net income (loss) before income taxes			293,380			344,632			240,348			332,421			(222,359)			(325,384)			311,369			351,669
Income tax expense
Current income tax expense																					966			4,407
Deferred income tax expense																					57,295			72,188
																					58,261			76,595
Net income																					$	253,108		$	275,074
Additions to exploration and evaluation assets			930			—			—			—			—			—			930			—
Additions to oil and gas properties			454,702			380,515			576,361			677,941			—			—			1,031,063			1,058,456
Property acquisitions			24,934			36,584			1,540			3,210			—			—			26,474			39,794
Proceeds from dispositions			(11,794)			368			549			(4,524)			—			—			(11,245)			(4,156)

At September 30, 2025 and December 31, 2024, the Company assessed its exploration and evaluation assets for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of its cash generating units ("CGUs").

At September 30, 2025 and December 31, 2024, the Company assessed its oil and gas properties for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of its CGUs.

In March 2025, Gibson Energy Inc. ("Gibson") and Baytex entered into a long-term take-or-pay agreement. Under the 15-year agreement, Baytex will construct certain oil and gas infrastructure, which will be funded by Gibson over the period of construction with ownership transferring to Gibson upon completion and acceptance, which is anticipated to be during the fourth quarter of 2025. Construction has commenced and as of September 30, 2025, $35.7 million has been incurred and Baytex has received $7.9 million of advances towards construction costs with an additional $12.3 million of construction payables outstanding.

(1)U.S. dollar denominated credit facilities balance was US$99.3 million as at September 30, 2025 (December 31, 2024 - US$143.6 million).

(2)The decrease in the principal amount of the credit facilities outstanding from December 31, 2024 to September 30, 2025 is the result of net repayments of $153.6 million and a decrease in the reported amount of U.S. denominated debt of $5.3 million due to foreign exchange.

On June 27, 2025, Baytex extended the maturity of the revolving credit facilities (the "Credit Facilities") from May 9, 2028 to June 27, 2029. There were no changes to the loan balances or financial covenants as a result of the amendment.

At September 30, 2025, Baytex had US$1.1 billion ($1.5 billion) of revolving credit facilities that mature on June 27, 2029. The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.

The Credit Facilities contain standard commercial covenants, in addition to the financial covenants detailed below, related to debt incurrence, restricted payments, certain transactions and compliance with applicable laws. Noncompliance with these covenants may result in an event of default, at which point the carrying value of the debt could become repayable within a 12-month period after the reporting date. Baytex continues to be in compliance with all financial and commercial covenants under its debt agreements.

Advances under the Baytex Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, Canadian Overnight Repo Rate Average rates or secured overnight financing rates ("SOFR"), plus applicable margins. Advances under the Baytex Energy USA, Inc. Credit Facilities can be drawn in U.S. funds and bear interest at the bank's prime lending rate or SOFR, plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.7% for the nine months ended September 30, 2025 (7.8% for nine months ended September 30, 2024).

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at September 30, 2025, the Company's Senior Secured Debt totaled $187.1 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2025 was $1.9 billion.

(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expense, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve-month period. Financing and interest expense for the twelve months ended September 30, 2025 was $183.0 million.

(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at September 30, 2025, the Company's Total Debt totaled $2.0 billion of principal amounts outstanding.

At September 30, 2025, Baytex had $4.7 million of outstanding letters of credit (December 31, 2024 - $5.8 million outstanding) under the Credit Facilities.

(1)The U.S. dollar denominated principal outstanding of the 8.50% notes was US$759.4 million as at September 30, 2025 (December 31, 2024 - US$800.0 million).

(2)The U.S. dollar denominated principal outstanding of the 7.375% notes was US$575.0 million as at September 30, 2025 (December 31, 2024 - US$575.0 million).

(3)The decrease in the principal amount of long-term notes outstanding from December 31, 2024 to September 30, 2025 is the result of the repurchase and cancellation of US$40.6 million ($56.4 million) principal amount of the 8.50% notes and changes in the reported amount of U.S. denominated debt of $68.6 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.

The long-term notes do not contain any significant financial maintenance covenants but do contain standard commercial covenants for debt incurrence and restricted payments.

During the nine months ended September 30, 2025, Baytex repurchased and cancelled US$40.6 million principal amount of the 8.50% Senior Notes and recorded a gain of $2.8 million.

(1)The total of these items reflects the total change in asset retirement obligations of $13.8 million per Note 5 - Oil and Gas Properties ($25.3 million increase in 2024).

(2)The discount and inflation rates used to calculate the liability for our Canadian operations at September 30, 2025 were 3.6% and 2.0% respectively (December 31, 2024 - 3.3% and 1.8%). The discount and inflation rates used to calculate the liability for our U.S. operations at September 30, 2025 were 4.7% and 2.3%, respectively (December 31, 2024 - 4.8% and 2.3%).

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at September 30, 2025, no preferred shares have been issued by the Company and all common shares issued were fully paid. The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.

On June 24, 2025, Baytex announced that the TSX accepted the renewal of the NCIB under which Baytex is permitted to purchase for cancellation up to 66.2 million common shares over the 12-month period commencing July 2, 2025, which represents 10% of the Company's public float, as defined by the TSX, as at June 18, 2025. Baytex obtained an exemption order from the Canadian securities regulators which permits the company to purchase its common shares through the NYSE and other U.S.-based trading systems. On June 18, 2025, Baytex had 768.3 million common shares outstanding.

During the nine months ended September 30, 2025, Baytex recorded $17.2 million related to common share repurchases, which includes $16.8 million of consideration paid for the repurchase and cancellation of common shares as well as $0.4 million of federal tax levied on common share repurchases.

Purchases are made on the open market at prices prevailing at the time of the transaction. During the nine months ended September 30, 2025, Baytex repurchased and cancelled 5.4 million common shares at an average price of $3.12 per share for total consideration of $16.8 million. During 2024, Baytex repurchased and cancelled 48.4 million common shares at an average price of $4.50 per share for total consideration of $217.9 million. The total consideration paid includes the commissions and fees paid as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased and cancelled are accounted for as a reduction in shareholders' capital at historical cost with any discount paid recorded to contributed surplus and any premium paid recorded to retained earnings.

During the nine months ended September 30, 2025, Baytex recorded a $0.4 million liability related to the 2% federal tax on equity repurchases (December 31, 2024 - $4.3 million), which is charged to shareholders’ equity.

The following dividends were declared by Baytex during the nine months ended September 30, 2025.

On October 30, 2025, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 2, 2026 to shareholders of record as at December 15, 2025.

For the three and nine months ended September 30, 2025 the Company recorded share-based compensation expense of $10.7 million and $13.1 million respectively ($2.3 million and $17.4 million for the three and nine months ended September 30, 2024) which is related to cash-settled awards.

The Company's closing share price on the TSX on September 30, 2025 was $3.26 (December 31, 2024 - $3.70 and September 30, 2024 - $4.04).

Baytex has a Share Award Incentive Plan pursuant to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share of Baytex or the equivalent cash value per restricted award at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares or the equivalent cash value on vesting; the number of common shares issued is determined by a performance multiplier. The multiplier can range between zero and two and is calculated based on a number of factors determined and approved by the Human Resources and Compensation Committee of the Board of Directors on an annual basis. The Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.

The weighted average fair value of share awards granted during the nine months ended September 30, 2025 was $2.92 per restricted and performance award ($4.28 for the nine months ended September 30, 2024).

Baytex has an Incentive Award Plan whereby the participants of the plan are entitled to receive a cash payment equal to the value of one Baytex common share per incentive award at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.

The weighted average fair value of share awards granted during the nine months ended September 30, 2025 was $2.91 per incentive award ($4.29 for the nine months ended September 30, 2024).

Baytex has a DSU Plan whereby each independent director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share per DSU award on the date at which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in share-based compensation liability.

The weighted average fair value of share awards granted during the nine months ended September 30, 2025 was $2.73 per DSU award ($4.57 for the nine months ended September 30, 2024).

The number of awards outstanding is detailed below:

Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the period.

For the three and nine months ended September 30, 2025 and 2024, no share awards were excluded from the calculation of diluted income per share.

Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table.

Included in trade receivables at September 30, 2025 is $264.2 million of accrued receivables related to delivered volumes (December 31, 2024 - $325.7 million).

The provision for income taxes has been computed as follows:

(1)The expected income tax rate decreased from 2024 due to changes in the provincial apportionment of Canadian income.

(2)A deferred tax asset of $22.4 million remains unrecognized due to uncertainty surrounding future capital gains (December 31, 2024 - $31.8 million). The unrecognized deferred income tax asset relates to realized and unrealized foreign exchange losses arising from the repayment of previously issued U.S. dollar denominated long-term notes and from the translation of U.S. dollar denominated long-term notes currently outstanding.

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During Q4/2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $232.9 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

The Company's financial assets and liabilities are comprised of cash, trade receivables, trade payables, dividends payable, financial derivatives, Credit Facilities and long-term notes. The fair value of trade receivables and trade payables approximates carrying value due to the short term to maturity. The fair value of the Credit Facilities is equal to the principal amount outstanding as the Credit Facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is based on quoted market prices. The fair value of the financial derivatives is based on quoted market prices or, in their absence, third-party market indications and forecasts.

The carrying value and fair value of the Company's financial instruments carried on the condensed consolidated statements of financial position are classified into the following categories:

There were no transfers between Level 1 and Level 2 during the nine months ended September 30, 2025 and 2024.

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:

As at October 30, 2025, Baytex had the following commodity financial derivative contracts.

(1)Based on the weighted average price per unit for the period.

(2)Contract entered subsequent to September 30, 2025.

(3)Contracts include deferred premiums to be paid throughout the contract term. The weighted average deferred premium is US$0.67bbl.

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.

The Company's capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute its development programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At September 30, 2025, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash and the Credit Facilities.

In order to manage its capital structure and liquidity, Baytex may from time-to-time issue or redeem equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

The capital-intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of adjusted funds flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity.

The Company uses net debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company defines net debt to be the sum of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables and prepaids and other assets. Baytex also uses net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.

The following table reconciles net debt to amounts disclosed in the primary financial statements.

Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirements obligations settled during the applicable period and transaction costs.

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2025. This information is provided as of October 30, 2025. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and nine months ended September 30, 2025 ("Q3/2025" and "YTD 2025") have been compared with the results for the three and nine months ended September 30, 2024 ("Q3/2024" and "YTD 2024"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2025, its audited comparative consolidated financial statements for the years ended December 31, 2024 and 2023, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2024. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning in accordance with International Financial Reporting Standards ("IFRS") as prescribed by the International Accounting Standards Board. The terms "operating netback", "free cash flow", "average royalty rate", "heavy oil, net of blending and other expense" and "total sales, net of blending and other expense" are specified financial measures that do not have any standardized meaning as prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. This MD&A also contains the terms "adjusted funds flow" and "net debt" which are capital management measures. Refer to our advisory on forward-looking information and statements and a summary of our specified financial measures at the end of the MD&A.

Baytex Energy Corp. is a North American focused oil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operated assets in Texas.

Baytex delivered strong operating and financial results in Q3/2025. Production of 150,950 boe/d and exploration and development expenditures of $270.4 million for Q3/2025 were consistent with our full-year plan and reflect our successful development programs in the U.S. and Canada. In the U.S., we successfully continued strong execution in the Eagle Ford with 15.6 net wells to sales. In Canada, we achieved record production in our Duvernay light oil operations and delivered a 5% increase in production from our heavy oil properties.

We spent $270.4 million on exploration and development expenditures in Q3/2025, compared to $306.3 million in Q3/2024 and consistent with our full year plan to spend approximately $1.2 billion. In the U.S., we invested $146.8 million and production averaged 82,765 boe/d during Q3/2025 compared to exploration and development expenditures of $185.9 million and production of 89,800 boe/d for Q3/2024. In Canada, we invested $123.6 million and generated production of 68,185 boe/d in Q3/2025 compared to exploration and development expenditures of $120.5 million and production of 64,668 boe/d in Q3/2024.

Oil prices were volatile during Q3/2025 due to concerns over global economic conditions along with increasing supply. The WTI benchmark price for Q3/2025 was US$64.93/bbl which was lower than Q3/2024 when WTI averaged US$75.10/bbl. Adjusted funds flow(1) of $422.2 million and cash flows from operating activities of $472.7 million for Q3/2025 reflect lower realized pricing compared to Q3/2024 when we generated adjusted funds flow of $537.9 million and cash flows from operating activities of $550.0 million.

(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.

Net debt(1) of $2.2 billion at September 30, 2025 was $172.8 million lower than at December 31, 2024. Free cash flow(2) of $198.4 million generated in YTD 2025 was allocated to debt repayment along with $38.7 million of shareholder returns including share buybacks and quarterly dividends. We expect net debt to decline over the remainder of 2025 as we continue to allocate free cash flow to the balance sheet after funding our dividend.

(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

We continue to execute our 2025 plan and anticipate full year production of approximately 148,000 boe/d and exploration and development expenditures of approximately $1.2 billion, consistent with our previous guidance. The following table compares our 2025 annual guidance to our YTD 2025 results.

(1)As announced on July 31, 2025.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

(3)As announced on December 3, 2024.

(4)Refer to Operating Expense, Transportation Expense, General and Administrative Expense and Financing and Interest Expense sections of this MD&A for a description of the composition of these measures.

(5)Cash interest per boe was updated to reflect the expected 2025 production of 148,000 boe/d.

(6)As announced on October 30, 2025.

(7)EBITDA is calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our operated and non-operated Eagle Ford assets in Texas.

Production was 150,950 boe/d for Q3/2025 and 147,771 boe/d for YTD 2025 compared to 154,468 boe/d for Q3/2024 and 153,099 boe/d for YTD 2024 which reflects lower development on our non-operated Eagle Ford assets and the disposition of non-core heavy oil assets in Q4/2024.

In Canada, production was 68,185 boe/d for Q3/2025 and 64,932 boe/d for YTD 2025 compared to 64,668 boe/d for Q3/2024 and 63,483 boe/d for YTD 2024. Our successful light and heavy oil development programs resulted in production that was 3,517 boe/d higher for Q3/2025 and 1,449 boe/d higher for YTD 2025 relative to the same periods of 2024 despite the disposition of 2,000 boe/d of heavy oil production from the Kerrobert thermal assets in Q4/2024.

In the U.S., production was 82,765 boe/d for Q3/2025 and 82,839 for YTD 2025 compared to 89,800 boe/d for Q3/2024 and 89,616 boe/d for YTD 2024. Lower production for both periods of 2025 reflects reduced non-operated Eagle Ford activity in late 2024 and early 2025. We initiated production from 23 (15.6 net) wells during Q3/2025 and 69 (46.2 net) wells during YTD 2025 compared to 35 (21.0 net) wells during Q3/2024 and 102 (58.1 net) wells during YTD 2024.

Total production of 147,771 boe/d for YTD 2025 is consistent with guidance of approximately 148,000 boe/d for 2025.

The prices received for our crude oil and natural gas production directly impact our earnings, free cash flow and our financial position.

During Q3/2025 and YTD 2025, global benchmark prices for crude oil were lower compared to the same periods of 2024 as a result of increasing supply and concerns over slowing global economic activity. The WTI benchmark price averaged US$64.93/bbl for Q3/2025 and US$66.70/bbl for YTD 2025 compared to US$75.10/bbl for Q3/2024 and US$77.54/bbl for YTD 2024.

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas. MEH is a representative benchmark for light oil pricing at the U.S. Gulf Coast which typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark averaged US$67.03/bbl during Q3/2025 and US$68.65/bbl during YTD 2025 compared to US$77.50/bbl for Q3/2024 and US$79.85/bbl for YTD 2024. The MEH benchmark premium to WTI was US$2.10/bbl for Q3/2025 and US$1.95/bbl for YTD 2025 compared to premiums of US$2.40/bbl for Q3/2024 and US$2.31/bbl for YTD 2024.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets and the cost of transportation from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada. Canadian oil differentials were narrower in Q3/2025 and YTD 2025 relative to both periods of 2024 after exports commenced from the TMX pipeline expansion in May 2024.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $86.20/bbl during Q3/2025 and $88.54/bbl during YTD 2025 compared to $97.91/bbl during Q3/2024 and $98.46/bbl during YTD 2024. Edmonton par traded at a discount to WTI of US$2.35/bbl for Q3/2025 and US$3.40/bbl for YTD 2025 compared to a discount of US$3.30/bbl for Q3/2024 and US$5.16/bbl for YTD 2024.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q3/2025 averaged $75.14/bbl and $77.80/bbl for YTD 2025 compared to $83.98/bbl for Q3/2024 and $84.45/bbl for YTD 2024. The WCS heavy oil differential to WTI was US$10.38/bbl in Q3/2025 and US$11.08/bbl in YTD 2025 compared to US$13.51/bbl for Q3/2024 and US$15.46/bbl for YTD 2024.

Natural gas prices in Canada and the U.S. were higher in both periods of 2025 compared to 2024 and reflect incremental demand and lower inventory levels.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$3.07/mmbtu for Q3/2025 and US$3.39/mmbtu for YTD 2025 compared to US$2.16/mmbtu for Q3/2024 and US$2.10/mmbtu for YTD 2024.

In Canada, we receive natural gas pricing based on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $1.00/mcf during Q3/2025 and $1.70/mcf for YTD 2025 which is higher than $0.81/mcf for Q3/2024 and $1.43/mcf for YTD 2024.

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2025 and 2024.

(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.

(2)MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.

(3)Edmonton par refers to the average posting price for the benchmark MSW crude oil.

(4)WCS refers to the average posting price for the benchmark WCS heavy oil.

(5)AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").

(6)NYMEX refers to the NYMEX last day average index price as published by the CGPR.

(1)Calculated as light oil and condensate or NGL sales divided by barrels of oil equivalent production volume for the applicable period, or natural gas sales divided by the production volume in Mcf for the applicable period.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

Our total sales, net of blending and other expense per boe(1) was $63.22/boe for Q3/2025 and $65.15/boe for YTD 2025 compared to $71.97/boe for Q3/2024 and $71.71/boe for YTD 2024. Our average realized sales price decreased due to lower WTI pricing partially offset by narrower Canadian oil differentials and higher natural gas prices.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) represents a discount to the Edmonton par price of $0.67/bbl for Q3/2025 and $1.22/bbl for YTD 2025 which is consistent with discounts of $1.33/bbl in Q3/2024 and $1.61/bbl in YTD 2024.

The price received for our U.S. light oil and condensate production is based on the MEH benchmark. Expressed in U.S. dollars, our realized light oil and condensate price(2) represents a discount to MEH of US$2.68/bbl for Q3/2025 and US$2.92/bbl for YTD 2025 consistent with a discount of US$2.83/bbl for Q3/2024 and US$3.04/bbl for YTD 2024.

Our realized heavy oil price, net of blending and other expense(1) was lower in Q3/2025 and YTD 2025 compared to the same periods of 2024 which reflects the decrease in WCS benchmark pricing. Our realized pricing for Q3/2025 and YTD 2025 represents a discount to the WCS benchmark of $8.09/bbl and $9.63/bbl compared to $7.98/bbl and $9.72/bbl for the same periods of 2024.

Our realized NGL price as a percentage of WTI varies based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Expressed in Canadian dollars, our realized NGL price(2) was 26% of WTI in Q3/2025 and 29% of WTI in YTD 2025 compared to 27% of WTI in Q3/2024 and 25% of WTI for YTD 2024.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. The increase in AECO and NYMEX benchmark prices for Q3/2025 and YTD 2025 resulted in higher realized natural gas pricing in Canada and the U.S. relative to both periods of 2024.

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

(2)Calculated as light oil and condensate or NGL sales divided by barrels of oil equivalent production volume for the applicable period, or natural gas sales divided by the production volume in Mcf for the applicable period.

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

Total sales, net of blending and other expense, was $877.9 million for Q3/2025 and $2.6 billion for YTD 2025 compared to $1.0 billion for Q3/2024 and $3.0 billion for YTD 2024. The decrease in total sales, net of blending and other expense reflects lower realized pricing and lower production in both periods of 2025 compared to 2024.

In Canada, total sales, net of blending and other expense, of $388.2 million for Q3/2025 and $1.1 billion for YTD 2025 decreased from $430.6 million reported for Q3/2024 and $1.2 billion for YTD 2024. The decrease in benchmark prices in Q3/2025 and YTD 2025 relative to Q3/2024 and YTD 2024 resulted in lower total sales, net of blending and other expense as production was higher than the same periods.

In the U.S., total petroleum and natural gas sales of $489.7 million for Q3/2025 and $1.5 billion for YTD 2025 decreased from $592.2 million reported for Q3/2024 and $1.8 billion for YTD 2024. Lower realized pricing resulted in a $56.0 million decrease in total sales in Q3/2025 relative to Q3/2024 while lower production contributed to a $46.4 million decrease in total sales relative to Q3/2024. Lower realized pricing resulted in a $133.3 million decrease in total sales in YTD 2025 relative to YTD 2024 while lower production contributed to a $141.0 million decrease in total sales relative to YTD 2024.

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2025 and 2024.

(1)Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

(3)Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period.

Royalties for Q3/2025 were $181.2 million or 20.6% of total sales, net of blending and other expense, compared to $223.8 million or 21.9% for Q3/2024. Total royalties for YTD 2025 were $566.6 million or 21.6% of total sales, net of blending and other expense, compared to $673.4 million or 22.4% for YTD 2024. Total royalty expense was lower for Q3/2025 and YTD 2025 due to lower total sales, net of blending and other expense, relative to the same periods of 2024.

Our average royalty rate in Canada of 13.8% for Q3/2025 and 14.4% for YTD 2025 was lower than 16.6% for Q3/2024 and 16.4% for YTD 2024 due to lower benchmark commodity prices. In the U.S., our average royalty rate was 26.1% for Q3/2025 and 26.9% for YTD 2025 which was relatively consistent with 25.7% for Q3/2024 and 26.5% for YTD 2024.

Our average royalty rate of 21.6% for YTD 2025 is consistent with our annual guidance of approximately 22% for 2025.

(1)Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period.

Total operating expense was $160.3 million ($11.54/boe) for Q3/2025 and $469.0 million ($11.63/boe) for YTD 2025 compared to $167.1 million ($11.76/boe) for Q3/2024 and $508.3 million ($12.12/boe) for YTD 2024. Total operating expense for both periods of 2025 decreased relative to 2024 due to lower production and per unit operating costs were slightly lower compared to the same periods as well.

In Canada, total operating expense was $85.0 million ($13.55/boe) for Q3/2025 and $248.6 million ($14.02/boe) for YTD 2025 compared to $87.4 million ($14.69/boe) for Q3/2024 and $257.2 million ($14.79/boe) for YTD 2024. Total operating expense in Canada for Q3/2025 decreased due to the disposition of higher cost non-core assets in Q4/2024 which also contributed to lower per unit operating expense of $13.55/boe for Q3/2025 and $14.02/boe for YTD 2025 compared to $14.69/boe for Q3/2024 and $14.79/boe for YTD 2024.

In the U.S., operating expense was $75.3 million ($9.89/boe) for Q3/2025 and $220.4 million ($9.75/boe) for YTD 2025 which was lower than $79.7 million ($9.65/boe) for Q3/2024 and $251.1 million ($10.22/boe) for YTD 2024. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$7.18/boe for Q3/2025 and US$6.97/boe for YTD 2025 which was consistent with US$7.08/boe for Q3/2024 and US$7.51/boe for YTD 2024. The decrease in total operating expense reflects lower production in both periods of 2025 compared to 2024.

Operating expense of $11.63/boe for YTD 2025 is slightly below our revised annual guidance range of $11.75 - $12.00/boe for 2025.

Transportation expense includes the costs incurred to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize sales prices and transportation rates.

The following table compares our transportation expense for the three and nine months ended September 30, 2025 and 2024.

(1)Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the applicable period.

Transportation expense was $35.3 million ($2.54/boe) for Q3/2025 and $98.7 million ($2.45/boe) for YTD 2025 consistent with $36.9 million ($2.60/boe) for Q3/2024 and $100.0 million ($2.38/boe) for YTD 2024.

Transportation expense of $2.45/boe for YTD 2025 is consistent with expectations and our annual guidance range of $2.40 - $2.55/boe for 2025.

Blending and other expense primarily includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines in order to meet pipeline specifications. The purchased diluent is recorded as blending and other expense. The price received for the blended product is recorded as heavy oil sales revenue. We net blending and other expense against heavy oil sales to compare the realized price on our produced volumes to benchmark pricing.

Blending and other expense was $49.8 million for Q3/2025 and $185.0 million for YTD 2025 compared to $51.9 million for Q3/2024 and $183.8 million for YTD 2024. Blending and other expense for Q3/2025 and YTD 2025 was comparable to Q3/2024 and YTD 2024 as heavy oil production was relatively consistent over the same periods.

Our business is exposed to fluctuations in commodity prices, foreign exchange rates and interest rates. We utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow caused by these exposures. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2025 and 2024.