Exhibit 99.1

BAYTEX DELIVERS SOLID SECOND QUARTER 2025 RESULTS WITH RECORD
PEMBINA DUVERNAY WELL PERFORMANCE AND CONTINUED DEBT REDUCTION

CALGARY, ALBERTA (July 31, 2025) - Baytex Energy Corp. (“Baytex” or the “Company”) (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2025 (all amounts are in Canadian dollars unless otherwise noted).

“Baytex delivered solid operational and financial results in the second quarter, with top-performing wells in the Pembina Duvernay, setting the highest average 30-day peak oil rates in the West Shale Basin,” said Eric T. Greager, President and Chief Executive Officer. “Combined with strong results across heavy oil operations and the Eagle Ford, including continued success with refracs, these results demonstrate the resource potential and value creation opportunities within our portfolio. We remain focused on disciplined capital allocation, prioritizing free cash flow and debt reduction while capitalizing on the most compelling opportunities from our high-quality assets.”

Second Quarter 2025 Highlights

2025 Outlook

In light of the current commodity price environment, we are targeting annual production of approximately 148,000 boe/d with full-year exploration and development expenditures of approximately $1.2 billion. Production is expected to average approximately 150,000 boe/d in the second half of 2025.

Based on forward strip pricing(3), we expect to generate approximately $400 million of free cash flow(4) in 2025, with the majority weighted to the second half of the year given our production and capital spending profile. We plan to allocate 100% of free cash flow to debt repayment after funding quarterly dividend payments, targeting net debt of approximately $2 billion by year-end.

We remain committed to disciplined capital allocation, prioritizing free cash flow and strengthening our balance sheet. We will continue to monitor market conditions and execute a prudent approach to shareholder returns, which has historically included a combination of share buybacks and quarterly dividend payments.

Notes:

Notes:

Financial Results

During the second quarter, we delivered operating and financial results in line with our full-year plan. Adjusted funds flow(1) was $367 million ($0.48 per basic share) and net income was $152 million ($0.20 per basic share).

We generated free cash flow(2) of $3 million and returned $21 million to shareholders through share repurchases of $4 million (1.7 million shares at an average price of $2.36) and a quarterly dividend payment of $17 million.

Net debt(1) decreased 4% ($96 million) to $2.3 billion, driven by unrealized foreign exchange gains from a strengthening Canadian dollar on our U.S. dollar-denominated debt. During the quarter, we repurchased and cancelled US$41 million principal amount of the 8.5% long-term notes below par.

We maintain strong financial flexibility with US$1.1 billion in credit facilities that mature in June 2029 and are less than 25% drawn, positioning us well across various commodity price cycles.

Operations

Production averaged 148,095 boe/d (84% oil and NGL) in the second quarter, representing a 2% increase in production per basic share compared to Q2/2024. Consistent with our full-year plan, exploration and development expenditures for Q2/2025 totaled $357 million and we brought 74 (66.5 net) wells onstream.

Inventory Extension Through Successful Eagle Ford Refracs

Eagle Ford production averaged 83,928 boe/d (81% oil and NGL), up 3% from Q1/2025. We brought onstream 14.9 net wells while realizing an approximate 11% improvement in operated drilling and completion costs per completed lateral foot compared to 2024. We also completed two successful refracs that are delivering initial rates comparable to our broader development program with improved capital efficiencies and returns.

The two refracs (Moulton A5H and Renee Unit 2H) were brought onstream in April and May with average completed lateral lengths of 1,648 meters (5,406 feet) and generated average 30-day peak production rates of 963 boe/d per well (734 bbl/d of crude oil, 124 bbl/d of NGLs, 631 Mcf/d of natural gas).

The refrac program extends inventory duration – we have identified approximately 300 refrac opportunities across our acreage and anticipate an expanded program in 2026.

Record Pembina Duvernay Well Results Demonstrate Asset Potential

Production from our Canadian light oil business averaged 16,349 boe/d (81% oil and NGL), relatively unchanged from Q1/2025. The Pembina Duvernay represents our largest growth asset and accounts for 40% of Canadian light oil production, with the remaining 60% from Viking operations.

The first Pembina Duvernay pad (07-01, 3 wells) from our 2025 program was brought onstream in May with average lateral lengths of 3,800 meters (12,500 feet) and generated average 30-day peak production rates of 1,865 boe/d per well (1,239 bbl/d of crude oil, 422 bbl/d of NGLs, 1,224 Mcf/d of natural gas). The second pad (08-08, 3 wells) came onstream through early July with similar lateral lengths, and over the last 26 days has averaged 1,264 boe/d per well (709 bbl/d of crude oil, 352 bbl/d of NGLs, 1,220 Mcf/d of natural gas. The third pad (10-31, 3 wells) is expected onstream in September.

The first two pads have exceeded initial rate expectations with the first pad delivering the highest peak oil rates to-date in the West Shale Basin. These results demonstrate our continued advancement in drilling and completion performance and facility enhancements. Strong production performance, combined with an approximate 12% improvement in drilling and completion costs per completed lateral foot compared to 2024 has significantly improved well economics.

We have assembled 140 net sections of highly prospective lands and identified approximately 200 drilling locations. As we transition to full commercialization over the next two years, we plan to implement a one-rig drilling program with 18 to 20 wells per year. At this development pace, we expect production to increase to 20,000-25,000 boe/d by 2029-2030, up from 6,665 boe/d in the second quarter.

Organic Heavy Oil Growth

Heavy oil production averaged 44,895 boe/d (96% oil and NGL), up 7% from Q1/2025. Strong operating results reflect continued performance at Peavine, Peace River, and across the broader Mannville group in Lloydminster. During the quarter, we brought onstream 43 net wells: 15 Clearwater wells at Peavine, 4 wells at Peace River, and 24 wells at Lloydminster.

Our heavy oil operations deliver the strongest economic returns across the portfolio, supported by our extensive acreage position, capital-efficient development, and the continued strength in Western Canadian Select pricing.

Quarterly Dividend

The Board of Directors has declared a quarterly cash dividend of $0.0225 per share, payable October 1, 2025 to shareholders of record on September 15, 2025.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2025 and the related Management’s Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov/ edgar.shtml.

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex’s shareholders and potential investors with information regarding Baytex, including management’s assessment of Baytex’s future plans and operations, certain statements in this press release are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 and “forward-looking information” within the meaning of applicable Canadian securities legislation (collectively, “forward-looking statements”). In some cases, forward-looking statements can be identified by terminology such as “believe”, “continue”, “estimate”, “expect”, “forecast”, “intend”, “may”, “objective”, “ongoing”, “outlook”, “potential”, “project”, “plan”, “should”, “target”, “would”, “will” or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to but not limited to: we are focused on disciplined capital allocation, prioritizing free cash flow, debt reduction and maximizing shareholder returns; for 2025: our guidance for exploration and development expenditures and production and the amount of free cash flow we expect to generate and its expected allocation; our targeted net debt at year-end 2025; the opportunity for refracs on our Eagle Ford acreage and the expected 2026 refrac program; and our Pembina Duvernay development plans. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy crude oil prices; well production rates and reserve volumes; success obtained in drilling new wells; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; our ability to market oil and natural gas successfully; that we will have sufficient financial resources in the future to provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices (including as a result of tariffs); risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; risks associated with achieving our total debt target, production guidance, exploration and development expenditures guidance; the amount of free cash flow we expect to generate; risk that the board of directors determines to allocate capital other than as set forth herein; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risk that we do not achieve our GHG emissions intensity reduction target; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts, loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Any decision to pay dividends on the Common Shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith) or acquire Common Shares pursuant to a share buyback (including through the current Normal Course Issuer Bid) will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely.

These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2024 filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings. The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.

This press release contains information that may be considered a financial outlook under applicable securities laws about the Company’s potential financial position, including, but not limited to, our 2025 guidance for development expenditures; our expected 2025 free cash flow; and our intentions regarding the allocating our annual free cash flow; all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Company and the resulting financial results will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about the Company’s potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

Specified Financial Measures

In this press release, we refer to certain financial measures (such as total sales, net of blending and other expense, operating netback, free cash flow, and working capital deficiency) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This press release also contains the terms “adjusted funds flow” and “net debt” which are considered capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.

Non-GAAP Financial Measures

Total sales, net of blending and other expense

Total sales, net of blending and other expense represents the revenues realized from produced volumes during a period. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. We believe including the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.

Operating netback

Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales less blending expense, royalties, operating expense and transportation expense.

The following table reconciles total sales, net of blending and other expense and operating netback to petroleum and natural gas sales.

Free cash flow

We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties, payments on lease obligations, and transaction costs.

Free cash flow is reconciled to cash flows from operating activities in the following table.

Working capital deficiency

Working capital deficiency is calculated as cash, trade receivables, and prepaids and other assets net of trade payables, share-based compensation liability, dividends payable, and other long-term liabilities. Working capital deficiency is used by management to measure the Company’s liquidity. At June 30, 2025, the Company had $1.2 billion of available credit facility capacity to cover any working capital deficiencies.

The following table summarizes the calculation of working capital deficiency.

Non-GAAP Financial Ratios

Total sales, net of blending and other expense per boe

Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is calculated as total sales, net of blending and other expense divided by barrels of oil equivalent production volume for the applicable period.

Operating netback per boe

Operating netback per boe is equal to operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent sales volume for the applicable period and is used to assess our operating performance on a unit of production basis.

Capital Management Measures

Net debt

We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash, trade receivables, and prepaids and other assets.

The following table summarizes our calculation of net debt.

Adjusted funds flow

Adjusted funds flow is used to monitor operating performance and our 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 retirement obligations settled, and transaction costs during the applicable period.

Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

References herein to average 30-day peak production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

Throughout this press release, “oil and NGL” refers to heavy crude oil, bitumen, light and medium crude oil, tight oil, condensate and natural gas liquids (“NGL”) product types as defined by NI 51-101. The following table shows Baytex’s disaggregated production volumes for the three and six months ended June 30, 2025 and 2024. The NI 51-101 product types are included as follows: “Heavy Crude Oil” - heavy crude oil and bitumen, “Light and Medium Crude Oil” - light and medium crude oil, tight oil and condensate, “NGL” - natural gas liquids and “Natural Gas” - shale gas and conventional natural gas.

Baytex Energy Corp.

Baytex Energy Corp. is an energy company with headquarters based in Calgary, Alberta and offices in Houston, Texas. The Company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Baytex’s common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit our website at www.baytexenergy.com or contact:

Brian Ector, Senior Vice President, Capital Markets & Investor Relations

Toll Free Number: 1-800-524-5521

Email: investor@baytexenergy.com

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2025 and 2024

Dated July 31, 2025

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2025. This information is provided as of July 31, 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 six months ended June 30, 2025 (“Q2/2025” and “YTD 2025”) have been compared with the results for the three and six months ended June 30, 2024 (“Q2/2024” 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 six months ended June 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.

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.

SECOND QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q2/2025. Production of 148,095 boe/d and exploration and development expenditures of $356.5 million for Q2/2025 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 completed two refracs on our operated Eagle Ford properties that extend inventory duration and improve capital efficiencies. In Canada, we achieved record well performance in our Duvernay light oil operations and delivered a 7% increase in production from our heavy oil properties.

We spent $356.5 million on exploration and development expenditures in Q2/2025, compared to $339.6 million in Q2/2024 and consistent with our full year plans to spend approximately $1.2 billion. In the U.S., we invested $208.8 million and production averaged 83,928 boe/d during Q2/2025 compared to exploration and development expenditures of $237.7 million and production of 90,506 boe/d for Q2/2024. In Canada, we invested $147.7 million and generated production of 64,167 boe/d in Q2/2025 compared to exploration and development expenditures of $101.9 million and production of 63,688 boe/d in Q2/2024.

Oil prices were volatile during Q2/2025 due to geopolitical events along with concerns over global economic conditions. The WTI benchmark price for Q2/2025 was US$63.74/bbl which was lower than Q2/2024 when WTI averaged US$80.57/bbl. Adjusted funds flow(1) of $366.9 million and cash flows from operating activities of $354.3 million for Q2/2025 were primarily a result of lower realized pricing compared to Q2/2024 when we generated adjusted funds flow of $532.8 million and cash flows from operating activities of $505.6 million.

Net debt(1) of $2.3 billion at June 30, 2025 was $123.2 million lower than at December 31, 2024. Free cash flow(2) of $55.7 million generated in YTD 2025 was allocated to debt repayment along with $51.4 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.

2025 GUIDANCE

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. We have fine-tuned several of our cost assumptions to reflect lower production and lower commodity prices. The following table compares our 2025 annual guidance to our YTD 2025 results.

RESULTS OF OPERATIONS

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

Production was 148,095 boe/d for Q2/2025 and 146,156 boe/d for YTD 2025 compared to 154,194 boe/d for Q2/2024 and 152,407 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 64,167 boe/d for Q2/2025 and 63,279 boe/d for YTD 2025 compared to 63,688 boe/d for Q2/2024 and 62,884 boe/d for YTD 2024. Our successful light and heavy oil development programs resulted in production that was 479 boe/d higher for Q2/2025 and 395 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 83,928 boe/d for Q2/2025 and 82,877 for YTD 2025 compared to 90,506 boe/d for Q2/2024 and 89,523 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 19 (14.9 net) wells during Q2/2025 and 46 (30.6 net) wells during YTD 2025 compared to 30 (14.8 net) wells during Q2/2024 and 67 (37.2 net) wells during YTD 2024.

Total production of 146,156 boe/d for YTD 2025 is consistent with expectations. We are expecting production of approximately 148,000 boe/d for 2025 which reflects average production of approximately 150,000 boe/d over the second half of 2025.

COMMODITY PRICES

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

Crude Oil

During Q2/2025 and YTD 2025, global benchmark prices for crude oil were lower compared to the same periods of 2024 as a result of increasing supply, geopolitical events and concerns over slowing global economic activity. The WTI benchmark price averaged US$63.74/bbl for Q2/2025 and US$67.58/bbl for YTD 2025 compared to US$80.57/bbl for Q2/2024 and US$78.77/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 which is a representative benchmark for light oil pricing at the U.S. Gulf Coast. The MEH benchmark averaged US$65.56/bbl during Q2/2025 and US$69.47/bbl during YTD 2025 compared to US$83.10/bbl for Q2/2024 and US$81.03/bbl for YTD 2024, and typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$1.82/ bbl for Q2/2025 and US$1.89/bbl for YTD 2025 compared to premiums of US$2.53/bbl for Q2/2024 and US$2.26/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 Q2/2025 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 $84.15/bbl during Q2/2025 and $89.71/bbl during YTD 2025 compared to $105.30/bbl during Q2/2024 and $98.73/ bbl during YTD 2024. Edmonton par traded at a discount to WTI of US$2.94/bbl for Q2/2025 and $3.93/bbl for YTD 2025 compared to a discount of US$3.62/bbl for Q2/2024 and $6.10/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 Q2/2025 averaged $74.10/bbl and $79.15/bbl for YTD 2025 compared to $91.72/bbl for Q2/2024 and $84.68/bbl for YTD 2024. The WCS heavy oil differential to WTI was US$10.20/bbl in Q2/2025 and US$11.43/bbl in YTD 2025 compared to US$13.55/bbl for Q2/2024 and US$16.44/bbl for YTD 2024.

Natural Gas

Natural gas prices in Canada and the U.S. were higher in both periods of 2025 compared to 2024 and reflect incremental demand from cold winter weather 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$3.44/mmbtu for Q2/2025 and US$3.55/mmbtu for YTD 2025 compared to US$1.89/ mmbtu for Q2/2024 and US$2.07/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 $2.07/mcf during Q2/2025 and $2.05/ mcf for YTD 2025 which is higher than $1.44/mcf for Q2/2024 and $1.74/mcf for YTD 2024.

The following tables compare select benchmark prices and our average realized selling prices for the three and six months ended June 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.

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $61.16/boe for Q2/2025 and $66.17/boe for YTD 2025 compared to $75.93/boe for Q2/2024 and $71.58/boe for YTD 2024. Our average realized sales price decreased due to lower WTI pricing partially offset by narrower Canadian oil differentials, higher natural gas prices and improved NGL realizations.

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 $1.61/bbl for Q2/2025 and $1.39/bbl for YTD 2025 which is consistent with discounts of $2.09/bbl in Q2/2024 and $1.71/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$2.89/bbl for Q2/2025 and $3.01/bbl for YTD 2025 consistent with a discount of US$2.93/bbl for Q2/2024 and $3.10/bbl for YTD 2024.

Our realized heavy oil price, net of blending and other expense(1) was lower in Q2/2025 and YTD 2025 compared to the same periods of 2024 which reflects the decrease in WCS benchmark pricing. Our realized pricing for Q2/2025 and YTD 2025 represents a discount to the WCS benchmark of $9.67/bbl and $10.36/bbl compared to $9.43/bbl and $10.61/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 29% of WTI in Q2/2025 and 30% of WTI in YTD 2025, which reflects strong ethane pricing compared to 24% of WTI in Q2/2024 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 Q2/2025 and YTD 2025 resulted in higher realized natural gas pricing in Canada and the U.S. relative to both periods of 2024.

PETROLEUM AND NATURAL GAS SALES

Total sales, net of blending and other expense, was $824.2 million for Q2/2025 and $1.8 billion for YTD 2025 compared to $1.1 billion for Q2/2024 and $2.0 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 $348.7 million for Q2/2025 and $730.0 million for YTD 2025 decreased from $440.9 million reported for Q2/2024 and $793.0 million for YTD 2024. The decrease in benchmark prices in Q2/2025 and YTD 2025 relative to Q2/2024 and YTD 2024 was the primary factor that resulted in lower total sales, net of blending and other expense over the same periods.

In the U.S., total petroleum and natural gas sales of $475.5 million for Q2/2025 and $1.0 billion for YTD 2025 decreased from $624.6 million reported for Q2/2024 and $1.2 billion for YTD 2024. Lower realized pricing resulted in a $103.6 million decrease in total sales in Q2/2025 relative to Q2/2024 while lower production contributed to a $45.4 million decrease in total sales relative to Q2/2024. Lower realized pricing resulted in a $77.3 million decrease in total sales in YTD 2025 relative to YTD 2024 while lower production contributed to a $94.6 million decrease in total sales relative to YTD 2024.

ROYALTIES

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 six months ended June 30, 2025 and 2024.

Royalties for Q2/2025 were $177.4 million or 21.5% of total sales, net of blending and other expense, compared to $240.4 million or 22.6% for Q2/2024. Total royalties for YTD 2025 were $385.3 million or 22.0% of total sales, net of blending and other expense, compared to $449.6 million or 22.6% for YTD 2024. Total royalty expense was lower for Q2/2025 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 13.7% for Q2/2025 and 14.7% for YTD 2025 was lower than 16.5% for Q2/2024 and 16.3% for YTD 2024 due to lower benchmark commodity prices. In the U.S., our average royalty rate was 27.3% for both periods of 2025 which was relatively consistent with 26.8% for both periods of 2024.

Our average royalty rate of 22.0% for YTD 2025 is consistent with expectations and we have updated our annual guidance to approximately 22% for 2025.

OPERATING EXPENSE

Total operating expense was $161.0 million ($11.95/boe) for Q2/2025 and $308.7 million ($11.67/boe) for YTD 2025 compared to $167.7 million ($11.95/boe) for Q2/2024 and $341.1 million ($12.30/boe) for YTD 2024. Total operating expense for both periods of 2025 decreased relative to 2024 due to lower production while per unit operating costs were relatively consistent over the same periods.

In Canada, total operating expense was $88.0 million ($15.08/boe) for Q2/2025 and $163.6 million ($14.29/boe) for YTD 2025 compared to $84.4 million ($14.57/boe) for Q2/2024 and $169.8 million ($14.84/boe) for YTD 2024. Operating expense in Canada for Q2/2025 has increased with higher production relative to Q2/2024 while per unit operating expense of $15.08/boe for Q2/2025 and $14.29/boe for YTD 2025 was relatively consistent with $14.57/boe for Q2/2024 and $14.84/boe for YTD 2024.

In the U.S., operating expense was $73.0 million ($9.56/boe) for Q2/2025 and $145.1 million ($9.67/boe) for YTD 2025 which was lower than $83.3 million ($10.11/boe) for Q2/2024 and $171.3 million ($10.51/boe) for YTD 2024. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$6.91/boe for Q2/2025 and US$6.86/boe for YTD 2025 which was lower than US$7.39/boe for Q2/2024 and US$7.74/boe for YTD 2024. The decrease in total and per unit operating expense reflects our cost savings initiatives and lower production in both periods of 2025 compared to 2024.

Operating expense of $11.67/boe for YTD 2025 is consistent with expectations and slightly below our annual guidance range of $11.75 - $12.50/boe for 2025.

TRANSPORTATION EXPENSE

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 six months ended June 30, 2025 and 2024.

Transportation expense was $32.9 million ($2.44/boe) for Q2/2025 and $63.4 million ($2.40/boe) for YTD 2025 consistent with $33.3 million ($2.37/boe) for Q2/2024 and $63.1 million ($2.28/boe) for YTD 2024.

Per unit transportation expense of $2.40/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

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 $62.4 million for Q2/2025 and $135.2 million for YTD 2025 compared to $67.7 million for Q2/2024 and $131.9 million for YTD 2024. Blending and other expense for Q2/2025 was comparable to Q2/2024 and YTD 2024 as heavy oil production was relatively consistent over the same periods.

FINANCIAL DERIVATIVES

Our business is exposed to fluctuations in commodity prices, foreign exchange rates, interest rates and changes in our share price. 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 six months ended June 30, 2025 and 2024.

We recorded a total financial derivatives gain of $18.7 million for Q2/2025 and a loss of $31.0 million for YTD 2025 compared to a gain of $8.5 million for Q2/2024 and a loss of $18.3 million for YTD 2024. The realized financial derivatives loss of $12.1 million for YTD 2025 resulted from losses of $13.3 million on crude oil contracts and gains of $1.2 million on natural gas contracts. The unrealized financial derivatives loss of $18.9 million for YTD 2025 resulted from a $15.6 million loss on crude oil contracts and a $3.3 million loss on natural gas contracts. The fair value of our financial derivative contracts resulted in a net asset of $5.0 million at June 30, 2025 compared to a net asset of $23.9 million at December 31, 2024.

Refer to Note 16 of the consolidated financial statements for a complete listing of our outstanding contracts at July 31, 2025.

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and six months ended June 30, 2025 and 2024.