Calgary, Alberta--(Newsfile Corp. - July 30, 2026) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex" or the "Company") reports its operating and financial results for the three and six months ended June 30, 2026 (all amounts are in Canadian dollars unless otherwise noted).

"Baytex delivered strong second-quarter results, highlighted by outperformance in the Duvernay and continued strength across our heavy oil portfolio," said Chad Lundberg, President and Chief Executive Officer. "Production exceeded the high end of guidance for the second consecutive quarter, and we are raising our full-year production guidance with no change to our capital program. Momentum continues to build as our teams execute our strategy while delivering strong operating and financial results."

Second Quarter Highlights

• Delivered production of 71,243 boe/d (88% oil and NGL), surpassing the high end of annual guidance and representing 11% growth relative to the second quarter of 2025.

• Full-year production raised to approximately 71,000 boe/d, a 1,000 boe/d increase from the mid-point of prior guidance, with exploration and development expenditures unchanged at approximately $625 million.

• Generated adjusted funds flow⁽¹⁾ of $254 million ($0.35 per basic share) and cash flows from operating activities of $231 million ($0.32 per basic share).

• Reported net income from continuing operations of $169 million ($0.23 per basic share).

• Generated free cash flow⁽²⁾ of $128 million ($0.18 per basic share) after exploration and development expenditures of $122 million.

• Repurchased 22 million common shares for $136 million, representing 3.0% of shares outstanding;

• Exited the second quarter with net cash⁽¹⁾ of $566 million, maintaining an industry-leading balance sheet.

(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("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 press release for further information.

2026 Outlook

Supported by strong well performance, annual production guidance has been increased to approximately 71,000 boe/d, representing 8% annual production growth in 2026 and a target exit rate of approximately 72,000 boe/d in Q4. The updated production guidance is driven by outperformance from our first Gilby Duvernay pad along with strong results across our heavy oil portfolio, where new well performance at Peavine exceeded internal expectations. Disciplined execution of our capital programs remains a priority, with exploration and development expenditures guidance unchanged at approximately $625 million.

Notes:
(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("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 press release for further information.
(3) Calculated in accordance with our credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

Notes:
(1) 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. The use of boe amounts 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.
(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 press release for further information.
(3) Other is comprised of realized foreign exchange gain or loss, cash other income or expense, current income tax expense or recovery and cash share-based compensation. Refer to the Q2/2026 MD&A for further information on these amounts.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated as royalties, operating expense, transportation expense, general and administrative expense, net cash interest income or expense, realized financial derivatives gain or loss, or other, divided by barrels of oil equivalent production volume for the applicable period for continuing operations.

Second Quarter 2026 Results

Q2 production exceeds guidance

Second quarter results were highlighted by outperformance across our light and heavy oil portfolio. Production of 71,243 boe/d (88% oil and NGL) exceeded the high end of our annual guidance range of 69,000 to 71,000 boe/d. Exploration and development expenditures of $122 million were consistent with our full-year plan.

Adjusted funds flow⁽¹⁾ of $254 million ($0.35 per basic share) includes $85 million of realized derivatives losses on oil contracts put in place at lower prices prior to the sale of our U.S. operations, we have no WTI hedges in place after Q2/2026. Disciplined execution of our capital program resulted in free cash flow⁽²⁾ of $128 million ($0.18 per basic share). We generated net income of $175 million ($0.24 per basic share) in the second quarter.

(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("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 press release for further information.

Strong new well results in the Duvernay

The first Duvernay pad (four wells) of 2026 was brought onstream in June and outperformed internal expectations. This was the first pad brought onstream on our new Gilby acreage to the south of our Pembina lands. The wells are amongst our strongest performing wells in the Duvernay to-date on a length normalized basis. Three of the wells delivered 30-day initial production rates of 1,630 boe/d per well (1,112 bbl/d of oil, 319 bbl/d of NGLs and 1,195 mcf/d of natural gas). The fourth well was completed at half the planned lateral length after the bottom hole assembly became stuck during drilling and was unrecoverable. This well delivered a 30-day initial production rate of 866 boe/d (537 bbl/d of oil, 202 bbl/d of NGLs and 759 mcf/d of natural gas). Results from Gilby support expectations of a high-quality reservoir and increase confidence in future development on our southern acreage.

Drilling operations are complete on the second Duvernay pad of our 2026 program, located on our northern Pembina acreage. Completion operations are underway and the pad is planned to be brought onstream in September. Our 2026 Duvernay program includes a total of 17 wells drilled and 13 wells brought onstream with the remaining 4 wells onstream in 2027.

Continued heavy oil outperformance with active second half program

Second quarter operating results reflect strong performance at Peavine, Peace River, and across the broader Mannville group in Lloydminster. A total of 14 wells were brought onstream; seven Clearwater wells at Peavine and seven wells at Lloydminster.

At Peavine, outperformance continued during the second quarter with six of the new wells brought onstream establishing 30-day initial production rates that average 478 bbl/d per well.

Heavy oil development activity has ramped following spring breakup, with four rigs running across our Peavine, Peace River and Lloydminster regions. A fifth rig is scheduled to begin drilling operations in August at Morinville. In total, the 2026 program is expected to bring 99.3 net heavy oil wells on stream during 2026 with 58 net wells expected to be brought onstream during Q3 and Q4.

Clearwater waterflood and additional pilots planned

Waterflood potential in the Clearwater is being evaluated to increase resource recovery and lower our sustaining capital requirements. Both initial waterflood pilots at Peavine are currently on injection. One of the pilots is designed to test reservoir repressurization through producer to injector conversion and the second pilot is testing pressure maintenance on new development.

The waterflood pilot will be expanded in the second half of 2026 with two additional patterns at Peavine and a waterflood test in the Rex formation (a Clearwater equivalent) at Morinville. These additional pilots are included in third quarter development plans and are expected to be on injection by the fourth quarter.

Heavy oil exploration at Peace River

A 21-square-mile seismic survey was recently completed covering 20% of our 109 sections of prospective lands at Utikuma in the Peace River region. Initial interpretations are encouraging and we are preparing to drill up to two exploration test wells in early 2027.

Delivering Shareholder Returns

During the second quarter, $152 million was returned to shareholders. A total of 22 million common shares were repurchased for $136 million, at an average price of $6.27 per share, and we paid a quarterly cash dividend of $16 million ($0.225 per share). Since the disposition of our U.S. business in December 2025 through July 29, 2026, we repurchased 69 million common shares for $378 million, representing 9% of our shares outstanding, at an average price of $5.46 per share.

On June 26, 2026, we announced the renewal of our Normal Course Issuer Bid ("NCIB") with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. The renewed NCIB allows Baytex to purchase up to 70.9 million common shares during the 12-month period commencing July 2, 2026 and ending July 1, 2027.

The second quarter ended with net cash⁽¹⁾ of $566 million.

(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.

Quarterly Dividend

The Board of Directors has declared a quarterly cash dividend of $0.0225 per share, payable October 1, 2026 to shareholders of record on September 15, 2026.

Board Changes

The Board of Directors is pleased to announce the appointment of Derek Evans and Deanna Zumwalt as independent directors of Baytex, effective July 30, 2026, following a process led by the Nominating and Governance Committee of the Board.

Derek Evans is a distinguished energy industry leader with more than four decades of experience. He served as President and Chief Executive Officer of MEG Energy, where he led a successful operational and financial turnaround over a six-year tenure, and previously as President and Chief Executive Officer of Pengrowth Energy, where he delivered the Lindbergh SAGD project on time and on budget. Following his retirement from MEG, Mr. Evans served as Executive Chairman of the Pathways Alliance and currently serves as Chair of the AltaGas board and a director of Franco-Nevada Corporation.

Deanna Zumwalt is a seasoned executive with broad experience across energy finance and operations. She spent over a decade at Nexen Energy in progressively senior roles spanning finance, natural gas and power, and North American crude oil marketing, before joining Coril Holdings Ltd., a privately held global investment company, where she served as President and Chief Executive Officer from 2021 to 2025, overseeing a diversified portfolio of assets across multiple sectors and geographies. Ms. Zumwalt has served as a director of SECURE Waste Infrastructure since 2019.

"We are pleased to welcome Derek and Deanna to the Baytex board," said Mark Bly, Chair of the Board of Directors. "Their combined experience and track record in the Canadian energy industry strengthen our board as we execute our strategy and advance opportunities in our portfolio. We look forward to their contributions in the years ahead."

Concurrent with these appointments Steve Reynish and Jeffrey Wojahn stepped down as directors. Following these changes, the Board of Directors comprises eight members, seven of whom are independent.

"We extend our sincere gratitude to Steve and Jeffrey for their guidance and contributions during their tenure and wish them well in their future endeavors," commented Mark Bly, Chair of the Board of Directors.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2026, 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: guidance for 2026 production, production growth rate, exit production rate and exportation and development expenditures; the number of wells to be drilled and brought on stream in heavy oil and the Duvernay in 2026; our plans with respect to waterflood development; and that we are planning to drill two Utikuma exploration well in early 2027. 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 drilling new wells; the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; 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 successfully market oil and natural gas; that we will have sufficient financial resources in the future to pursue our development plans and 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; 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; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; 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, 2025, 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 2026 guidance for development expenditures; that we can maintain a net cash position and the expected field-level operating income growth in Duvernay during our 3-year outlook period; and our intentions regarding excess 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 (surplus) 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 (cash) 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 - Canada

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 for Canada. 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 - Canada

Operating netback is 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 for Canada.

The following table reconciles operating netback to petroleum and natural gas sales for Canada.

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, and payments on lease obligations.

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

Working capital (surplus) deficiency

Working capital (surplus) deficiency is calculated as cash, trade receivables, prepaids and other assets, and inventory net of trade payables, share-based compensation liability, dividends payable, and other long-term liabilities. Working capital (surplus) deficiency is used by management to measure the Company's liquidity. On June 30, 2026, the Company had $745.6 million of available credit facility capacity to cover any working capital deficiencies.

The following table summarizes the calculation of working capital (surplus) 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 (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period for Canada.

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 for Canada and is used to assess our operating performance on a unit of production basis.

Capital Management Measures

Net (cash) debt

We use net (cash) debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net (cash) debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net (cash) 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, prepaids and other assets, and inventory.

The following table summarizes our calculation of net (cash) debt.

(1) Unamortized debt issuance costs were obtained from the Long-term Notes and Credit Facilities notes within the consolidated financial statements for the respective period end.

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, and asset retirement obligations settled 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 initial 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.

This press release discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex's proved, probable and unbooked locations. Proved locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves. Unbooked locations are farther away from existing wells and, therefore, there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty whether such wells will result in additional oil and gas reserves, resources or production. In the Duvernay, Baytex's net drilling locations include 58 proved and 11 probable locations as at December 31, 2025 and 141 unbooked locations. In the Viking, Baytex's net drilling locations include 457 proved and 196 probable locations as at December 31, 2025 and 263 unbooked locations. In the heavy oil business unit, Baytex's net drilling locations include 160 proved and 167 probable locations as at December 31, 2025 and 773 unbooked locations.

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, 2026 and 2025. 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 a Calgary-based energy company committed to driving shareholder value through disciplined execution. The Company operates in the Western Canadian Sedimentary Basin, featuring the Duvernay and heavy oil plays in Alberta and Saskatchewan. 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:

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