UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington,D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 Underthe

Securities Exchange Actof 1934

For the month of August 2025

Commission File Number: 1-32754

BAYTEX ENERGY CORP.

(Exact name of registrant as specified in its charter)

2800, 520 – 3^rd AVENUE S.W.

CALGARY, ALBERTA, CANADA

T2P 0R3

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annualreports under cover Form 20-F or Form 40-F.

Indicate by check mark if the registrant is submitting the Form 6-Kin paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-Kin paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing theinformation to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

If “Yes” is marked, indicate below the file number assignedto the registrant in connection with Rule 12g3-2(b):

The following document attached as an exhibit hereto is incorporatedby reference herein:

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Exhibit 99.1

BAYTEX DELIVERS SOLID SECOND QUARTER2025 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 resultsfor the three and six months ended June 30, 2025 (all amounts are in Canadian dollars unless otherwise noted).

“Baytex delivered solid operationaland financial results in the second quarter, with top-performing wells in the Pembina Duvernay, setting the highest average 30-day peakoil rates in the West Shale Basin,” said Eric T. Greager, President and Chief Executive Officer. “Combined with strong resultsacross heavy oil operations and the Eagle Ford, including continued success with refracs, these results demonstrate the resource potentialand value creation opportunities within our portfolio. We remain focused on disciplined capital allocation, prioritizing free cash flowand 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 priceenvironment, we are targeting annual production of approximately 148,000 boe/d with full-year exploration and development expendituresof 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 secondhalf of the year given our production and capital spending profile. We plan to allocate 100% of free cash flow to debt repayment afterfunding quarterly dividend payments, targeting net debt of approximately $2 billion by year-end.

We remain committed to disciplined capitalallocation, prioritizing free cash flow and strengthening our balance sheet. We will continue to monitor market conditions and executea 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 operatingand 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% ($96million) to $2.3 billion, driven by unrealized foreign exchange gains from a strengthening Canadian dollar on our U.S. dollar-denominateddebt. 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 withUS$1.1 billion in credit facilities that mature in June 2029 and are less than 25% drawn, positioning us well across various commodityprice cycles.

Operations

Production averaged 148,095 boe/d (84% oil andNGL) in the second quarter, representing a 2% increase in production per basic share compared to Q2/2024. Consistent with our full-yearplan, 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 drillingand completion costs per completed lateral foot compared to 2024. We also completed two successful refracs that are delivering initialrates 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 average30-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 businessaveraged 16,349 boe/d (81% oil and NGL), relatively unchanged from Q1/2025. The Pembina Duvernay represents our largest growth assetand 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 average30-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 secondpad (08-08, 3 wells) came onstream through early July with similar lateral lengths, and over the last 26 days has averaged 1,264boe/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 onstreamin September.

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

We have assembled 140 net sections of highlyprospective 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 increaseto 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 broaderMannville group in Lloydminster. During the quarter, we brought onstream 43 net wells: 15 Clearwater wells at Peavine, 4 wells at PeaceRiver, and 24 wells at Lloydminster.

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

Quarterly Dividend

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

Additional Information

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

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex’sshareholders and potential investors with information regarding Baytex, including management’s assessment of Baytex’s futureplans and operations, certain statements in this press release are “forward-looking statements” within the meaning of the UnitedStates Private Securities Litigation Reform Act of 1995 and “forward-looking information” within the meaning of applicableCanadian securities legislation (collectively, “forward-looking statements”). In some cases, forward-looking statements canbe 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 expresslyqualified by this cautionary statement.

Specifically, this press release containsforward-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 productionand the amount of free cash flow we expect to generate and its expected allocation; our targeted net debt at year-end 2025; the opportunityfor 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, basedon certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitablyproduced in the future.

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

Actual resultsachieved 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 resultof tariffs); risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefitsof acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions orcosts imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand forpetroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership andkey personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associatedwith higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; risks associatedwith achieving our total debt target, production guidance, exploration and development expenditures guidance; the amount of free cashflow we expect to generate; risk that the board of directors determines to allocate capital other than as set forth herein; current orfuture controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influenceon the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated withour hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and naturalgas 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 andgas industry; risk that we do not achieve our GHG emissions intensity reduction target; risks associated with our use of informationtechnology 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 Indigenousclaims; risks of counterparty default; impact of geopolitical risk and conflicts, loss of foreign private issuer status; conflicts ofinterest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownershipof our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, includingthe ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residentsand foreign exchange risk; and other factors, many of which are beyond our control. Readers are cautioned that the foregoing list ofrisk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of suchfactors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination offactors, may cause actual results to differ materially from those contained in any forward-looking statements.

Any decisionto pay dividends on the Common Shares (including the actual amount, the declaration date, the record date and the payment date in connectiontherewith) or acquire Common Shares pursuant to a share buyback (including through the current Normal Course Issuer Bid) will be subjectto 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 futuretime including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtednessthat the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvencytests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Companywill acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured orguaranteed and dividends may be reduced or suspended entirely.

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

This press releasecontains information that may be considered a financial outlook under applicable securities laws about the Company’s potentialfinancial 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 andthe resulting financial results will vary from the amounts set forth in this press release and such variations may be material. Thisinformation has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculativeand are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not tobe relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligationto update such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook containedin this press release was made as of the date of this press release and was provided for the purpose of providing further informationabout the Company’s potential future business operations. Readers are cautioned that the financial outlook contained in this pressrelease is not conclusive and is subject to change.

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

Specified Financial Measures

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

Non-GAAP Financial Measures

Total sales, net of blending and otherexpense

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

Operating netback

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

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

Free cash flow

We use free cash flow to evaluate our financialperformance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Freecash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to explorationand 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 activitiesin the following table.

Working capital deficiency

Working capital deficiency is calculated ascash, 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 capitaldeficiency.

 

		As at
($ thousands)		June 30, 2025			March 31, 2025			June 30, 2024
Cash		$	(7,156	)	$	(5,966	)	$	(35,887	)
Trade receivables			(363,507	)		(391,905	)		(429,098	)
Prepaids and other assets			(75,856	)		(72,045	)		(81,805	)
Trade payables			538,330			582,053			617,222
Share-based compensation liability			13,851			12,602			22,706
Dividends payable			17,304			17,334			19,845
Other long-term liabilities			19,751			20,849			18,161
Working capital deficiency		$	142,717		$	162,922		$	131,144

Non-GAAP Financial Ratios

Total sales, net of blending and other expense per boe

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

Operating netback per boe

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

Capital Management Measures

Net debt

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

The following table summarizes our calculation of net debt.

 

		As at
($ thousands)		June 30, 2025			March 31, 2025			June 30, 2024
Credit facilities		$	317,310		$	234,683		$	607,589
Unamortized debt issuance costs - Credit facilities (1)			16,206			15,601			18,387
Long-term notes			1,776,647			1,930,809			1,833,182
Unamortized debt issuance costs - Long-term notes (1)			41,060			46,235			48,712
Trade payables			538,330			582,053			617,222
Share-based compensation liability			13,851			12,602			22,706
Dividends payable			17,304			17,334			19,845
Other long-term liabilities			19,751			20,849			18,161
Cash			(7,156	)		(5,966	)		(35,887	)
Trade receivables			(363,507	)		(391,905	)		(429,098	)
Prepaids and other assets			(75,856	)		(72,045	)		(81,805	)
Net debt		$	2,293,940		$	2,390,250		$	2,639,014

Adjusted funds flow

Adjusted funds flow is used to monitor operatingperformance 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 retirementobligations settled, and transaction costs during the applicable period.

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

 

		Three Months Ended										Six Months Ended
($ thousands)		June 30, 2025				March 31, 2025			June 30, 2024			June 30, 2025			June 30, 2024
Cash flow from operating activities		$	354,312			$	431,317		$	505,584		$	785,629		$	889,357
Change in non-cash working capital			9,042				29,034			20,140			38,076			52,163
Asset retirement obligations settled			3,565				3,519			7,115			7,084			13,626
Transaction costs			—				—			—			—			1,539
Adjusted funds flow		$	366,919			$	463,870		$	532,839		$	830,789		$	956,685

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent amounts havebeen calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularlyif 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 equivalencyconversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

Throughout this press release, “oiland 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 sixmonths ended June 30, 2025 and 2024. The NI 51-101 product types are included as follows: “Heavy Crude Oil” - heavycrude 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 withheadquarters based in Calgary, Alberta and offices in Houston, Texas. The Company is engaged in the acquisition, development and productionof crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Baytex’s commonshares 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 atwww.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 and2024

Dated July 31, 2025

The following is management’s discussionand analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months endedJune 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 itssubsidiaries 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 condensedconsolidated 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 theaccompanying notes, and its Annual Information Form (“AIF”) for the year ended December 31, 2024. These documentsand additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities andExchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousandsof 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 representsan energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. Whileit 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 informationand statements along with certain measures which do not have any standardized meaning in accordance with International Financial ReportingStandards (“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 “totalsales, net of blending and other expense” are specified financial measures that do not have any standardized meaning as prescribedby IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. ThisMD&A also contains the terms “adjusted funds flow” and “net debt” which are capital management measures. Referto 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 focusedoil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States (“U.S.”). The Canadianoperating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster andour conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operatedassets in Texas.

SECOND QUARTER HIGHLIGHTS

Baytex delivered strong operating and financialresults in Q2/2025. Production of 148,095 boe/d and exploration and development expenditures of $356.5 million for Q2/2025 were consistentwith our full-year plan and reflect our successful development programs in the U.S. and Canada. In the U.S., we successfully completedtwo refracs on our operated Eagle Ford properties that extend inventory duration and improve capital efficiencies. In Canada, we achievedrecord 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 developmentexpenditures 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 expendituresof $237.7 million and production of 90,506 boe/d for Q2/2024. In Canada, we invested $147.7 million and generated production of 64,167boe/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 togeopolitical events along with concerns over global economic conditions. The WTI benchmark price for Q2/2025 was US$63.74/bbl which waslower than Q2/2024 when WTI averaged US$80.57/bbl. Adjusted funds flow⁽¹⁾ of $366.9 million and cash flows from operatingactivities of $354.3 million for Q2/2025 were primarily a result of lower realized pricing compared to Q2/2024 when we generated adjustedfunds flow of $532.8 million and cash flows from operating activities of $505.6 million.

Net debt⁽¹⁾ of $2.3 billion atJune 30, 2025 was $123.2 million lower than at December 31, 2024. Free cash flow⁽²⁾ of $55.7 million generatedin 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 fundingour dividend.

2025 GUIDANCE

We continue to execute our 2025 plan and anticipatefull year production of approximately 148,000 boe/d and exploration and development expenditures of approximately $1.2 billion, consistentwith 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 Vikingand 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 and146,156 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 ournon-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 Q2/2025and 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 oildevelopment programs resulted in production that was 479 boe/d higher for Q2/2025 and 395 boe/d higher for YTD 2025 relative to the sameperiods 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 forQ2/2025 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 periodsof 2025 reflects reduced non-operated Eagle Ford activity in late 2024 and early 2025. We initiated production from 19 (14.9 net) wellsduring 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 duringYTD 2024.

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

COMMODITY PRICES

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

Crude Oil

During Q2/2025 and YTD 2025, global benchmarkprices for crude oil were lower compared to the same periods of 2024 as a result of increasing supply, geopolitical events and concernsover slowing global economic activity. The WTI benchmark price averaged US$63.74/bbl for Q2/2025 and US$67.58/bbl for YTD 2025 comparedto US$80.57/bbl for Q2/2024 and US$78.77/bbl for YTD 2024.

We compare the price received for our U.S. crudeoil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for lightoil 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 comparedto 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 Q2/2024and US$2.26/bbl for YTD 2024.

Prices for Canadian oil trade at a discount toWTI due to a lack of egress to diversified markets and the cost of transportation from Western Canada. Differentials for Canadian oilprices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada. Canadian oil differentialswere 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 oilproduction in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $84.15/bbl during Q2/2025 and $89.71/bblduring 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/bblfor 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 oilproduction 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 comparedto $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/bblin 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. werehigher 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 inreference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$3.44/mmbtufor 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 basedon the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. TheAECO 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/mcffor 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 averageof NYMEX prompt month WTI for the applicable period.

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

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

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

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

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

Average Realized Sales Prices

Our total sales, net of blending and other expenseper 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 forYTD 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 Canadato the Edmonton par benchmark price. Our realized light oil and condensate price⁽²⁾ represents a discount to the Edmontonpar 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/bblin YTD 2024.

The price received for our U.S. light oil andcondensate production is based on the MEH benchmark. Expressed in U.S. dollars, our realized light oil and condensate price⁽²⁾ representsa 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/bblfor YTD 2024.

Our realized heavy oil price, net of blendingand other expense⁽¹⁾ was lower in Q2/2025 and YTD 2025 compared to the same periods of 2024 which reflects the decreasein 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/bblcompared to $9.43/bbl and $10.61/bbl for the same periods of 2024.

Our realized NGL price as a percentage of WTIvaries based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Expressed in Canadiandollars, our realized NGL price⁽²⁾ was 29% of WTI in Q2/2025 and 30% of WTI in YTD 2025, which reflects strong ethanepricing compared to 24% of WTI in Q2/2024 and 25% of WTI for YTD 2024.

We compare our realized natural gas price inthe U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. The increase in AECO and NYMEX benchmark prices for Q2/2025and 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. Thedecrease in total sales, net of blending and other expense reflects lower realized pricing and lower production in both periods of 2025compared to 2024.

In Canada, total sales, net of blending and otherexpense, of $348.7 million for Q2/2025 and $730.0 million for YTD 2025 decreased from $440.9 million reported for Q2/2024 and $793.0million for YTD 2024. The decrease in benchmark prices in Q2/2025 and YTD 2025 relative to Q2/2024 and YTD 2024 was the primary factorthat resulted in lower total sales, net of blending and other expense over the same periods.

In the U.S., total petroleum and natural gassales 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 billionfor YTD 2024. Lower realized pricing resulted in a $103.6 million decrease in total sales in Q2/2025 relative to Q2/2024 while lowerproduction contributed to a $45.4 million decrease in total sales relative to Q2/2024. Lower realized pricing resulted in a $77.3 milliondecrease in total sales in YTD 2025 relative to YTD 2024 while lower production contributed to a $94.6 million decrease in total salesrelative to YTD 2024.

ROYALTIES

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