EX-99.1 2 tm2526117d2_ex99-1.htm EXHIBIT 99.1

Exhibit 99.1

BAYTEX DELIVERS SOLID THIRD QUARTER 2025 RESULTS WITH RECORD PEMBINA
DUVERNAY PRODUCTION AND STRONG FREE CASH FLOW

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

“Baytex delivered solid third-quarter results highlighted by record production in the Pembina Duvernay, strong free cash flow generation, and further progress on debt reduction,” said Eric T. Greager, President and Chief Executive Officer. “Our heavy oil business continues to generate reliable returns and, through targeted land acquisitions, we are expanding our long-term inventory. In the Pembina Duvernay, a strategic property swap further consolidates our position, setting the stage for full-scale development. These results reinforce our focus on disciplined capital allocation and demonstrate the quality and value creation potential of our asset base as we work to drive sustainable value for shareholders.”

Third Quarter 2025 Highlights

•

Delivered production of 150,950 boe/d (86% oil and NGL), a 1% increase in production per basic share compared to Q3/2024.

•

Generated free cash flow⁽¹⁾ of $143 million ($0.19 per basic share).

•

Achieved record Pembina Duvernay production of 10,185 boe/d (77% oil and NGL), up 53% compared to Q2/2025.

•

Increased heavy oil production 5% over Q2/2025 with continued strong performance.

•

Brought 15.6 net wells to sales in the Eagle Ford with strong execution, achieving a 12% improvement in drilling and completion costs, compared to 2024.

•

Expanded our heavy oil development fairway and consolidated Pembina Duvernay acreage through targeted land acquisitions and a property swap.

•

Reported cash flows from operating activities of $473 million ($0.62 per basic share).

•

Generated net income of $32 million ($0.04 per basic share).

•

Delivered adjusted funds flow⁽²⁾ of $422 million ($0.55 per basic share).

•

Reduced net debt⁽²⁾ by 2% ($50 million) and maintained balance sheet strength with a total debt⁽³⁾ to Bank EBITDA⁽³⁾ ratio of 1.1x.

2025 Outlook

We remain committed to disciplined capital allocation, prioritizing free cash flow and strengthening our balance sheet. We continue to execute our 2025 plan and anticipate full-year production of approximately 148,000 boe/d with exploration and development expenditures of approximately $1.2 billion.

Based on year-to-date actual results and the forward strip for the balance of 2025⁽⁴⁾ we expect to generate free cash flow⁽²⁾of approximately $300 million in 2025. We continue to allocate 100% of free cash flow to debt repayment after funding quarterly dividend payments, targeting net debt of approximately $2.1 billion by year-end.

Our 2026 capital budget will be released in January following approval by our Board of Directors.

(1)

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.

(2)

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

(3)

Ratio is calculated as total debt on September 30, 2025 divided by EBITDA for the twelve months ended September 30, 2025. Total debt and EBITDA are calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

(4)

Q4/2025 commodity prices: WTI - US$60/bbl; WCS differential - US$12/bbl; NYMEX Gas - US$3.40/MMbtu; Exchange Rate (CAD/USD) - 1.39.

	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,			September 30,
	2025			2025			2024			2025			2024
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales	$	927,648		$	886,579		$	1,074,623		$	2,813,357		$	3,191,938
Adjusted funds flow ⁽¹⁾		422,232			366,919			537,947			1,253,021			1,494,632
Per share – basic		0.55			0.48			0.68			1.63			1.84
Per share – diluted		0.55			0.48			0.67			1.62			1.84
Free cash flow ⁽²⁾		142,688			3,188			220,159			198,405			400,744
Per share – basic		0.19			—			0.28			0.26			0.49
Per share – diluted		0.18			—			0.28			0.26			0.49
Cash flows from operating activities		472,676			354,312			550,042			1,258,305			1,439,399
Per share – basic		0.62			0.46			0.69			1.64			1.78
Per share – diluted		0.61			0.46			0.69			1.63			1.77
Net income		31,968			151,549			185,219			253,108			275,074
Per share – basic		0.04			0.20			0.23			0.33			0.34
Per share – diluted		0.04			0.20			0.23			0.33			0.34
Dividends declared		17,326			17,304			17,732			51,919			54,387
Per share		0.0225			0.0225			0.0225			0.0675			0.0675

Capital Expenditures
Exploration and development expenditures	$	270,364		$	356,532		$	306,332		$	1,031,993		$	1,058,456
Acquisitions and divestitures		15,770			468			(394	)		15,229			35,638
Total oil and natural gas capital expenditures	$	286,134		$	357,000		$	305,938		$	1,047,222		$	1,094,094

Net Debt
Credit facilities	$	182,345		$	333,516		$	466,108		$	182,345		$	466,108
Long-term notes		1,855,605			1,817,707			1,856,869			1,855,605			1,856,869
Total debt ⁽³⁾		2,037,950			2,151,223			2,322,977			2,037,950			2,322,977
Working capital deficiency ⁽²⁾		206,408			142,717			170,292			206,408			170,292
Net debt ⁽¹⁾	$	2,244,358		$	2,293,940		$	2,493,269		$	2,244,358		$	2,493,269

Shares Outstanding - basic (thousands)
Weighted average		768,317			768,717			796,064			769,481			810,589
End of period		768,317			768,317			787,328			768,317			787,328

BENCHMARK PRICES
Crude oil
WTI (US$/bbl)	$	64.93		$	63.74		$	75.10		$	66.70		$	77.54
MEH oil (US$/bbl)		67.03			65.56			77.50			68.65			79.85
MEH oil differential to WTI (US$/bbl)		2.10			1.82			2.40			1.95			2.31
Edmonton par ($/bbl)		86.20			84.15			97.91			88.54			98.46
Edmonton par differential to WTI (US$/bbl)		(2.35	)		(2.94	)		(3.30	)		(3.40	)		(5.16	)
WCS heavy oil ($/bbl)		75.14			74.10			83.98			77.80			84.45
WCS differential to WTI (US$/bbl)		(10.38	)		(10.20	)		(13.51	)		(11.08	)		(15.46	)
Natural gas
NYMEX (US$/MMbtu)	$	3.07		$	3.44		$	2.16		$	3.39		$	2.10
AECO ($/Mcf)		1.00			2.07			0.81			1.70			1.43

CAD/USD average exchange rate		1.3774			1.3840			1.3636			1.3988			1.3603

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 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 amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

2	Baytex Energy Corp. Third Quarter Report 2025

	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,			September 30,
	2025			2025			2024			2025			2024
OPERATING
Daily Production
Light oil and condensate (bbl/d)		64,935			62,108			69,843			63,136			67,645
Heavy oil (bbl/d)		45,269			42,959			42,759			42,825			42,342
NGL (bbl/d)		19,067			19,948			19,836			19,353			19,767
Total liquids (bbl/d)		129,271			125,015			132,438			125,314			129,754
Natural gas (Mcf/d)		130,076			138,482			132,175			134,742			140,069
Oil equivalent (boe/d @ 6:1) ⁽¹⁾		150,950			148,095			154,468			147,771			153,099

Adjusted Funds Flow (thousands of Canadian dollars)
Total sales, net of blending and other expense ⁽²⁾	$	877,898		$	824,198		$	1,022,721		$	2,628,406		$	3,008,143
Royalties		(181,230	)		(177,390	)		(223,800	)		(566,557	)		(673,411	)
Operating expense		(160,284	)		(161,020	)		(167,119	)		(469,007	)		(508,259	)
Transportation expense		(35,295	)		(32,907	)		(36,883	)		(98,714	)		(100,032	)
Operating netback ⁽²⁾	$	501,089		$	452,881		$	594,919		$	1,494,128		$	1,726,441
General and administrative expense		(20,736	)		(22,220	)		(17,895	)		(68,562	)		(61,313	)
Cash interest		(43,873	)		(44,875	)		(50,109	)		(135,535	)		(157,335	)
Realized financial derivatives (loss) gain		(8,580	)		(11,874	)		331			(20,648	)		3,562
Other ⁽³⁾		(5,668	)		(6,993	)		10,701			(16,362	)		(16,723	)
Adjusted funds flow ⁽⁴⁾	$	422,232		$	366,919		$	537,947		$	1,253,021		$	1,494,632

Adjusted Funds Flow (per boe)
Total sales, net of blending and other expense ⁽²⁾	$	63.22		$	61.16		$	71.97		$	65.15		$	71.71
Royalties ⁽⁵⁾		(13.05	)		(13.16	)		(15.75	)		(14.04	)		(16.05	)
Operating expense ⁽⁵⁾		(11.54	)		(11.95	)		(11.76	)		(11.63	)		(12.12	)
Transportation expense ⁽⁵⁾		(2.54	)		(2.44	)		(2.60	)		(2.45	)		(2.38	)
Operating netback ⁽²⁾	$	36.09		$	33.61		$	41.86		$	37.03		$	41.16
General and administrative expense ⁽⁵⁾		(1.49	)		(1.65	)		(1.26	)		(1.70	)		(1.46	)
Cash interest ⁽⁵⁾		(3.16	)		(3.33	)		(3.53	)		(3.36	)		(3.75	)
Realized financial derivatives (loss) gain ⁽⁵⁾		(0.62	)		(0.88	)		0.02			(0.51	)		0.08
Other (3)(5)		(0.42	)		(0.52	)		0.76			(0.40	)		(0.40	)
Adjusted funds flow	$	30.40		$	27.23		$	37.85		$	31.06		$	35.63

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)

(3)

Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax recovery or expense and cash share-based compensation. Refer to the Q3/2025 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, cash interest, realized financial derivatives gain or loss, or other, divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp. Third Quarter Report 2025

Financial Results

During the third quarter, we delivered operating and financial results in line with our full-year plan. Adjusted funds flow⁽¹⁾ was $422 million ($0.55 per basic share) and net income was $32 million ($0.04 per basic share).

We generated free cash flow⁽²⁾ of $143 million and returned $17 million to shareholders through our quarterly dividend.

Net debt⁽¹⁾ decreased 2% ($50 million) to $2.2 billion, driven by strong free cash flow, partially offset by an unrealized foreign exchange loss from a weakening Canadian dollar on our U.S. dollar-denominated debt.

We maintain strong financial flexibility with US$1.1 billion in credit facilities that mature in June 2029 and are less than 15% drawn, positioning us well across various commodity price cycles.

Operations

Production averaged 150,950 boe/d (86% oil and NGL) in the third quarter, representing a 1% increase in production per basic share compared to Q3/2024. Consistent with our full-year plan, exploration and development expenditures for Q3/2025 totaled $270 million and we brought 69 (61.6 net) wells onstream.

Oil-Focused Eagle Ford Development

Eagle Ford production averaged 82,765 boe/d (82% oil and NGL), relatively unchanged from Q2/2025. Crude oil production averaged 52,330 bbl/d, up 3% from Q2/2025.

Our 2025 development program has largely focused on the black oil to condensate windows of our acreage. We brought 15.6 net wells onstream while achieving a 12% improvement in operated drilling and completion costs per completed lateral foot compared to 2024.

During the second quarter we successfully completed two refracs in the Lower Eagle Ford. The wells continue to deliver results comparable to our broader development program with improved capital efficiencies and returns. We anticipate an expanded refrac program in 2026.

Record Pembina Duvernay Production

Production from our Canadian light oil business averaged 19,589 boe/d (80% oil and NGL), up 20% from Q2/2025. The Pembina Duvernay represents our largest growth asset and accounted for approximately 50% of Canadian light oil production during the quarter.

We achieved record Pembina Duvernay production of 10,185 boe/d (77% oil and NGL) in Q3/2025, up 53% from Q2/2025. The third pad (10-31, 3 wells) from our 2025 program was brought onstream in September with two of three wells generating strong 30-day peak production rates averaging 1,380 boe/d per well (830 bbl/d of crude oil, 355 bbl/d of NGLs, 1,172 Mcf/d of natural gas). The third well encountered casing issues during completion and was subsequently abandoned.

Our 2025 program (3 pads, 8 producing wells) exceeded initial rate expectations and sets the stage for full commercialization. Strong production, combined with an 11% 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. Over the next two years, we expect to transition to a one-rig drilling program with 18 to 20 wells per year, targeting production of 20,000-25,000 boe/d by 2029-2030.

Subsequent to quarter-end, we completed an asset swap in the Pembina Duvernay consolidating our southern acreage. This enables more efficient development of these lands commencing in 2026. In addition, in support of our ongoing development, we commissioned midstream infrastructure associated with our partnership with Gibson Energy. Construction of the infrastructure was completed on time and under budget.

(1)

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

(2)

4	Baytex Energy Corp. Third Quarter Report 2025

Organic Heavy Oil Growth and Inventory Expansion

Heavy oil production averaged 47,280 boe/d (96% oil and NGL), up 5% from Q2/2025. Strong operating results reflect continued performance at Peavine, Peace River, and across the broader Mannville group in Lloydminster. We brought onstream 20.0 net wells during the quarter: 10 Clearwater wells at Peavine, 4 wells at Peace River, and 6 wells at Lloydminster.

We continue to build on our heavy oil expertise and enhance our long-term inventory of development prospects. During the quarter, we acquired 40.5 net sections of highly prospective lands at Peace River, and 4.5 net sections in northeast Alberta targeting the broader Mannville group.

To-date in 2025, through organic development and land acquisitions, we have added 200 drilling locations to our inventory count, bringing our heavy oil portfolio to 1,100 drilling locations. This supports approximately 10 years of drilling at our current pace of development.

Our heavy oil operations continue to deliver the strongest economic returns across our portfolio, supported by our extensive acreage, 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 January 2, 2026 to shareholders of record on December 15, 2025.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and nine months ended September 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: that we are working to drive sustainable value for shareholders; we are focused on disciplined capital allocation, prioritizing free cash flow, and strengthening our balance sheet; for 2025: our guidance for exploration and development expenditures, production and the amount of free cash flow we expect to generate and its expected allocation as between debt reduction and dividend payments; our targeted net debt at year-end 2025; the expected release date for our 2026 capital budget; the opportunity for an expanded 2026 refrac program; that our Pembina Duvernay lands are highly prospective, that we will transition to a one-rig program drilling 18-20 wells per year over the next two years and our targeted production of 25,000 boe/d by 2029-2030; and the number of years of drilling activity our heavy oil portfolio supports. 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.

Baytex Energy Corp. Third Quarter Report 2025

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.

6	Baytex Energy Corp. Third Quarter Report 2025

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

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

	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,			September 30,
($ thousands)	2025			2025			2024			2025			2024
Petroleum and natural gas sales	$	927,648		$	886,579		$	1,074,623		$	2,813,357		$	3,191,938
Blending and other expense		(49,750	)		(62,381	)		(51,902	)		(184,951	)		(183,795	)
Total sales, net of blending and other expense	$	877,898		$	824,198		$	1,022,721		$	2,628,406		$	3,008,143
Royalties		(181,230	)		(177,390	)		(223,800	)		(566,557	)		(673,411	)
Operating expense		(160,284	)		(161,020	)		(167,119	)		(469,007	)		(508,259	)
Transportation expense		(35,295	)		(32,907	)		(36,883	)		(98,714	)		(100,032	)
Operating netback	$	501,089		$	452,881		$	594,919		$	1,494,128		$	1,726,441
Realized financial derivatives (loss) gain ⁽¹⁾		(8,580	)		(11,874	)		331			(20,648	)		3,562
Operating netback after realized financial derivatives	$	492,509		$	441,007		$	595,250		$	1,473,480		$	1,730,003

(1)

Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See the Financial Instruments and Risk Management note within the consolidated financial statements for the respective period end for further information.

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.

	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,			September 30,
($ thousands)	2025			2025			2024			2025			2024
Cash flows from operating activities	$	472,676		$	354,312		$	550,042		$	1,258,305		$	1,439,399
Change in non-cash working capital		(55,961	)		9,042			(20,813	)		(17,885	)		31,350
Additions to exploration and evaluation assets		—			(930	)		—			(930	)		—
Additions to oil and gas properties		(270,364	)		(355,602	)		(306,332	)		(1,031,063	)		(1,058,456	)
Payments on lease obligations		(3,663	)		(3,634	)		(2,738	)		(10,022	)		(13,088	)
Transaction costs		—			—			—			—			1,539
Free cash flow	$	142,688		$	3,188		$	220,159		$	198,405		$	400,744

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 September 30, 2025, the Company had $1.3 billion of available credit facility capacity to cover any working capital deficiencies.

Baytex Energy Corp. Third Quarter Report 2025

The following table summarizes the calculation of working capital deficiency.

	As at
($ thousands)	September 30, 2025			June 30, 2025			September 30, 2024
Cash	$	(10,417	)	$	(7,156	)	$	(21,311	)
Trade receivables		(324,287	)		(363,507	)		(375,942	)
Prepaids and other assets		(75,100	)		(75,856	)		(78,427	)
Trade payables		554,057			538,330			584,696
Share-based compensation liability		24,666			13,851			23,962
Dividends payable		17,326			17,304			17,732
Other long-term liabilities		20,163			19,751			19,582
Working capital deficiency	$	206,408		$	142,717		$	170,292

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.

	As at
($ thousands)	September 30, 2025			June 30, 2025			September 30, 2024
Credit facilities	$	166,841		$	317,310		$	449,116
Unamortized debt issuance costs - Credit facilities ⁽¹⁾		15,504			16,206			16,992
Long-term notes		1,815,230			1,776,647			1,810,701
Unamortized debt issuance costs - Long-term notes ⁽¹⁾		40,375			41,060			46,168
Trade payables		554,057			538,330			584,696
Share-based compensation liability		24,666			13,851			23,962
Dividends payable		17,326			17,304			17,732
Other long-term liabilities		20,163			19,751			19,582
Cash		(10,417	)		(7,156	)		(21,311	)
Trade receivables		(324,287	)		(363,507	)		(375,942	)
Prepaids and other assets		(75,100	)		(75,856	)		(78,427	)
Net debt	$	2,244,358		$	2,293,940		$	2,493,269

(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, asset retirement obligations settled, and transaction costs during the applicable period.

8	Baytex Energy Corp. Third Quarter Report 2025

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

	Three Months Ended								Nine Months Ended
	September 30,			June 30,		September 30,			September 30,			September 30,
($ thousands)	2025			2025		2024			2025			2024
Cash flow from operating activities	$	472,676		$	354,312	$	550,042		$	1,258,305		$	1,439,399
Change in non-cash working capital		(55,961	)		9,042		(20,813	)		(17,885	)		31,350
Asset retirement obligations settled		5,517			3,565		8,718			12,601			22,344
Transaction costs		—			—		—			—			1,539
Adjusted funds flow	$	422,232		$	366,919	$	537,947		$	1,253,021		$	1,494,632

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.

This presentation discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex’s total 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 42 proved and 20 probable locations as at December 31, 2024 and 153 unbooked locations. In the heavy oil business unit, Baytex’s net drilling locations include 149 proved and 112 probable locations as at December 31, 2024 and 839 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 nine months ended September 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.

	Three Months Ended September 30, 2025										Three Months Ended September 30, 2024
	Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)		Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)
Canada – Heavy
Peace River		9,900		13		38		10,079		11,631		9,024		13		36		11,959		11,067
Lloydminster		13,260		26		1		1,224		13,491		12,792		19		—		1,659		13,088
Peavine		20,953		—		—		—		20,953		20,085		—		—		—		20,085
Remaining Properties		1,094		3		—		648		1,205		846		1		—		494		929

Canada - Light
Viking		56		7,500		210		9,832		9,404		—		9,328		183		9,152		11,036
Duvernay		—		4,824		3,068		13,758		10,185		—		4,019		2,276		7,529		7,550
Remaining Properties		6		239		168		5,420		1,316		12		401		38		2,773		913

United States
Eagle Ford		—		52,330		15,582		89,115		82,765		—		56,062		17,303		98,609		89,800
Total		45,269		64,935		19,067		130,076		150,950		42,759		69,843		19,836		132,175		154,468

Baytex Energy Corp. Third Quarter Report 2025

	Nine Months Ended September 30, 2025										Nine Months Ended September 30, 2024
	Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)		Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)
Canada – Heavy
Peace River		9,805		13		30		9,850		11,490		9,206		10		41		10,931		11,079
Lloydminster		12,362		20		—		1,188		12,580		13,211		16		—		1,566		13,488
Peavine		19,455		—		—		—		19,455		19,211		—		—		—		19,211
Remaining Properties		1,113		2		—		687		1,229		706		32		—		344		795

Canada - Light
Viking		85		8,015		187		10,302		10,004		—		8,881		185		10,264		10,776
Duvernay		—		3,478		2,488		9,485		7,547		—		2,782		1,892		6,291		5,723
Remaining Properties		5		324		494		10,823		2,627		8		402		373		9,766		2,411

United States
Eagle Ford		—		51,284		16,154		92,407		82,839		—		55,522		17,276		100,907		89,616
Total		42,825		63,136		19,353		134,742		147,771		42,342		67,645		19,767		140,069		153,099

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

10	Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2025 and 2024

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

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

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

BAYTEX ENERGY CORP.

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.

THIRD QUARTER HIGHLIGHTS

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

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

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

(1)

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

Baytex Energy Corp. Third Quarter Report 2025

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

(1)

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

(2)

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. The following table compares our 2025 annual guidance to our YTD 2025 results.

	2025 Annual Guidance	YTD 2025 Results
Exploration and development expenditures ⁽¹⁾	~ $1.2 billion	$1.0 billion
Production (boe/d) ⁽¹⁾	~ 148,000	147,771

Expenses:
Average royalty rate ⁽¹⁾⁽²⁾	~ 22%	21.6 %
Operating ⁽⁴⁾⁽⁶⁾	$11.75 - $12.00/boe	$11.63/boe
Transportation ⁽³⁾⁽⁴⁾	$2.40 - $2.55/boe	$2.45/boe
General and administrative ⁽¹⁾⁽⁴⁾	$95 million ($1.76/boe)	$68.6 million ($1.70/boe)
Cash interest ^(3)(4)(5)	$180 million ($3.33/boe)	$135.5 million ($3.36/boe)
Current income tax ⁽⁶⁾	< 1% of EBITDA ⁽⁷⁾	0.1% of EBITDA ⁽⁷⁾

Leasing expenditures	$15 million	$10 million
Asset retirement obligations	$20 million	$12.6 million

(1)

As announced on July 31, 2025.

(2)

(3)

As announced on December 3, 2024.

(4)

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

(5)

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

(6)

As announced on October 30, 2025.

(7)

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

12	Baytex Energy Corp. Third Quarter Report 2025

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

	Three Months Ended September 30
	2025									2024
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		12,605			52,330			64,935			13,781			56,062			69,843
Heavy oil		45,269			—			45,269			42,759			—			42,759
Natural Gas Liquids (NGL)		3,485			15,582			19,067			2,533			17,303			19,836
Total liquids (bbl/d)		61,359			67,912			129,271			59,073			73,365			132,438
Natural gas (mcf/d)		40,961			89,115			130,076			33,566			98,609			132,175
Total production (boe/d)		68,185			82,765			150,950			64,668			89,800			154,468

Production Mix
Segment as a percent of total		45	%		55	%		100	%		42	%		58	%		100	%

Light oil and condensate		19	%		63	%		43	%		21	%		63	%		45	%
Heavy oil		66	%		—	%		30	%		66	%		—	%		28	%
NGL		5	%		19	%		13	%		4	%		19	%		13	%
Natural gas		10	%		18	%		14	%		9	%		18	%		14	%

	Nine Months Ended September 30
	2025									2024
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		11,852			51,284			63,136			12,123			55,522			67,645
Heavy oil		42,825			—			42,825			42,342			—			42,342
Natural Gas Liquids (NGL)		3,199			16,154			19,353			2,491			17,276			19,767
Total liquids (bbl/d)		57,876			67,438			125,314			56,956			72,798			129,754
Natural gas (mcf/d)		42,335			92,407			134,742			39,162			100,907			140,069
Total production (boe/d)		64,932			82,839			147,771			63,483			89,616			153,099

Production Mix
Segment as a percent of total		44	%		56	%		100	%		41	%		59	%		100	%

Light oil and condensate		18	%		62	%		43	%		19	%		62	%		44	%
Heavy oil		66	%		—	%		29	%		67	%		—	%		28	%
NGL		5	%		20	%		13	%		4	%		19	%		13	%
Natural gas		11	%		18	%		15	%		10	%		19	%		15	%

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

Baytex Energy Corp. Third Quarter Report 2025

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

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

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

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

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

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

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

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

Natural Gas

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

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

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

14	Baytex Energy Corp. Third Quarter Report 2025

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

	Three Months Ended September 30									Nine Months Ended September 30
	2025			2024			Change			2025			2024			Change
Benchmark Averages
WTI oil (US$/bbl) ⁽¹⁾		64.93			75.10			(10.17	)		66.70			77.54			(10.84	)
MEH oil (US$/bbl) ⁽²⁾		67.03			77.50			(10.47	)		68.65			79.85			(11.20	)
MEH oil differential to WTI (US$/bbl)		2.10			2.40			(0.30	)		1.95			2.31			(0.36	)
Edmonton par oil ($/bbl) ⁽³⁾		86.20			97.91			(11.71	)		88.54			98.46			(9.92	)
Edmonton par oil differential to WTI (US$/bbl)		(2.35	)		(3.30	)		0.95			(3.40	)		(5.16	)		1.76
WCS heavy oil ($/bbl) ⁽⁴⁾		75.14			83.98			(8.84	)		77.80			84.45			(6.65	)
WCS heavy oil differential to WTI (US$/bbl)		(10.38	)		(13.51	)		3.13			(11.08	)		(15.46	)		4.38
AECO natural gas ($/mcf) ⁽⁵⁾		1.00			0.81			0.19			1.70			1.43			0.27
NYMEX natural gas (US$/mmbtu) ⁽⁶⁾		3.07			2.16			0.91			3.39			2.10			1.29
CAD/USD average exchange rate		1.3774			1.3636			0.0138			1.3988			1.3603			0.0385

(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.

	Three Months Ended September 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) ⁽¹⁾	$	85.53	$	88.63	$	88.03	$	96.58	$	101.82	$	100.78
Heavy oil, net of blending and other expense ($/bbl) ⁽²⁾		67.05		—		67.05		76.00		—		76.00
NGL ($/bbl) ⁽¹⁾		22.62		23.83		23.60		26.04		27.66		27.45
Natural gas ($/mcf) ⁽¹⁾		0.65		3.52		2.62		1.00		2.53		2.14
Total sales, net of blending and other expense ($/boe) ⁽²⁾	$	61.88	$	64.32	$	63.22	$	72.37	$	71.68	$	71.97

	Nine Months Ended September 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) ⁽¹⁾	$	87.32	$	91.94	$	91.08	$	96.85	$	104.49	$	103.12
Heavy oil, net of blending and other expense ($/bbl) ⁽²⁾		68.17		—		68.17		74.73		—		74.73
NGL ($/bbl) ⁽¹⁾		24.47		27.29		26.82		25.76		27.03		26.87
Natural gas ($/mcf) ⁽¹⁾		1.49		4.07		3.26		1.61		2.42		2.20
Total sales, net of blending and other expense ($/boe) ⁽²⁾	$	63.08	$	66.78	$	65.15	$	70.34	$	72.68	$	71.71

(1)

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

(2)

Baytex Energy Corp. Third Quarter Report 2025

Average Realized Sales Prices

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

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

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

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

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

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

(1)

(2)

16	Baytex Energy Corp. Third Quarter Report 2025

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended September 30
	2025								2024
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	99,188		$	426,712	$	525,900		$	122,452		$	525,135	$	647,587
Heavy oil		329,005			—		329,005			350,859			—		350,859
NGL		7,250			34,154		41,404			6,067			44,034		50,101
Total oil sales		435,443			460,866		896,309			479,378			569,169		1,048,547
Natural gas sales		2,462			28,877		31,339			3,089			22,987		26,076
Total petroleum and natural gas sales		437,905			489,743		927,648			482,467			592,156		1,074,623
Blending and other expense		(49,750	)		—		(49,750	)		(51,902	)		—		(51,902	)
Total sales, net of blending and other expense ⁽¹⁾	$	388,155		$	489,743	$	877,898		$	430,565		$	592,156	$	1,022,721

	Nine Months Ended September 30
	2025								2024
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	282,532		$	1,287,251	$	1,569,783		$	321,704		$	1,589,648	$	1,911,352
Heavy oil		981,970			—		981,970			1,050,743			—		1,050,743
NGL		21,371			120,333		141,704			17,579			127,963		145,542
Total oil sales		1,285,873			1,407,584		2,693,457			1,390,026			1,717,611		3,107,637
Natural gas sales		17,219			102,681		119,900			17,314			66,987		84,301
Total petroleum and natural gas sales		1,303,092			1,510,265		2,813,357			1,407,340			1,784,598		3,191,938
Blending and other expense		(184,951	)		—		(184,951	)		(183,795	)		—		(183,795	)
Total sales, net of blending and other expense ⁽¹⁾	$	1,118,141		$	1,510,265	$	2,628,406		$	1,223,545		$	1,784,598	$	3,008,143

(1)

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

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

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

Baytex Energy Corp. Third Quarter Report 2025

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 nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30
	2025									2024
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	53,645		$	127,585		$	181,230		$	71,351		$	152,449		$	223,800
Average royalty rate ⁽¹⁾⁽²⁾		13.8	%		26.1	%		20.6	%		16.6	%		25.7	%		21.9	%
Royalties per boe ⁽³⁾	$	8.55		$	16.76		$	13.05		$	11.99		$	18.45		$	15.75

	Nine Months Ended September 30
	2025									2024
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	160,701		$	405,856		$	566,557		$	200,809		$	472,602		$	673,411
Average royalty rate ⁽¹⁾⁽²⁾		14.4	%		26.9	%		21.6	%		16.4	%		26.5	%		22.4	%
Royalties per boe ⁽³⁾	$	9.07		$	17.95		$	14.04		$	11.54		$	19.25		$	16.05

(1)

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

(2)

(3)

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

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

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

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

18	Baytex Energy Corp. Third Quarter Report 2025

OPERATING EXPENSE

	Three Months Ended September 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	84,994	$	75,290	$	160,284	$	87,373	$	79,746	$	167,119
Operating expense per boe ⁽¹⁾	$	13.55	$	9.89	$	11.54	$	14.69	$	9.65	$	11.76

	Nine Months Ended September 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	248,609	$	220,398	$	469,007	$	257,191	$	251,068	$	508,259
Operating expense per boe ⁽¹⁾	$	14.02	$	9.75	$	11.63	$	14.79	$	10.22	$	12.12

(1)

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

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

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

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

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

TRANSPORTATION EXPENSE

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

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

	Three Months Ended September 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	23,060	$	12,235	$	35,295	$	24,837	$	12,046	$	36,883
Transportation expense per boe ⁽¹⁾	$	3.68	$	1.61	$	2.54	$	4.17	$	1.46	$	2.60

	Nine Months Ended September 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	62,383	$	36,331	$	98,714	$	62,616	$	37,416	$	100,032
Transportation expense per boe ⁽¹⁾	$	3.52	$	1.61	$	2.45	$	3.60	$	1.52	$	2.38

(1)

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

Baytex Energy Corp. Third Quarter Report 2025

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

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

BLENDING AND OTHER EXPENSE

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

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

FINANCIAL DERIVATIVES

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

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2025			2024			Change			2025			2024			Change
Realized financial derivatives gain (loss)
Crude oil	$	(9,203	)	$	(2,190	)	$	(7,013	)	$	(22,484	)	$	(6,091	)	$	(16,393	)
Natural gas		623			2,521			(1,898	)		1,836			9,653			(7,817	)
Total	$	(8,580	)	$	331		$	(8,911	)	$	(20,648	)	$	3,562		$	(24,210	)
Unrealized financial derivatives gain (loss)
Crude oil	$	(4,401	)	$	21,239		$	(25,640	)	$	(20,016	)	$	3,251		$	(23,267	)
Natural gas		7,942			1,357			6,585			4,669			(2,215	)		6,884
Total	$	3,541		$	22,596		$	(19,055	)	$	(15,347	)	$	1,036		$	(16,383	)
Total financial derivatives gain (loss)
Crude oil	$	(13,604	)	$	19,049		$	(32,653	)	$	(42,500	)	$	(2,840	)	$	(39,660	)
Natural gas		8,565			3,878			4,687			6,505			7,438			(933	)
Total	$	(5,039	)	$	22,927		$	(27,966	)	$	(35,995	)	$	4,598		$	(40,593	)

We recorded total financial derivatives losses of $5.0 million for Q3/2025 and $36.0 million for YTD 2025 compared to gains of $22.9 million for Q3/2024 and $4.6 million for YTD 2024. The realized financial derivatives loss of $20.6 million for YTD 2025 resulted from losses of $22.5 million on crude oil contracts and gains of $1.8 million on natural gas contracts. The unrealized financial derivatives loss of $15.3 million for YTD 2025 resulted from a $20.0 million loss on crude oil contracts and a $4.7 million gain on natural gas contracts. The fair value of our financial derivative contracts resulted in a net asset of $8.6 million at September 30, 2025 compared to a net asset of $23.9 million at December 31, 2024.

Refer to Note 17 of the consolidated financial statements for a complete listing of our outstanding contracts at October 30, 2025.

20	Baytex Energy Corp. Third Quarter Report 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 nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30
	2025									2024
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		68,185			82,765			150,950			64,668			89,800			154,468
Operating netback:
Total sales, net of blending and other expense ⁽¹⁾	$	61.88		$	64.32		$	63.22		$	72.37		$	71.68		$	71.97
Less:
Royalties ⁽²⁾		(8.55	)		(16.76	)		(13.05	)		(11.99	)		(18.45	)		(15.75	)
Operating expense ⁽²⁾		(13.55	)		(9.89	)		(11.54	)		(14.69	)		(9.65	)		(11.76	)
Transportation expense ⁽²⁾		(3.68	)		(1.61	)		(2.54	)		(4.17	)		(1.46	)		(2.60	)
Operating netback ⁽¹⁾	$	36.10		$	36.06		$	36.09		$	41.52		$	42.12		$	41.86
Realized financial derivatives (loss) gain ⁽³⁾		—			—			(0.62	)		—			—			0.02
Operating netback after financial derivatives ⁽¹⁾	$	36.10		$	36.06		$	35.47		$	41.52		$	42.12		$	41.88

	Nine Months Ended September 30
	2025									2024
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		64,932			82,839			147,771			63,483			89,616			153,099
Operating netback:
Total sales, net of blending and other expense ⁽¹⁾	$	63.08		$	66.78		$	65.15		$	70.34		$	72.68		$	71.71
Less:
Royalties ⁽²⁾		(9.07	)		(17.95	)		(14.04	)		(11.54	)		(19.25	)		(16.05	)
Operating expense ⁽²⁾		(14.02	)		(9.75	)		(11.63	)		(14.79	)		(10.22	)		(12.12	)
Transportation expense ⁽²⁾		(3.52	)		(1.61	)		(2.45	)		(3.60	)		(1.52	)		(2.38	)
Operating netback ⁽¹⁾	$	36.47		$	37.47		$	37.03		$	40.41		$	41.69		$	41.16
Realized financial derivatives (loss) gain ⁽³⁾		—			—			(0.51	)		—			—			0.08
Operating netback after financial derivatives ⁽¹⁾	$	36.47		$	37.47		$	36.52		$	40.41		$	41.69		$	41.24

(1)

(2)

Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description of the composition these measures.

(3)

Calculated as realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.

Our operating netback of $36.09/boe for Q3/2025 and $37.03/boe for YTD 2025 was lower than $41.86/boe for Q3/2024 and $41.16/boe for YTD 2024 due to the decrease in our realized price which resulted in lower per unit sales net of royalties. Total operating and transportation expense for Q3/2025 and YTD 2025 was consistent with the same periods of 2024. Our operating netback net of realized gains and losses on financial derivatives of $35.47/boe for Q3/2025 and $36.52/boe for YTD 2025 was lower than $41.88/boe for Q3/2024 and $41.24/boe for YTD 2024 due to the decrease in realized prices.

GENERAL AND ADMINISTRATIVE EXPENSE

General and administrative (“G&A”) expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.

Baytex Energy Corp. Third Quarter Report 2025

The following table summarizes our G&A expense for the three and nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for per boe)	2025			2024			Change			2025			2024			Change
Gross general and administrative expense	$	27,445		$	24,255		$	3,190		$	88,967		$	80,082		$	8,885
Overhead recoveries		(6,709	)		(6,360	)		(349	)		(20,405	)		(18,769	)		(1,636	)
General and administrative expense	$	20,736		$	17,895		$	2,841		$	68,562		$	61,313		$	7,249
General and administrative expense per boe ⁽¹⁾	$	1.49		$	1.26		$	0.23		$	1.70		$	1.46		$	0.24

(1)

General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period.

G&A expense was $20.7 million ($1.49/boe) for Q3/2025 and $68.6 million ($1.70/boe) for YTD 2025 compared to $17.9 million ($1.26/boe) for Q3/2024 and $61.3 million ($1.46/boe) for YTD 2024. G&A expense of $68.6 million ($1.70/boe) for YTD 2025 is consistent with expectations and our 2025 annual guidance of approximately $95.0 million ($1.76/boe) which reflects the timing of certain costs and our expectations for production over the remainder of 2025.

FINANCING AND INTEREST EXPENSE

Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.

The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for per boe)	2025		2024		Change			2025			2024		Change
Interest on credit facilities	$	6,832	$	12,343	$	(5,511	)	$	19,870		$	46,271	$	(26,401	)
Interest on long-term notes		36,718		37,426		(708	)		114,680			109,760		4,920
Interest on lease obligations		323		340		(17	)		985			1,304		(319	)
Cash interest	$	43,873	$	50,109	$	(6,236	)	$	135,535		$	157,335	$	(21,800	)
Accretion of debt issue costs		2,564		3,067		(503	)		9,300			13,989		(4,689	)
Accretion of asset retirement obligations		5,999		5,524		475			17,315			15,910		1,405
Gain on repurchase and cancellation of long-term notes		—		—		—			(2,755	)		—		(2,755	)
Early redemption expense		—		—		—			—			24,350		(24,350	)
Financing and interest expense	$	52,436	$	58,700	$	(6,264	)	$	159,395		$	211,584	$	(52,189	)
Cash interest per boe ⁽¹⁾	$	3.16	$	3.53	$	(0.37	)	$	3.36		$	3.75	$	(0.39	)
Financing and interest expense per boe ⁽¹⁾	$	3.78	$	4.13	$	(0.35	)	$	3.95		$	5.04	$	(1.09	)

(1)

Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period.

Financing and interest expense was $52.4 million ($3.78/boe) for Q3/2025 and $159.4 million ($3.95/boe) for YTD 2025 compared to $58.7 million ($4.13/boe) for Q3/2024 and $211.6 million ($5.04/boe) for YTD 2024. The decrease for both periods of 2025 is due to lower outstanding debt balances for YTD 2025 and early redemption expense recognized in Q2/2024 related to the redemption of the 8.75% senior notes.

Cash interest of $43.9 million ($3.16/boe) for Q3/2025 and $135.5 million ($3.36/boe) for YTD 2025 was lower than $50.1 million ($3.53/boe) for Q3/2024 and $157.3 million ($3.75/boe) for YTD 2024. Lower interest on our credit facilities reflects lower debt balances outstanding in both periods of 2025 and lower rates, while higher interest on long-term notes is a result of additional principal amounts outstanding after the issuance of the 7.375% Senior Notes in Q2/2024. The weighted average interest rate applicable on our credit facilities was 6.7% for Q3/2025 and 6.7% for YTD 2025 compared to 7.5% for Q3/2024 and 7.8% for YTD 2024.

22	Baytex Energy Corp. Third Quarter Report 2025

Accretion of asset retirement obligations of $6.0 million for Q3/2025 and $17.3 million for YTD 2025 was consistent with $5.5 million for Q3/2024 and $15.9 million for YTD 2024. Accretion of debt issue costs of $2.6 million for Q3/2025 and $9.3 million for YTD 2025 was lower than $3.1 million for Q3/2024 and $14.0 million for YTD 2024. In Q2/2024, we recorded $24.4 million of early redemption expense related to the redemption of the 8.75% senior notes.

Cash interest expense of $135.5 million ($3.36/boe) for YTD 2025 is consistent with our expectations and our 2025 annual guidance of $180 million ($3.33/boe).

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation (“E&E”) expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company’s exploration programs. Exploration and evaluation expense was $0.1 million for Q3/2025 and $0.7 million for YTD 2025 compared to $0.1 million for Q3/2024 and $0.7 million for YTD 2024.

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company’s oil and gas properties, the amount of proved and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for per boe)	2025		2024		Change			2025		2024		Change
Depletion	$	326,707	$	352,745	$	(26,038	)	$	960,737	$	1,043,898	$	(83,161	)
Depreciation		2,386		3,639		(1,253	)		10,438		9,724		714
Depletion and depreciation	$	329,093	$	356,384	$	(27,291	)	$	971,175	$	1,053,622	$	(82,447	)
Depletion and depreciation per boe ⁽¹⁾	$	23.70	$	25.08	$	(1.38	)	$	24.07	$	25.12	$	(1.05	)

(1)

Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production volume for the applicable period.

Depletion and depreciation expense was $329.1 million ($23.70/boe) for Q3/2025 and $971.2 million ($24.07/boe) for YTD 2025 compared to $356.4 million ($25.08/boe) for Q3/2024 and $1.1 billion ($25.12/boe) for YTD 2024. Total depletion and depreciation expense and depletion and depreciation per boe were lower in Q3/2025 and YTD 2025 relative to Q3/2024 and YTD 2024. This was due to lower production and a decrease in future development costs for proved plus probable reserves which resulted in a lower depletable base for our oil and gas properties during 2025.

IMPAIRMENT

We assessed our oil and gas properties and exploration and evaluation assets for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of our cash generating units at September 30, 2025 and December 31, 2024.

SHARE-BASED COMPENSATION EXPENSE

Share-based compensation (“SBC”) expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with cash-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding share-based compensation liability. SBC expense varies with the quantity of share awards outstanding and changes in the market price of our common shares.

We recorded SBC expense of $10.7 million for Q3/2025 and $13.1 million for YTD 2025 compared to $2.3 million for Q3/2024 and $17.4 million for YTD 2024. SBC expense for Q3/2025 reflects an increase in the Company’s share price which resulted in higher SBC expense relative to Q3/2024, while the decrease in SBC expense for YTD 2025 reflects a decrease in the Company’s share price compared to YTD 2024.

FOREIGN EXCHANGE

Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities in our Canadian functional currency entities. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.

Baytex Energy Corp. Third Quarter Report 2025

	Three Months Ended September 30							Nine Months Ended September 30
($ thousands except for exchange rates)	2025		2024			Change		2025			2024		Change
Unrealized foreign exchange loss (gain)	$	36,840	$	(24,401	)	$	61,241	$	(67,427	)	$	33,506	$	(100,933	)
Realized foreign exchange loss (gain)		81		(151	)		232		(116	)		1,934		(2,050	)
Foreign exchange loss (gain)	$	36,921	$	(24,552	)	$	61,473	$	(67,543	)	$	35,440	$	(102,983	)
CAD/USD exchange rates:
At beginning of period		1.3622		1.3687					1.4405			1.3205
At end of period		1.3906		1.3505					1.3906			1.3505

We recorded a foreign exchange loss of $36.9 million for Q3/2025 and a gain of $67.5 million for YTD 2025 compared to a gain of $24.6 million for Q3/2024 and a loss of $35.4 million for YTD 2024.

The unrealized foreign exchange loss of $36.8 million for Q3/2025 and gain of $67.4 million for YTD 2025 is related to changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2025 compared to June 30, 2025 and December 31, 2024. The unrealized foreign exchange gain of $24.4 million for Q3/2024 and loss of $33.5 million for YTD 2024 is related to changes in the reported amount of our long-term notes and credit facilities due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2024 compared to June 30, 2024 and December 31, 2023.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian functional currency entities. We recorded a realized foreign exchange loss of $0.1 million for Q3/2025 and a gain of $0.1 million for YTD 2025 compared to a gain of $0.2 million for Q3/2024 and a loss of $1.9 million for YTD 2024.

INCOME TAXES

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2025			2024			Change			2025		2024		Change
Current income tax (recovery) expense	$	(5,733	)	$	(3,748	)	$	(1,985	)	$	966	$	4,407	$	(3,441	)
Deferred income tax expense		20,773			33,577			(12,804	)		57,295		72,188		(14,893	)
Total income tax expense	$	15,040		$	29,829		$	(14,789	)	$	58,261	$	76,595	$	(18,334	)

We recorded a current income tax recovery of $5.7 million for Q3/2025 and expense of $1.0 million for YTD 2025 compared to a recovery of $3.7 million for Q3/2024 and expense of $4.4 million for YTD 2024. The current income tax expense for YTD 2025 and 2024 primarily relates to repatriation and related taxes and the recoveries recorded in Q3/2025 and Q3/2024 represent recoveries of taxes previously accrued for the 2024 and 2023 tax years, respectively.

We recorded deferred income tax expense of $20.8 million for Q3/2025 and $57.3 million for YTD 2025 compared to $33.6 million for Q3/2024 and $72.2 million for YTD 2024. The deferred tax expense for Q3/2025 and YTD 2025 decreased compared to Q3/2024 and YTD 2024 as a result of lower earnings, partially offset by the removal of the valuation allowance against tax pools associated with our Canadian operations in 2024, with no such movement in 2025.

On July 4, 2025, the U.S. enacted a budget reconciliation package known as the One Big Beautiful Bill Act of 2025 (“OBBBA”) which included both tax and non-tax provisions. The changes resulting from the tax provisions in OBBBA did not have a material impact on the Company’s financial results.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (“CRA”) that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court of Canada (“TCC”) and we estimate it could take another two to three years to receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be unsuccessful at the TCC, additional appeals are available; a process that we estimate could take another two years and potentially longer.

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

24	Baytex Energy Corp. Third Quarter Report 2025

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the “Losses”). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. In September 2025, the Department of Justice, legal counsel for the Crown, abandoned the position that the trusts were resettled. The issue of whether the general anti-avoidance rule applies remains in dispute. If, after exhausting available appeals, the deduction of the Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income for the three and nine months ended September 30, 2025 and 2024 are set forth in the following table.

	Three Months Ended September 30									Nine Months Ended September 30
($ thousands)	2025			2024			Change			2025			2024			Change
Petroleum and natural gas sales	$	927,648		$	1,074,623		$	(146,975	)	$	2,813,357		$	3,191,938		$	(378,581	)
Royalties		(181,230	)		(223,800	)		42,570			(566,557	)		(673,411	)		106,854
Revenue, net of royalties		746,418			850,823			(104,405	)		2,246,800			2,518,527			(271,727	)

Expenses
Operating		(160,284	)		(167,119	)		6,835			(469,007	)		(508,259	)		39,252
Transportation		(35,295	)		(36,883	)		1,588			(98,714	)		(100,032	)		1,318
Blending and other		(49,750	)		(51,902	)		2,152			(184,951	)		(183,795	)		(1,156	)
Operating netback ⁽¹⁾	$	501,089		$	594,919		$	(93,830	)	$	1,494,128		$	1,726,441		$	(232,313	)
General and administrative		(20,736	)		(17,895	)		(2,841	)		(68,562	)		(61,313	)		(7,249	)
Cash interest		(43,873	)		(50,109	)		6,236			(135,535	)		(157,335	)		21,800
Realized financial derivatives (loss) gain		(8,580	)		331			(8,911	)		(20,648	)		3,562			(24,210	)
Realized foreign exchange (loss) gain		(81	)		151			(232	)		116			(1,934	)		2,050
Cash other (expense) income		(583	)		9,107			(9,690	)		(2,457	)		7,011			(9,468	)
Current income tax recovery (expense)		5,733			3,748			1,985			(966	)		(4,407	)		3,441
Cash share-based compensation		(10,737	)		(2,305	)		(8,432	)		(13,055	)		(17,393	)		4,338
Adjusted funds flow ⁽²⁾	$	422,232		$	537,947		$	(115,715	)	$	1,253,021		$	1,494,632		$	(241,611	)
Transaction costs		—			—			—			—			(1,539	)		1,539
Exploration and evaluation		(127	)		(82	)		(45	)		(691	)		(749	)		58
Depletion and depreciation		(329,093	)		(356,384	)		27,291			(971,175	)		(1,053,622	)		82,447
Non-cash financing and interest		(8,563	)		(8,591	)		28			(23,860	)		(54,249	)		30,389
Unrealized financial derivatives gain (loss)		3,541			22,596			(19,055	)		(15,347	)		1,036			(16,383	)
Unrealized foreign exchange (loss) gain		(36,840	)		24,401			(61,241	)		67,427			(33,506	)		100,933
Gain (loss) on dispositions		1,591			(1,091	)		2,682			1,028			(4,741	)		5,769
Deferred income tax expense		(20,773	)		(33,577	)		12,804			(57,295	)		(72,188	)		14,893
Net income	$	31,968		$	185,219		$	(153,251	)	$	253,108		$	275,074		$	(21,966	)

(1)

(2)

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

We generated adjusted funds flow of $422.2 million for Q3/2025 and $1.3 billion for YTD 2025 compared to $537.9 million for Q3/2024 and $1.5 billion for YTD 2024. The decrease in adjusted funds flow was primarily due to the decrease in realized pricing and production that resulted in lower revenues net of royalties partially offset by lower operating and transportation expense.

Baytex Energy Corp. Third Quarter Report 2025

We reported net income of $32.0 million for Q3/2025 and $253.1 million for YTD 2025 compared to net income of $185.2 million for Q3/2024 and $275.1 million for YTD 2024. The decrease in net income for Q3/2025 and YTD 2025 is the result of an unrealized foreign exchange loss and lower unrealized financial derivatives gains, partially offset by lower depletion expense and lower deferred income tax expense.

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation gain of $90.5 million for Q3/2025 and loss of $165.3 million for YTD 2025 relates to the change in value of our U.S. net assets and is due to changes in the Canadian dollar relative to the U.S. dollar at September 30, 2025 compared to June 30, 2025 and December 31, 2024. The CAD/USD exchange rate was 1.3906 CAD/USD as at September 30, 2025 compared to 1.3622 CAD/USD at June 30, 2025 and 1.4405 CAD/USD at December 31, 2024.

CAPITAL EXPENDITURES

Capital expenditures for the three and nine months ended September 30, 2025 and 2024 are summarized as follows.

	Three Months Ended September 30
	2025								2024
($ thousands)	Canada			U.S.		Total			Canada		U.S.			Total
Drilling, completion and equipping	$	109,383		$	141,772	$	251,155		$	104,787	$	175,544		$	280,331
Facilities and other		14,196			5,013		19,209			15,686		10,315			26,001
Exploration and development expenditures	$	123,579		$	146,785	$	270,364		$	120,473	$	185,859		$	306,332
Property acquisitions	$	23,560		$	464	$	24,024		$	507	$	535		$	1,042
Proceeds from dispositions	$	(8,254	)	$	—	$	(8,254	)	$	236	$	(1,672	)	$	(1,436	)

	Nine Months Ended September 30
	2025								2024
($ thousands)	Canada			U.S.		Total			Canada		U.S.			Total
Drilling, completion and equipping	$	398,810		$	535,571	$	934,381		$	311,143	$	604,144		$	915,287
Facilities and other		56,822			40,790		97,612			69,372		73,797			143,169
Exploration and development expenditures	$	455,632		$	576,361	$	1,031,993		$	380,515	$	677,941		$	1,058,456
Property acquisitions	$	24,934		$	1,540	$	26,474		$	36,584	$	3,210		$	39,794
Proceeds from dispositions	$	(11,794	)	$	549	$	(11,245	)	$	368	$	(4,524	)	$	(4,156	)

Exploration and development expenditures were $270.4 million for Q3/2025 and $1.0 billion for YTD 2025 compared to $306.3 million for Q3/2024 and $1.1 billion for YTD 2024. Exploration and development expenditures in Q3/2025 and YTD 2025 reflect our active heavy and light oil development program in Canada along with lower non-operated Eagle Ford development in the U.S.

In Canada, exploration and development expenditures were $123.6 million in Q3/2025 and $455.6 million for YTD 2025 compared to $120.5 million in Q3/2024 and $380.5 million for YTD 2024. Drilling and completion spending of $109.4 million in Q3/2025 and $398.8 million for YTD 2025 was higher than the comparative periods of 2024 which reflects increased development activity on our light and heavy oil properties.

Total U.S. exploration and development expenditures were $146.8 million for Q3/2025 and $576.4 million for YTD 2025 compared to $185.9 million in Q3/2024 and $677.9 million for YTD 2024. The decrease in exploration and development expenditures for both periods of 2025 compared to the same periods of 2024 reflects lower development activity primarily on our non-operated Eagle Ford properties in addition to lower drilling and completion costs on our operated properties.

Exploration and development expenditures of $1.0 billion for YTD 2025 were consistent with expectations. We expect exploration and development expenditures for 2025 to be approximately $1.2 billion.

26	Baytex Energy Corp. Third Quarter Report 2025

CAPITAL RESOURCES AND LIQUIDITY

Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions and dispositions. We strive to actively manage our capital structure in response to changes in economic conditions. At September 30, 2025, our capital structure was comprised of shareholders’ capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.

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

Management of debt levels is a priority for Baytex in order to sustain operations and support our business strategy. Net debt⁽¹⁾ of $2.2 billion at September 30, 2025 was $172.8 million lower than $2.4 billion at December 31, 2024 which reflects our allocation of free cash flow to debt repayment. At current commodity prices we plan to allocate free cash flow to debt repayment after funding our quarterly dividend.

(1)

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

Credit Facilities

At September 30, 2025, we had $182.3 million of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (the “Credit Facilities”). The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex’s wholly-owned subsidiary, Baytex Energy USA, Inc.

On June 27, 2025, we extended the maturity of the Credit Facilities from May 9, 2028 to June 27, 2029. There were no changes to the loan balances or financial covenants as a result of the amendment.

There are no mandatory principal payments required prior to maturity which could be extended upon our request. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances under the Baytex Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, Canadian Overnight Repo Rate Average rates or secured overnight financing rates (“SOFR”), plus applicable margins. Advances under the Baytex Energy USA, Inc. Credit Facilities can be drawn in U.S. funds and bear interest at the bank’s prime lending rate or SOFR, plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.7% for Q3/2025 and 6.7% for YTD 2025 compared to 7.5% for Q3/2024 and 7.8% for YTD 2024. The interest rate on our Credit Facilities has decreased with lower government benchmark rates.

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

The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov.

Baytex Energy Corp. Third Quarter Report 2025

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at September 30, 2025.

Covenant Description	Position as at September 30, 2025		Covenant
Senior Secured Debt ⁽¹⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)		0.1:1.0		3.5:1.0
Interest Coverage ⁽³⁾ (Minimum Ratio)		10.5:1.0		3.5:1.0
Total Debt ⁽⁴⁾to Bank EBITDA ⁽²⁾ (Maximum Ratio)		1.1:1.0		4:0:1.0

(1)

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

(2)

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

(3)

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

(4)

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

Long-Term Notes

At September 30, 2025 we have two issuances of long-term notes outstanding with a total principal amount of $1.9 billion. The long-term notes do not contain any financial maintenance covenants.

On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing interest at a rate of 8.50% per annum semi-annually (the “8.50% Senior Notes”). The 8.50% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be redeemable at par from April 30, 2028 to maturity.

On April 1, 2024, we issued US$575 million aggregate principal amount of senior unsecured notes due March 15, 2032 bearing interest at a rate of 7.375% per annum payable semi-annually (“7.375% Senior Notes”). The 7.375% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity.

During YTD 2025, Baytex repurchased and cancelled US$40.6 million principal of the 8.50% Senior Notes for US$38.8 million ($53.7 million) and recorded a gain of $2.8 million.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2025, we issued 0.1 million common shares pursuant to our share-based compensation program. As at September 30, 2025, we had 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding. As at October 30, 2025, there were 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding.

Our shareholder returns framework includes common share repurchases and a quarterly dividend. During the nine months ended September 30, 2025, we repurchased 5.4 million common shares under our normal course issuer bid (“NCIB”) at an average price of $3.12 per share for total consideration of $16.8 million. In June 2025, we renewed our NCIB under which we are permitted to purchase for cancellation up to 66.2 million common shares over the 12-month period commencing July 2, 2025, which represents 10% of Baytex’s public float, as defined by the Toronto Stock Exchange, as at June 18, 2025. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase its common shares through the New York Stock Exchange and other U.S.-based trading systems.

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

28	Baytex Energy Corp. Third Quarter Report 2025

On January 2, April 1, July 2, and October 1, 2025 we paid a quarterly cash dividend of $0.0225 per share to shareholders of record. On October 30, 2025, the Company’s Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 2, 2026 to shareholders of record as at December 15, 2025. These dividends are designated as “eligible dividends” for Canadian income tax purposes. These dividends are considered “qualified dividends” for U.S income tax purposes.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2025 and the expected timing for funding these obligations are noted in the table below.

($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Credit facilities - principal	$	182,345	$	—	$	—	$	182,345	$	—
Long-term notes - principal		1,855,605		—		—		1,056,039		799,566
Interest on long-term notes ⁽¹⁾		792,385		148,731		297,463		260,082		86,109
Lease obligations - principal		35,531		12,901		13,797		8,833		—
Processing agreements		5,206		948		732		536		2,990
Transportation agreements		181,765		56,919		69,560		23,899		31,387
Total	$	3,052,837	$	219,499	$	381,552	$	1,531,734	$	920,052

(1)

Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

Baytex Energy Corp. Third Quarter Report 2025

QUARTERLY FINANCIAL INFORMATION

	2025									2024												2023
($ thousands, except per common share amounts)	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Petroleum and natural gas sales		927,648			886,579			999,130			1,017,017			1,074,623			1,133,123			984,192			1,065,515
Net income (loss)		31,968			151,549			69,591			(38,477	)		185,219			103,898			(14,043	)		(625,830	)
Per common share - basic		0.04			0.20			0.09			(0.05	)		0.23			0.13			(0.02	)		(0.75	)
Per common share - diluted		0.04			0.20			0.09			(0.05	)		0.23			0.13			(0.02	)		(0.75	)
Adjusted funds flow ⁽¹⁾		422,232			366,919			463,870			461,886			537,947			532,839			423,846			502,148
Per common share - basic		0.55			0.48			0.60			0.59			0.68			0.65			0.52			0.60
Per common share - diluted		0.55			0.48			0.60			0.59			0.67			0.65			0.52			0.60
Free cash flow ⁽²⁾		142,688			3,188			52,529			254,838			220,159			180,673			(88	)		290,785
Per common share - basic		0.19			—			0.07			0.33			0.28			0.22			—			0.35
Per common share - diluted		0.18			—			0.07			0.33			0.28			0.22			—			0.35
Cash flows from operating activities		472,676			354,312			431,317			468,865			550,042			505,584			383,773			474,452
Per common share - basic		0.62			0.46			0.56			0.60			0.69			0.62			0.47			0.57
Per common share - diluted		0.61			0.46			0.56			0.60			0.69			0.62			0.47			0.57
Dividends declared		17,326			17,304			17,334			17,598			17,732			18,161			18,494			18,381
Per common share		0.0225			0.0225			0.0225			0.0225			0.0225			0.0225			0.0225			0.0225
Exploration and development		270,364			356,532			405,097			198,177			306,332			339,573			412,551			199,214
Canada		123,579			147,734			184,319			108,971			120,473			101,916			158,126			75,137
U.S.		146,785			208,798			220,778			89,206			185,859			237,657			254,425			124,077
Property acquisitions		24,024			1,193			1,257			12,621			1,042			3,349			35,403			33,923
Proceeds from dispositions		(8,254	)		(725	)		(2,266	)		(42,339	)		(1,436	)		(2,695	)		(25	)		(159,745	)
Net debt ⁽¹⁾		2,244,358			2,293,940			2,390,250			2,417,172			2,493,269			2,639,014			2,639,841			2,534,287
Total assets		7,601,389			7,552,013			7,824,576			7,759,745			7,614,157			7,770,926			7,717,495			7,460,931
Common shares outstanding		768,317			768,317			770,039			773,590			787,328			804,977			821,322			821,681

Daily production
Total production (boe/d)		150,950			148,095			144,194			152,894			154,468			154,194			150,620			160,373
Canada (boe/d)		68,185			64,167			62,380			65,332			64,668			63,688			62,081			64,744
U.S. (boe/d)		82,765			83,928			81,814			87,562			89,800			90,506			88,540			95,629

Benchmark prices
WTI oil (US$/bbl)		64.93			63.74			71.42			70.27			75.10			80.57			76.96			78.32
WCS heavy oil ($/bbl)		75.14			74.10			84.33			80.77			83.98			91.72			77.73			76.86
Edmonton par oil ($/bbl)		86.20			84.15			95.27			94.98			97.91			105.30			92.16			99.72
CAD/USD avg exchange rate		1.3774			1.3840			1.4350			1.3992			1.3636			1.3684			1.3488			1.3619
AECO natural gas ($/mcf)		1.00			2.07			2.02			1.46			0.81			1.44			2.05			2.66
NYMEX natural gas (US$/mmbtu)		3.07			3.44			3.65			2.79			2.16			1.89			2.24			2.88

Total sales, net of blending and other expense ($/boe) ⁽²⁾		63.22			61.16			71.38			66.60			71.97			75.93			67.12			68.00
Royalties ($/boe) ⁽³⁾		(13.05	)		(13.16	)		(16.02	)		(14.69	)		(15.75	)		(17.14	)		(15.26	)		(15.49	)
Operating expense ($/boe) ⁽³⁾		(11.54	)		(11.95	)		(11.38	)		(10.36	)		(11.76	)		(11.95	)		(12.65	)		(11.17	)
Transportation expense ($/boe) ⁽³⁾		(2.54	)		(2.44	)		(2.35	)		(2.35	)		(2.60	)		(2.37	)		(2.18	)		(2.02	)
Operating netback ($/boe) ⁽²⁾		36.09			33.61			41.63			39.20			41.86			44.47			37.03			39.32
Financial derivatives (loss) gain ($/boe) ⁽³⁾		(0.62	)		(0.88	)		(0.01	)		(0.15	)		0.02			(0.16	)		0.40			0.84
Operating netback after financial derivatives ($/boe) ⁽²⁾		35.47			32.73			41.62			39.05			41.88			44.31			37.43			40.16

(1)

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

(2)

(3)

Calculated as royalties, operating expense, transportation expense or financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.

30	Baytex Energy Corp. Third Quarter Report 2025

Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have fluctuated.

Benchmark prices for crude oil have declined over the previous eight quarters due to increasing supply from OPEC+ and North American production growth along with concerns over slowing global economic activity. Our realized sales price of $75.93/boe for Q2/2024 was our strongest realized pricing in the most recent eight quarters and we reported a realized price of $63.22/boe for Q3/2025.

Increased activity on our Eagle Ford properties following the Ranger merger resulted in production of 160,373 boe/d in Q4/2023 and has moderated since then as oil prices have declined. We have completed several non-core dispositions in Canada and the pace of non-operated activity in the U.S. has moderated which has resulted in production of 150,950 boe/d in Q3/2025. Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow⁽¹⁾ of $422.2 million and cash flows from operating activities of $472.7 million for Q3/2025 reflect strong production results from our development plans in the U.S. and Canada.

Net debt can fluctuate on a quarterly basis depending on changes in our free cash flow, shareholder returns and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt⁽¹⁾ decreased to $2.2 billion at Q3/2025 from $2.5 billion at Q4/2023 which reflects free cash flow⁽²⁾ of $854.0 million generated in the period since Q4/2023, and $358.6 million allocated to shareholder returns in addition to a weaker Canadian dollar at Q3/2025, which increases the reported amount of our U.S. dollar denominated debt.

(1)

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

(2)

ENVIRONMENTAL REGULATIONS

As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2024 for a full description of the risks associated with these regulations and how they may impact our business in the future.

Reporting Regulations

Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future disclosure requirements. The International Sustainability Standards Board (“ISSB”) has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Sustainability Standards Board has released voluntary standards for reporting periods starting on or after January 1, 2025 that are aligned with the ISSB release and include suggestions for Canadian-specific modifications. The Canadian Securities Administrators (“CSA”) have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. In April 2025, the CSA announced it is pausing development of new sustainability reporting requirements to allow issuers to adapt to recent developments in the U.S. and globally. Baytex continues to monitor developments on these reporting requirements and has not yet quantified the cost to comply with these regulations.

OFF BALANCE SHEET TRANSACTIONS

We do not have any material financial arrangements that are excluded from the consolidated financial statements as at September 30, 2025, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the nine months ended September 30, 2025. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2024.

SPECIFIED FINANCIAL MEASURES

In this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of blending and other expense, heavy oil sales, net of blending and other expense, and average royalty rate) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This MD&A also contains the terms “adjusted funds flow” and “net debt” which are 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.

Baytex Energy Corp. Third Quarter Report 2025

Non-GAAP Financial Measures

Total sales, net of blending and other expense and heavy oil, net of blending and other expense

Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated as heavy oil sales less 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.

The following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements in the following table.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2025			2024			2025			2024
Petroleum and natural gas sales	$	927,648		$	1,074,623		$	2,813,357		$	3,191,938
Light oil and condensate ⁽¹⁾		(525,900	)		(647,587	)		(1,569,783	)		(1,911,352	)
NGL ⁽¹⁾		(41,404	)		(50,101	)		(141,704	)		(145,542	)
Natural gas ⁽¹⁾		(31,339	)		(26,076	)		(119,900	)		(84,301	)
Heavy oil	$	329,005		$	350,859		$	981,970		$	1,050,743
Blending and other expense ⁽²⁾		(49,750	)		(51,902	)		(184,951	)		(183,795	)
Heavy oil, net of blending and other expense	$	279,255		$	298,957		$	797,019		$	866,948

(1)

Component of petroleum and natural gas sales. See Note 13 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and nine months ended September 30, 2025 for further information.

(2)

The portion of blending and other expense that relates to heavy oil sales for the applicable period.

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. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to provide price certainty on a portion of our production.

The following table reconciles operating netback and operating netback after realized financial derivatives to petroleum and natural gas sales.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2025			2024			2025			2024
Petroleum and natural gas sales	$	927,648		$	1,074,623		$	2,813,357		$	3,191,938
Blending and other expense		(49,750	)		(51,902	)		(184,951	)		(183,795	)
Total sales, net of blending and other expense		877,898			1,022,721			2,628,406			3,008,143
Royalties		(181,230	)		(223,800	)		(566,557	)		(673,411	)
Operating expense		(160,284	)		(167,119	)		(469,007	)		(508,259	)
Transportation expense		(35,295	)		(36,883	)		(98,714	)		(100,032	)
Operating netback	$	501,089		$	594,919		$	1,494,128		$	1,726,441
Realized financial derivatives (loss) gain ⁽¹⁾		(8,580	)		331			(20,648	)		3,562
Operating netback after realized financial derivatives	$	492,509		$	595,250		$	1,473,480		$	1,730,003

(1)

Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2025 for further information.

32	Baytex Energy Corp. Third Quarter Report 2025

Free cash flow

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

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2025			2024			2025			2024
Cash flows from operating activities	$	472,676		$	550,042		$	1,258,305		$	1,439,399
Change in non-cash working capital		(55,961	)		(20,813	)		(17,885	)		31,350
Additions to exploration and evaluation assets		—			—			(930	)		—
Additions to oil and gas properties		(270,364	)		(306,332	)		(1,031,063	)		(1,058,456	)
Payments on lease obligations		(3,663	)		(2,738	)		(10,022	)		(13,088	)
Transaction costs		—			—			—			1,539
Free cash flow	$	142,688		$	220,159		$	198,405		$	400,744

Non-GAAP Financial Ratios

Heavy oil, net of blending and other expense per bbl

Heavy oil, net of blending and other expense per bbl represents the realized price for produced heavy oil volumes during a period. Heavy oil, net of blending and other expense is a non-GAAP measure that is divided by barrels of heavy oil production volume for the applicable period to calculate the ratio. We use heavy oil, net of blending and other expense per bbl to analyze our realized heavy oil price for produced volumes against the WCS benchmark price.

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.

Average royalty rate

Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties divided by total sales, net of blending and other expense (a non-GAAP financial measure). 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.

Operating netback per boe

Operating netback per boe is operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period and is used to assess our operating performance on a unit of production basis. Realized financial derivative gains and losses per boe are added to operating netback per boe to arrive at operating netback after financial derivatives per boe. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to provide price certainty on a portion of our production.

Capital Management Measures

Net debt

Baytex Energy Corp. Third Quarter Report 2025

The following table summarizes our calculation of net debt.

	As at
($ thousands)	September 30, 2025			December 31, 2024
Credit facilities	$	166,841		$	324,346
Unamortized debt issuance costs - Credit facilities ⁽¹⁾		15,504			16,861
Long-term notes		1,815,230			1,932,890
Unamortized debt issuance costs - Long-term notes ⁽¹⁾		40,375			47,729
Trade payables		554,057			512,473
Share-based compensation liability		24,666			24,732
Dividends payable		17,326			17,598
Other long-term liabilities		20,163			20,887
Cash		(10,417	)		(16,610	)
Trade receivables		(324,287	)		(387,266	)
Prepaids and other assets		(75,100	)		(76,468	)
Net debt	$	2,244,358		$	2,417,172

(1)

Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2025. These amounts represent the remaining balance of costs that were paid by Baytex at the inception of the contract.

Adjusted funds flow

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

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

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2025			2024			2025			2024
Cash flow from operating activities	$	472,676		$	550,042		$	1,258,305		$	1,439,399
Change in non-cash working capital		(55,961	)		(20,813	)		(17,885	)		31,350
Asset retirement obligations settled		5,517			8,718			12,601			22,344
Transaction costs		—			—			—			1,539
Adjusted funds flow	$	422,232		$	537,947		$	1,253,021		$	1,494,632

INTERNAL CONTROL OVER FINANCIAL REPORTING

We are required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. This instrument requires us to disclose in our interim MD&A any material weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such material weaknesses were identified in, or that changes were made to, internal controls over financial reporting during the three months ended September 30, 2025.

FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management’s assessment of the Company’s future plans and operations, certain statements in this document 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 “anticipate”, “believe”, “continue”, “could”, “estimate”, “expect”, “forecast”, “intend”, “may”, “objective”, “ongoing”, “outlook”, “potential”, “plan”, “project”, “should”, “target”, “would”, “will” or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to but not limited to: we expect net debt to decline over the remainder of 2025; our 2025 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; the expected time to resolve the reassessment of our tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions and dispositions; that we may issue or repurchase debt or equity securities from time to time; our intent to fund certain financial obligations with adjusted funds flow and the expected timing of those financial obligations. 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 the reserves can be profitably produced in the future. 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 the reserves can be profitably produced in the future.

34	Baytex Energy Corp. Third Quarter Report 2025

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; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; 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; 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; 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; 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. 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.

There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback 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.

Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. 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 and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’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 and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend is subject to the discretion of the Board of Directors of Baytex.

Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Financial Position

(thousands of Canadian dollars) (unaudited)

		As at
	Notes	September 30, 2025			December 31, 2024
ASSETS
Current assets
Cash	17	$	10,417		$	16,610
Trade receivables	13, 17		324,287			387,266
Prepaids and other assets			24,903			20,178
Financial derivatives	17		15,896			25,573
			375,503			449,627
Non-current assets
Exploration and evaluation assets	4		140,606			124,355
Oil and gas properties	5		6,820,579			6,921,168
Other plant and equipment			9,180			8,025
Infrastructure under construction	6		35,655			—
Lease assets			28,573			22,068
Prepaids and other assets	14		50,197			56,290
Deferred income tax asset	14		141,096			178,212
		$	7,601,389		$	7,759,745

LIABILITIES
Current liabilities
Trade payables	17	$	554,057		$	512,473
Financial derivatives	17		4,732			—
Share-based compensation liability	11		18,561			18,806
Dividends payable	10, 17		17,326			17,598
Liabilities related to infrastructure under construction	6		20,227			—
Lease obligations			11,082			9,193
Asset retirement obligations	9		16,076			15,656
			642,061			573,726
Non-current liabilities
Other long-term liabilities			20,163			20,887
Share-based compensation liability	11		6,105			5,926
Financial derivatives	17		2,583			1,645
Credit facilities	7		166,841			324,346
Long-term notes	8		1,815,230			1,932,890
Lease obligations			20,139			15,459
Asset retirement obligations	9		626,436			625,295
Deferred income tax liability	14		111,804			88,561
			3,411,362			3,588,735

SHAREHOLDERS’ EQUITY
Shareholders’ capital	10		6,094,686			6,137,479
Contributed surplus			387,818			361,854
Accumulated other comprehensive income			927,918			1,093,261
Deficit			(3,220,395	)		(3,421,584	)
			4,190,027			4,171,010
		$	7,601,389		$	7,759,745

Subsequent events (notes 10 and 17)

See accompanying notes to the condensed consolidated interim financial statements.

36	Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Income and Comprehensive Income

(thousands of Canadian dollars, except per common share amounts and weighted average common shares) (unaudited)

		Three Months Ended September 30						Nine Months Ended September 30
	Notes	2025			2024			2025			2024
Revenue, net of royalties
Petroleum and natural gas sales	13	$	927,648		$	1,074,623		$	2,813,357		$	3,191,938
Royalties			(181,230	)		(223,800	)		(566,557	)		(673,411	)
			746,418			850,823			2,246,800			2,518,527

Expenses
Operating			160,284			167,119			469,007			508,259
Transportation			35,295			36,883			98,714			100,032
Blending and other			49,750			51,902			184,951			183,795
General and administrative			20,736			17,895			68,562			61,313
Transaction costs			—			—			—			1,539
Exploration and evaluation	4		127			82			691			749
Depletion and depreciation			329,093			356,384			971,175			1,053,622
Share-based compensation	11		10,737			2,305			13,055			17,393
Financing and interest	15		52,436			58,700			159,395			211,584
Financial derivatives loss (gain)	17		5,039			(22,927	)		35,995			(4,598	)
Foreign exchange loss (gain)	16		36,921			(24,552	)		(67,543	)		35,440
(Gain) loss on dispositions			(1,591	)		1,091			(1,028	)		4,741
Other expense (income)			583			(9,107	)		2,457			(7,011	)
			699,410			635,775			1,935,431			2,166,858
Net income before income taxes			47,008			215,048			311,369			351,669
Income tax expense	14
Current income tax (recovery) expense			(5,733	)		(3,748	)		966			4,407
Deferred income tax expense			20,773			33,577			57,295			72,188
			15,040			29,829			58,261			76,595
Net income		$	31,968		$	185,219		$	253,108		$	275,074
Other comprehensive income (loss)
Foreign currency translation adjustment			90,523			(61,640	)		(165,343	)		100,942
Comprehensive income		$	122,491		$	123,579		$	87,765		$	376,016

Net income per common share	12
Basic		$	0.04		$	0.23		$	0.33		$	0.34
Diluted		$	0.04		$	0.23		$	0.33		$	0.34

Weighted average common shares (000’s)	12
Basic			768,317			796,064			769,481			810,589
Diluted			773,165			800,217			773,680			814,351

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Changes in Equity

(thousands of Canadian dollars) (unaudited)

	Notes	Shareholders’ capital			Contributed surplus		Accumulated other comprehensive income			Deficit			Total equity
Balance at December 31, 2023		$	6,527,289		$	193,077	$	690,917		$	(3,586,196	)	$	3,825,087
Vesting of share awards			1,167			—		—			—			1,167
Repurchase of common shares for cancellation			(280,172	)		111,704		—			—			(168,468	)
Dividends declared			—			—		—			(54,387	)		(54,387	)
Comprehensive income			—			—		100,942			275,074			376,016
Balance at September 30, 2024		$	6,248,284		$	304,781	$	791,859		$	(3,365,509	)	$	3,979,415

Balance at December 31, 2024		$	6,137,479		$	361,854	$	1,093,261		$	(3,421,584	)	$	4,171,010
Vesting of share awards	10		330			—		—			—			330
Repurchase of common shares for cancellation	10		(43,123	)		25,964		—			—			(17,159	)
Dividends declared	10		—			—		—			(51,919	)		(51,919	)
Comprehensive (loss) income			—			—		(165,343	)		253,108			87,765
Balance at September 30, 2025		$	6,094,686		$	387,818	$	927,918		$	(3,220,395	)	$	4,190,027

See accompanying notes to the condensed consolidated interim financial statements.

38	Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Cash Flows

(thousands of Canadian dollars) (unaudited)

		Three Months Ended September 30						Nine Months Ended September 30
	Notes	2025			2024			2025			2024
CASH PROVIDED BY (USED IN):
Operating activities
Net income		$	31,968		$	185,219		$	253,108		$	275,074
Adjustments for:
Unrealized foreign exchange loss (gain)	16		36,840			(24,401	)		(67,427	)		33,506
Exploration and evaluation	4		127			82			691			749
Depletion and depreciation			329,093			356,384			971,175			1,053,622
Non-cash financing and interest	15		8,563			8,591			23,860			54,249
Unrealized financial derivatives (gain) loss	17		(3,541	)		(22,596	)		15,347			(1,036	)
(Gain) loss on dispositions			(1,591	)		1,091			(1,028	)		4,741
Deferred income tax expense	14		20,773			33,577			57,295			72,188
Asset retirement obligations settled	9		(5,517	)		(8,718	)		(12,601	)		(22,344	)
Change in non-cash working capital			55,961			20,813			17,885			(31,350	)
Cash flows from operating activities			472,676			550,042			1,258,305			1,439,399

Financing activities
Decrease in credit facilities			(155,729	)		(157,104	)		(153,582	)		(404,620	)
Deferred finance costs			—			—			(2,714	)		(25,023	)
Payments on lease obligations			(3,663	)		(2,738	)		(10,022	)		(13,088	)
Net proceeds from issuance of long-term notes	8		—			—			—			780,936
Redemption of long-term notes	8		—			—			(53,681	)		(580,913	)
Repurchase of common shares	10		—			(84,573	)		(17,159	)		(168,468	)
Dividends declared	10		(17,326	)		(17,732	)		(51,919	)		(54,387	)
Change in non-cash working capital			—			6,570			(2,803	)		4,470
Cash flows used in financing activities			(176,718	)		(255,577	)		(291,880	)		(461,093	)

Investing activities
Additions to exploration and evaluation assets	4		—			—			(930	)		—
Additions to oil and gas properties	5		(270,364	)		(306,332	)		(1,031,063	)		(1,058,456	)
Additions to other plant and equipment			(611	)		(744	)		(1,405	)		(4,280	)
Additions to infrastructure under construction	6		(35,655	)		—			(35,655	)		—
Advances received for infrastructure under construction	6		7,925			—			7,925			—
Property acquisitions			(24,024	)		(1,042	)		(26,474	)		(39,794	)
Proceeds from dispositions			8,254			1,436			11,245			4,156
Change in non-cash working capital			21,778			(2,359	)		103,739			85,564
Cash flows used in investing activities			(292,697	)		(309,041	)		(972,618	)		(1,012,810	)

Change in cash			3,261			(14,576	)		(6,193	)		(34,504	)
Cash, beginning of period			7,156			35,887			16,610			55,815
Cash, end of period		$	10,417		$	21,311		$	10,417		$	21,311

Supplementary information
Interest paid		$	36,088		$	38,581		$	126,720		$	143,597
Income taxes paid		$	2,453		$	1,730		$	22,094		$	18,151

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Third Quarter Report 2025

Baytex Energy Corp.

Notes to the Condensed Consolidated Interim Financial Statements

For the periods ended September 30, 2025 and 2024

(all tabular amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)

REPORTING ENTITY

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

BASIS OF PREPARATION

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

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

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

The audited 2024 annual consolidated financial statements of the Company are available through its filings on SEDAR+ at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov.

Estimation Uncertainty

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

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

Environmental Reporting Regulations

Material Accounting Policies

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

40	Baytex Energy Corp. Third Quarter Report 2025

Future Accounting Pronouncements

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

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

SEGMENTED FINANCIAL INFORMATION

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

•

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

•

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

•

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

	Canada						U.S.						Corporate						Consolidated
Three Months Ended September 30	2025			2024			2025			2024			2025			2024			2025			2024
Revenue, net of royalties
Petroleum and natural gas sales	$	437,905		$	482,467		$	489,743		$	592,156		$	—		$	—		$	927,648		$	1,074,623
Royalties		(53,645	)		(71,351	)		(127,585	)		(152,449	)		—			—			(181,230	)		(223,800	)
		384,260			411,116			362,158			439,707			—			—			746,418			850,823

Expenses
Operating		84,994			87,373			75,290			79,746			—			—			160,284			167,119
Transportation		23,060			24,837			12,235			12,046			—			—			35,295			36,883
Blending and other		49,750			51,902			—			—			—			—			49,750			51,902
General and administrative		—			—			—			—			20,736			17,895			20,736			17,895
Exploration and evaluation		127			82			—			—			—			—			127			82
Depletion and depreciation		123,444			123,742			203,263			229,003			2,386			3,639			329,093			356,384
Share-based compensation		—			—			—			—			10,737			2,305			10,737			2,305
Financing and interest		—			—			—			—			52,436			58,700			52,436			58,700
Financial derivatives loss (gain)		—			—			—			—			5,039			(22,927	)		5,039			(22,927	)
Foreign exchange loss (gain)		—			—			—			—			36,921			(24,552	)		36,921			(24,552	)
(Gain) loss on dispositions		(1,591	)		—			—			1,091			—			—			(1,591	)		1,091
Other expense (income)		—			—			—			—			583			(9,107	)		583			(9,107	)
		279,784			287,936			290,788			321,886			128,838			25,953			699,410			635,775
Net income (loss) before income taxes		104,476			123,180			71,370			117,821			(128,838	)		(25,953	)		47,008			215,048
Income tax (recovery) expense
Current income tax recovery																				(5,733	)		(3,748	)
Deferred income tax expense																				20,773			33,577
																				15,040			29,829
Net income																			$	31,968		$	185,219

Additions to oil and gas properties		123,579			120,473			146,785			185,859			—			—			270,364			306,332
Property acquisitions		23,560			507			464			535			—			—			24,024			1,042
Proceeds from dispositions		(8,254	)		236			—			(1,672	)		—			—			(8,254	)		(1,436	)

Baytex Energy Corp. Third Quarter Report 2025

	Canada						U.S.						Corporate						Consolidated
Nine Months Ended September 30	2025			2024			2025			2024			2025			2024			2025			2024
Revenue, net of royalties
Petroleum and natural gas sales	$	1,303,092		$	1,407,340		$	1,510,265		$	1,784,598		$	—		$	—		$	2,813,357		$	3,191,938
Royalties		(160,701	)		(200,809	)		(405,856	)		(472,602	)		—			—			(566,557	)		(673,411	)
		1,142,391			1,206,531			1,104,409			1,311,996			—			—			2,246,800			2,518,527

Expenses
Operating		248,609			257,191			220,398			251,068			—			—			469,007			508,259
Transportation		62,383			62,616			36,331			37,416			—			—			98,714			100,032
Blending and other		184,951			183,795			—			—			—			—			184,951			183,795
General and administrative		—			—			—			—			68,562			61,313			68,562			61,313
Transaction costs		—			—			—			—			—			1,539			—			1,539
Exploration and evaluation		691			749			—			—			—			—			691			749
Depletion and depreciation		353,405			358,603			607,332			685,295			10,438			9,724			971,175			1,053,622
Share-based compensation		—			—			—			—			13,055			17,393			13,055			17,393
Financing and interest		—			—			—			—			159,395			211,584			159,395			211,584
Financial derivatives loss (gain)		—			—			—			—			35,995			(4,598	)		35,995			(4,598	)
Foreign exchange (gain) loss		—			—			—			—			(67,543	)		35,440			(67,543	)		35,440
(Gain) loss on dispositions		(1,028	)		(1,055	)		—			5,796			—			—			(1,028	)		4,741
Other expense (income)		—			—			—			—			2,457			(7,011	)		2,457			(7,011	)
		849,011			861,899			864,061			979,575			222,359			325,384			1,935,431			2,166,858
Net income (loss) before income taxes		293,380			344,632			240,348			332,421			(222,359	)		(325,384	)		311,369			351,669
Income tax expense
Current income tax expense																				966			4,407
Deferred income tax expense																				57,295			72,188
																				58,261			76,595
Net income																			$	253,108		$	275,074

Additions to exploration and evaluation assets		930			—			—			—			—			—			930			—
Additions to oil and gas properties		454,702			380,515			576,361			677,941			—			—			1,031,063			1,058,456
Property acquisitions		24,934			36,584			1,540			3,210			—			—			26,474			39,794
Proceeds from dispositions		(11,794	)		368			549			(4,524	)		—			—			(11,245	)		(4,156	)

	September 30, 2025		December 31, 2024
Canadian assets	$	2,468,239	$	2,381,991
U.S. assets		5,043,846		5,322,088
Corporate assets		89,304		55,666
Total consolidated assets	$	7,601,389	$	7,759,745

42	Baytex Energy Corp. Third Quarter Report 2025

EXPLORATION AND EVALUATION ASSETS

	September 30, 2025			December 31, 2024
Balance, beginning of period	$	124,355		$	90,919
Additions to exploration and evaluation assets		930			—
Property acquisitions		29,097			39,355
Divestitures		(9,822	)		(2,009	)
Exploration and evaluation expense		(691	)		(779	)
Transfer to oil and gas properties (note 5)		(3,263	)		(3,131	)
Balance, end of period	$	140,606		$	124,355

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

OIL AND GAS PROPERTIES

	Cost			Accumulated depletion			Net book value
Balance, December 31, 2023	$	15,526,017		$	(8,906,984	)	$	6,619,033
Additions to oil and gas properties		1,256,633			—			1,256,633
Property acquisitions		16,437			—			16,437
Transfers from exploration and evaluation assets (note 4)		3,131			—			3,131
Transfers from lease assets		8,210			—			8,210
Change in asset retirement obligations (note 9)		25,253			—			25,253
Divestitures		(187,103	)		135,742			(51,361	)
Foreign currency translation		794,766			(378,871	)		415,895
Depletion		—			(1,372,063	)		(1,372,063	)
Balance, December 31, 2024	$	17,443,344		$	(10,522,176	)	$	6,921,168
Additions to oil and gas properties		1,031,063			—			1,031,063
Property acquisitions		1,654			—			1,654
Transfers from exploration and evaluation assets (note 4)		3,263			—			3,263
Change in asset retirement obligations (note 9)		13,793			—			13,793
Divestitures		(68,153	)		49,870			(18,283	)
Foreign currency translation		(346,885	)		175,543			(171,342	)
Depletion		—			(960,737	)		(960,737	)
Balance, September 30, 2025	$	18,078,079		$	(11,257,500	)	$	6,820,579

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

INFRASTRUCTURE UNDER CONSTRUCTION

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

Baytex Energy Corp. Third Quarter Report 2025

CREDIT FACILITIES

	September 30, 2025			December 31, 2024
Credit facilities - U.S. dollar denominated ⁽¹⁾	$	138,067		$	206,826
Credit facilities - Canadian dollar denominated		44,278			134,381
Credit facilities - principal ⁽²⁾	$	182,345		$	341,207
Unamortized debt issuance costs		(15,504	)		(16,861	)
Credit facilities	$	166,841		$	324,346

(1)

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

(2)

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

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

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

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

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

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

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at September 30, 2025.

Covenant Description	Position as at September 30, 2025		Covenant
Senior Secured Debt ⁽¹⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)		0.1:1.0		3.5:1.0
Interest Coverage ⁽³⁾ (Minimum Ratio)		10.5:1.0		3.5:1.0
Total Debt ⁽⁴⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)		1.1:1.0		4:0:1.0

(1)

(2)

(3)

(4)

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

44	Baytex Energy Corp. Third Quarter Report 2025

LONG-TERM NOTES

	September 30, 2025			December 31, 2024
8.50% notes due April 30, 2030 ⁽¹⁾	$	1,056,039		$	1,152,360
7.375% notes due March 15, 2032 ⁽²⁾		799,566			828,259
Total long-term notes - principal ⁽³⁾	$	1,855,605		$	1,980,619
Unamortized debt issuance costs		(40,375	)		(47,729	)
Total long-term notes - net of unamortized debt issuance costs	$	1,815,230		$	1,932,890

(1)

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

(2)

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

(3)

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

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

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

ASSET RETIREMENT OBLIGATIONS

	September 30, 2025			December 31, 2024
Balance, beginning of period	$	640,951		$	623,399
Liabilities incurred ⁽¹⁾		14,339			32,635
Liabilities settled		(12,601	)		(28,793	)
Liabilities acquired from property acquisitions		—			814
Liabilities divested		(13,611	)		(9,482	)
Accretion (note 15)		17,315			21,226
Change in estimate ⁽¹⁾		8,085			10,113
Changes in discount and inflation rates ⁽¹⁾⁽²⁾		(8,631	)		(17,495	)
Foreign currency translation		(3,335	)		8,534
Balance, end of period	$	642,512		$	640,951
Less current portion of asset retirement obligations		16,076			15,656
Non-current portion of asset retirement obligations	$	626,436		$	625,295

(1)

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

(2)

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

Baytex Energy Corp. Third Quarter Report 2025

10.

SHAREHOLDERS’ CAPITAL

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

	Number of Common Shares (000s)			Amount
Balance, December 31, 2023		821,681		$	6,527,289
Vesting of share awards		272			1,167
Common shares repurchased and cancelled		(48,363	)		(390,977	)
Balance, December 31, 2024		773,590		$	6,137,479
Vesting of share awards		112			330
Common shares repurchased and cancelled		(5,385	)		(43,123	)
Balance, September 30, 2025		768,317		$	6,094,686

Normal Course Issuer Bid (“NCIB”) Share Repurchases

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

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

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

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

Dividends

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

Record Date	Payable Date	Per Share Amount		Dividend Amount
March 14, 2025	April 1, 2025	$	0.0225	$	17,289
June 13, 2025	July 2, 2025		0.0225		17,304
September 15, 2025	October 1, 2025		0.0225		17,326
Total dividends declared				$	51,919

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

11.

SHARE-BASED COMPENSATION PLAN

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

46	Baytex Energy Corp. Third Quarter Report 2025

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

Share Award Incentive Plan

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

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

Incentive Award Plan

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

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

Deferred Share Unit Plan (“DSU Plan”)

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

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

The number of awards outstanding is detailed below:

(000s)	Restricted awards			Performance awards			Incentive awards			DSU awards			Total
Total, December 31, 2023		2,279			3,355			4,483			1,245			11,362
Granted		13			2,416			3,671			335			6,435
Added by performance factor		—			524			—			—			524
Vested		(1,457	)		(2,449	)		(2,577	)		(162	)		(6,645	)
Forfeited		(9	)		(364	)		(302	)		—			(675	)
Total, December 31, 2024		826			3,482			5,275			1,418			11,001
Granted		5			3,868			5,693			414			9,980
Forfeited by performance factor		—			(243	)		—			—			(243	)
Vested		(804	)		(1,297	)		(2,235	)		—			(4,336	)
Forfeited		(4	)		(60	)		(468	)		—			(532	)
Total, September 30, 2025		23			5,750			8,265			1,832			15,870

12.

NET INCOME PER SHARE

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

Baytex Energy Corp. Third Quarter Report 2025

	Three Months Ended September 30
	2025						2024
	Net income		Weighted average common shares (000s)		Net income per share		Net income		Weighted average common shares (000s)		Net income per share
Net income - basic	$	31,968		768,317	$	0.04	$	185,219		796,064	$	0.23
Dilutive effect of share awards and DSUs		—		4,848		—		—		4,153		—
Net income - diluted	$	31,968		773,165	$	0.04	$	185,219		800,217	$	0.23

	Nine Months Ended September 30
	2025						2024
	Net income		Weighted average common shares (000s)		Net income per share		Net income		Weighted average common shares (000s)		Net income per share
Net income - basic	$	253,108		769,481	$	0.33	$	275,074		810,589	$	0.34
Dilutive effect of share awards and DSUs		—		4,199		—		—		3,762		—
Net income - diluted	$	253,108		773,680	$	0.33	$	275,074		814,351	$	0.34

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

13.

PETROLEUM AND NATURAL GAS SALES

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

	Three Months Ended September 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	99,188	$	426,712	$	525,900	$	122,452	$	525,135	$	647,587
Heavy oil		329,005		—		329,005		350,859		—		350,859
NGL		7,250		34,154		41,404		6,067		44,034		50,101
Natural gas		2,462		28,877		31,339		3,089		22,987		26,076
Total petroleum and natural gas sales	$	437,905	$	489,743	$	927,648	$	482,467	$	592,156	$	1,074,623

	Nine Months Ended September 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	282,532	$	1,287,251	$	1,569,783	$	321,704	$	1,589,648	$	1,911,352
Heavy oil		981,970		—		981,970		1,050,743		—		1,050,743
NGL		21,371		120,333		141,704		17,579		127,963		145,542
Natural gas sales		17,219		102,681		119,900		17,314		66,987		84,301
Total petroleum and natural gas sales	$	1,303,092	$	1,510,265	$	2,813,357	$	1,407,340	$	1,784,598	$	3,191,938

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

48	Baytex Energy Corp. Third Quarter Report 2025

14.

INCOME TAXES

The provision for income taxes has been computed as follows:

	Nine Months Ended September 30
	2025			2024
Net income before income taxes	$	311,369		$	351,669
Expected income taxes at the statutory rate of 24.16% (2024 – 24.38%) ⁽¹⁾		75,227			85,737
Change in income taxes resulting from:
Effect of foreign exchange		(8,533	)		4,269
Effect of rate adjustments for foreign jurisdictions		(5,745	)		(6,333	)
Effect of change in deferred tax benefit not recognized ⁽²⁾		(9,465	)		(22,087	)
Repatriation and related taxes		8,124			10,863
Adjustments, assessments and other		(1,347	)		4,146
Income tax expense	$	58,261		$	76,595

(1)

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

(2)

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

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

Baytex Energy Corp. Third Quarter Report 2025

15.

FINANCING AND INTEREST

	Three Months Ended September 30				Nine Months Ended September 30
	2025		2024		2025			2024
Interest on Credit Facilities	$	6,832	$	12,343	$	19,870		$	46,271
Interest on long-term notes		36,718		37,426		114,680			109,760
Interest on lease obligations		323		340		985			1,304
Cash interest	$	43,873	$	50,109	$	135,535		$	157,335
Amortization of debt issue costs		2,564		3,067		9,300			13,989
Accretion on asset retirement obligations (note 9)		5,999		5,524		17,315			15,910
Gain on repurchase and cancellation of long-term notes (note 8)		—		—		(2,755	)		—
Early redemption expense		—		—		—			24,350
Financing and interest	$	52,436	$	58,700	$	159,395		$	211,584

16.

FOREIGN EXCHANGE

	Three Months Ended September 30					Nine Months Ended September 30
	2025		2024			2025			2024
Unrealized foreign exchange loss (gain)	$	36,840	$	(24,401	)	$	(67,427	)	$	33,506
Realized foreign exchange loss (gain)		81		(151	)		(116	)		1,934
Foreign exchange loss (gain)	$	36,921	$	(24,552	)	$	(67,543	)	$	35,440

50	Baytex Energy Corp. Third Quarter Report 2025

17.

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

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

	September 30, 2025						December 31, 2024
	Carrying value			Fair value			Carrying value			Fair value			Fair Value Measurement Hierarchy
Financial Assets
Fair value through profit and loss
Financial derivatives	$	15,896		$	15,896		$	25,573		$	25,573			Level 2
Total	$	15,896		$	15,896		$	25,573		$	25,573

Amortized cost
Cash	$	10,417		$	10,417		$	16,610		$	16,610			—
Trade receivables		324,287			324,287			387,266			387,266			—
Total	$	334,704		$	334,704		$	403,876		$	403,876

Financial Liabilities
Fair value through profit and loss
Financial derivatives	$	(7,315	)	$	(7,315	)	$	(1,645	)	$	(1,645	)		Level 2
Total	$	(7,315	)	$	(7,315	)	$	(1,645	)	$	(1,645	)

Amortized cost
Trade payables	$	(554,057	)	$	(554,057	)	$	(512,473	)	$	(512,473	)		—
Dividends payable		(17,326	)		(17,326	)		(17,598	)		(17,598	)		—
Credit Facilities ⁽¹⁾		(166,841	)		(182,345	)		(324,346	)		(341,207	)		—
Long-term notes		(1,815,230	)		(1,870,105	)		(1,932,890	)		(1,990,598	)		Level 1
Total	$	(2,553,454	)	$	(2,623,833	)	$	(2,787,307	)	$	(2,861,876	)

(1)

The difference in the carrying value and fair value of the credit facilities is due to unamortized debt issuance costs. Refer to Note 7.

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

Foreign Currency Risk

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

Assets

Liabilities

September 30, 2025

December 31, 2024

September 30, 2025

December 31, 2024

U.S. dollar denominated

US$

14,442

US$

21,450

US$

1,367,342

US$

1,399,881

Baytex Energy Corp. Third Quarter Report 2025

Commodity Price Risk

Financial Derivative Contracts

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

	Remaining Period	Volume	Price/Unit ⁽¹⁾	Index
Oil
Basis differential	Oct 2025 to Dec 2025	23,500 bbl/d	WTI less US$13.25/bbl	WCS
Basis differential	Jan 2026 to Mar 2026	2,500 bbl/d	WTI less US$13.35/bbl	WCS
Basis differential	Apr 2026 to Jun 2026	2,500 bbl/d	WTI less US$12.55/bbl	WCS
Basis differential	Jul 2026 to Sep 2026	2,500 bbl/d	WTI less US$13.05/bbl	WCS
Basis differential	Jan 2026 to Dec 2026	17,500 bbl/d	WTI less US$13.20/bbl	WCS
Basis differential	Oct 2026 to Dec 2026	2,500 bbl/d	WTI less US$13.75/bbl	WCS
Basis differential ⁽²⁾	Jan 2026 to Dec 2026	2,000 bbl/d	WTI less US$12.50/bbl	WCS
Basis differential	Oct 2025 to Dec 2025	5,900 bbl/d	WTI less US$3.46/bbl	MSW
Basis differential	Apr 2026 to Jun 2026	1,000 bbl/d	WTI less US$3.75/bbl	MSW
Basis differential	Jul 2026 to Sep 2026	1,000 bbl/d	WTI less US$3.50/bbl	MSW
Basis differential	Oct 2026 to Dec 2026	1,000 bbl/d	WTI less US$4.25/bbl	MSW
Put option ⁽³⁾	Jan 2026 to Jun 2026	2,000 bbl/d	US$60.00	WTI
Call option ⁽³⁾	Jan 2026 to Jun 2026	2,000 bbl/d	US$70.00	WTI
Collar	Oct 2025 to Dec 2025	4,500 bbl/d	US$60.00/US$70.00	WTI
Collar ⁽³⁾	Oct 2025 to Dec 2025	25,000 bbl/d	US$60.00/US$70.00	WTI
Collar ⁽³⁾	Oct 2025 to Dec 2025	6,000 bbl/d	US$60.00/US$80.00	WTI
Collar ⁽³⁾	Jan 2026 to Mar 2026	2,000 bbl/d	US$60.00/US$75.00	WTI
Collar ⁽³⁾	Jan 2026 to Mar 2026	2,000 bbl/d	US$60.00/US$75.55	WTI
Collar	Jan 2026 to Jun 2026	5,000 bbl/d	US$60.00/US$67.00	WTI
Collar	Jan 2026 to Apr 2026	2,500 bbl/d	US$60.00/US$68.00	WTI
Collar	Jan 2026 to Jun 2026	5,000 bbl/d	US$60.00/US$66.00	WTI
Collar	Jan 2026 to Jun 2026	5,000 bbl/d	US$60.00/US$64.00	WTI
Collar	Jan 2026 to Jun 2026	5,000 bbl/d	US$60.00/US$65.00	WTI
Collar	Jan 2026 to Jun 2026	2,500 bbl/d	US$60.00/US$68.00	WTI

Natural Gas
Swap	Oct 2025 to Dec 2026	2,000 GJ/d	$3.21	AECO
Basis differential	Oct 2025 to Dec 2025	5,000 mmbtu/d	NYMEX less US$1.58/mmbtu	NYMEX/AECO
Basis differential	Jan 2026 to Dec 2026	2,500 mmbtu/d	NYMEX less US$1.66/mmbtu	NYMEX/AECO
Collar	Oct 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.01	NYMEX
Collar	Oct 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.03	NYMEX
Collar	Oct 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.08	NYMEX
Collar	Oct 2025 to Dec 2025	3,000 mmbtu/d	US$3.25/US$4.135	NYMEX
Collar	Oct 2025 to Dec 2025	5,500 mmbtu/d	US$3.25/US$4.14	NYMEX
Collar	Oct 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.32	NYMEX
Collar	Oct 2025 to Dec 2025	3,000 mmbtu/d	US$3.00/US$4.85	NYMEX
Collar	Oct 2025 to Dec 2025	8,000 mmbtu/d	US$3.00/US$4.855	NYMEX
Collar	Oct 2025 to Dec 2025	9,000 mmbtu/d	US$3.00/US$4.05	NYMEX
Collar	Jan 2026 to Dec 2026	10,000 mmbtu/d	US$3.25/US$4.25	NYMEX
Collar	Jan 2026 to Dec 2026	11,000 mmbtu/d	US$3.25/US$5.02	NYMEX
Collar	Jan 2026 to Dec 2026	20,000 mmbtu/d	US$4.00/US$5.10	NYMEX

(1)

Based on the weighted average price per unit for the period.

(2)

Contract entered subsequent to September 30, 2025.

(3)

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

52	Baytex Energy Corp. Third Quarter Report 2025

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

	Three Months Ended September 30						Nine Months Ended September 30
	2025			2024			2025		2024
Realized financial derivatives loss (gain)	$	8,580		$	(331	)	$	20,648	$	(3,562	)
Unrealized financial derivatives (gain) loss		(3,541	)		(22,596	)		15,347		(1,036	)
Financial derivatives loss (gain)	$	5,039		$	(22,927	)	$	35,995	$	(4,598	)

18.

CAPITAL MANAGEMENT

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

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

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

Net Debt

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

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

	September 30, 2025			December 31, 2024
Credit Facilities	$	166,841		$	324,346
Unamortized debt issuance costs - Credit Facilities (note 7)		15,504			16,861
Long-term notes		1,815,230			1,932,890
Unamortized debt issuance costs - Long-term notes (note 8)		40,375			47,729
Trade payables		554,057			512,473
Share-based compensation liability		24,666			24,732
Dividends payable		17,326			17,598
Other long-term liabilities		20,163			20,887
Cash		(10,417	)		(16,610	)
Trade receivables		(324,287	)		(387,266	)
Prepaids and other assets		(75,100	)		(76,468	)
Net Debt	$	2,244,358		$	2,417,172

Baytex Energy Corp. Third Quarter Report 2025

Adjusted Funds Flow

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

	Three Months Ended September 30						Nine Months Ended September 30
	2025			2024			2025			2024
Cash flows from operating activities	$	472,676		$	550,042		$	1,258,305		$	1,439,399
Change in non-cash working capital		(55,961	)		(20,813	)		(17,885	)		31,350
Asset retirement obligations settled		5,517			8,718			12,601			22,344
Transaction costs		—			—			—			1,539
Adjusted Funds Flow	$	422,232		$	537,947		$	1,253,021		$	1,494,632

54	Baytex Energy Corp. Third Quarter Report 2025

ABBREVIATIONS

AECO	the natural gas storage facility located at Suffield, Alberta
bbl	barrel
bbl/d	barrel per day
boe*	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
COSO	Committee of Sponsoring Organizations of the Treadway Commission
GAAP	generally accepted accounting principles
GJ	gigajoule
GJ/d	gigajoule per day
IAS	International Accounting Standard
IASB	International Accounting Standard Board

IFRS	International Financial Reporting Standards
LLS	Louisiana Light Sweet
mbbl	thousand barrels
mboe*	thousand barrels of oil equivalent
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmBtu	million British Thermal Units
mmBtu/d	million British Thermal Units per day
mmcf	million cubic feet
mmcf/d	million cubic feet per day
NGL	natural gas liquids
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
TSX	Toronto Stock Exchange
WCS	Western Canadian Select
WTI	West Texas Intermediate

Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Baytex Energy Corp. Third Quarter Report 2025