Baytex Announces Fourth Quarter and Full Year 2025 Results and CEO Succession; Completes Transition to a Focused Canadian Energy Company

By ogrepublic On Mar 4, 2026

Calgary, Alberta–(Newsfile Corp. – March 4, 2026) – Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) (“Baytex”) reports its operating and financial results for the three months and year ended December 31, 2025 (all amounts are in Canadian dollars unless otherwise noted).

“2025 was a definitive year for Baytex, marked by the successful repositioning of our portfolio into a focused, high-return Canadian oil producer,” said Eric T. Greager, Chief Executive Officer. “We strengthened our financial position and reinforced our potential for long-term value creation. With a sustaining breakeven of US$52/bbl WTI, Baytex is well-positioned to navigate market volatility and accelerate shareholder returns. Our 2026 plan is already delivering operational momentum across our core Pembina Duvernay and heavy oil fairways, and I am confident the company is set up for a seamless leadership transition.”

2025 Highlights

Completed the divestiture of U.S. Eagle Ford assets for net proceeds of $3.0 billion on December 19, 2025, successfully transitioning Baytex to a focused Canadian producer.
Significantly strengthened financial position with cash of $857 million (cash less principal amount of Senior Notes that remain outstanding).
Delivered 2025 Canadian production of 65,528 boe/d (89% oil and NGL), representing 6% organic growth over 2024. Q4/2025 Canadian production averaged 67,295 boe/d (88% oil and NGL).
Reported a 2025 net loss of $604 million ($0.78 per basic share) due to non-cash, one-time items associated with the Eagle Ford divestiture and a Viking impairment, with no impact to cash flow.
Reported cash flows from operating activities of $1.5 billion ($1.93 per basic share) for 2025, including $228 million ($0.30 per basic share) in the fourth quarter.
Delivered full-year adjusted funds flow⁽¹⁾of $1.5 billion ($1.97 per basic share) with $262 million ($0.34 per basic share) generated in Q4/2025.
Realized free cash flow⁽²⁾ of $275 million ($0.36 per basic share) for the full-year, including $76 million ($0.10 per basic share) in Q4/2025.
Re-initiated share buybacks on December 24, 2025. To-date, Baytex has repurchased 30 million shares (3.9% of shares outstanding) for $141 million.
Declared total cash dividends of $0.09 per share in 2025, representing $69 million returned to shareholders.

CEO Succession

Chad Lundberg, President and Chief Operating Officer, will succeed Eric Greager as Chief Executive Officer following the Annual General Meeting (“AGM”) on May 7, 2026. Mr. Lundberg joined Baytex in 2018 and has played an instrumental role in the strategic development and operational expansion of the Company’s portfolio. To ensure a seamless transition, Mr. Greager will remain as CEO and a member of the Board until the AGM, at which time Mr. Lundberg will be nominated for election as a Director.

“The Board has been committed to a rigorous succession process to ensure Baytex is led by the right individual for our next chapter,” said Mark Bly, Chair of the Board of Directors. “As we sharpen our focus on our core Canadian assets, Chad’s deep operational expertise and proven leadership make him the right choice to drive our business forward. We are confident that his strategic vision and commitment to financial discipline will drive continued value creation. On behalf of the Board, I thank Eric for positioning the company for success and establishing the strong foundation from which Chad will now lead.”

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

(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standard (“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.

		Three Months Ended									Twelve Months Ended
		December 31, 2025			September 30, 2025			December 31, 2024			December 31, 2025			December 31, 2024
FINANCIAL (thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales	$	759,815		$	927,648		$	1,017,017		$	3,573,172		$	4,208,955
Adjusted funds flow ⁽¹⁾		261,531			422,232			461,886			1,514,552			1,956,518
Per share – basic		0.34			0.55			0.59			1.97			2.44
Per share – diluted		0.34			0.55			0.59			1.97			2.42
Free cash flow ⁽²⁾		76,486			142,688			254,838			274,891			655,582
Per share – basic		0.10			0.19			0.33			0.36			0.82
Per share – diluted		0.10			0.18			0.33			0.36			0.81
Cash flows from operating activities		227,657			472,676			468,865			1,485,962			1,908,264
Per share – basic		0.30			0.62			0.60			1.93			2.38
Per share – diluted		0.30			0.61			0.60			1.93			2.36
Net (loss) income		(856,887	)		31,968			(38,477	)		(603,779	)		236,597
Per share – basic		(1.12	)		0.04			(0.05	)		(0.78	)		0.29
Per share – diluted		(1.12	)		0.04			(0.05	)		(0.78	)		0.29
Dividends declared		17,268			17,326			17,598			69,187			71,985
Per share		0.0225			0.0225			0.0225			0.090			0.090

Capital Expenditures
Exploration and development expenditures	$	174,078		$	270,364		$	198,177		$	1,206,071		$	1,256,633
Acquisitions and (divestitures)		(3,006,514	)		15,770			(29,718	)		(2,991,285	)		5,920
Total oil and natural gas capital expenditures	$	(2,832,436	)	$	286,134		$	168,459		$	(1,785,214	)	$	1,262,553

Net (Cash) Debt
Credit facilities	$	1,400		$	182,345		$	341,207		$	1,400		$	341,207
Long-term notes		95,947			1,855,605			1,980,619			95,947			1,980,619
Total debt ⁽³⁾		97,347			2,037,950			2,321,826			97,347			2,321,826
Working capital (surplus) deficiency ⁽²⁾		(863,132	)		206,408			95,346			(863,132	)		95,346
Net (cash) debt⁽¹⁾	$	(765,785	)	$	2,244,358		$	2,417,172		$	(765,785	)	$	2,417,172

Shares Outstanding – basic (thousands)
Weighted average		768,287			768,317			782,131			769,180			803,435
End of period		765,568			768,317			773,590			765,568			773,590

BENCHMARK PRICES
Crude oil
WTI (US$/bbl)	$	59.14		$	64.93		$	70.27		$	64.81		$	75.72
MEH oil (US$/bbl)		60.70			67.03			72.40			66.66			77.99
MEH oil differential to WTI (US$/bbl)		1.56			2.10			2.13			1.85			2.27
Edmonton par ($/bbl)		76.49			86.20			94.98			85.53			97.59
Edmonton par differential to WTI (US$/bbl)		(4.30	)		(2.35	)		(2.39	)		(3.62	)		(4.49	)
WCS heavy oil ($/bbl)		66.88			75.14			80.77			75.06			83.56
WCS differential to WTI (US$/bbl)		(11.19	)		(10.38	)		(12.54	)		(11.11	)		(14.73	)
Natural gas
NYMEX (US$/mmbtu)	$	3.55		$	3.07		$	2.79		$	3.43		$	2.27
AECO ($/mcf)		2.34			1.00			1.46			1.86			1.44

CAD/USD average exchange rate		1.3949			1.3774			1.3992			1.3978			1.3700

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.

		Three Months Ended									Twelve Months Ended
		December 31, 2025			September 30, 2025			December 31, 2024			December 31, 2025			December 31, 2024
OPERATING
Daily Production
Light oil and condensate (bbl/d)		12,031			12,605			11,568			11,897			11,983
Heavy oil (bbl/d)		42,628			45,269			42,227			42,775			42,313
NGL (bbl/d)		4,488			3,485			3,519			3,524			2,749
Total liquids (bbl/d)		59,147			61,359			57,314			58,196			57,045
Natural gas (mcf/d)		48,895			40,961			48,113			43,988			41,412
Total Canada (boe/d) ⁽¹⁾		67,295			68,185			65,332			65,528			63,948
Discontinued operations (boe/d) ⁽¹⁾		69,792			82,765			87,562			79,551			89,100
Oil equivalent (boe/d) ⁽¹⁾		137,087			150,950			152,894			145,079			153,048

Adjusted Funds Flow (thousands of Canadian dollars)
Total sales, net of blending and other expense ⁽²⁾	$	331,517		$	388,155		$	386,558		$	1,449,658		$	1,610,103
Royalties		(43,132	)		(53,645	)		(60,396	)		(203,833	)		(261,205	)
Operating expense		(85,708	)		(84,994	)		(78,878	)		(334,317	)		(336,069	)
Transportation expense		(21,314	)		(23,060	)		(21,595	)		(83,697	)		(84,211	)
Operating netback – Canada⁽²⁾	$	181,363		$	226,456		$	225,689		$	827,811		$	928,618
General and administrative		(16,918	)		(15,824	)		(14,719	)		(67,903	)		(58,363	)
Cash interest		(36,455	)		(39,906	)		(46,277	)		(161,432	)		(188,632	)
Realized financial derivatives gain (loss)		1,013			(8,580	)		(2,115	)		(19,635	)		1,447
Other ⁽³⁾		(12,789	)		(10,300	)		(14,516	)		(36,251	)		(26,516	)
Adjusted funds flow – Canada ⁽⁴⁾	$	116,214		$	151,846		$	148,062		$	542,590		$	656,554
Adjusted funds flow – Discontinued operations ⁽⁴⁾	$	145,317		$	270,386		$	313,824		$	971,962		$	1,299,964
Adjusted funds flow ⁽⁴⁾	$	261,531		$	422,232		$	461,886		$	1,514,552		$	1,956,518

Adjusted Funds Flow (per boe)
Total sales, net of blending and other expense ⁽²⁾	$	53.55		$	61.88		$	64.31		$	60.61		$	68.79
Royalties ⁽⁵⁾		(6.97	)		(8.55	)		(10.05	)		(8.52	)		(11.16	)
Operating expense ⁽⁵⁾		(13.84	)		(13.55	)		(13.12	)		(13.98	)		(14.36	)
Transportation expense ⁽⁵⁾		(3.44	)		(3.68	)		(3.59	)		(3.50	)		(3.60	)
Operating netback – Canada ⁽²⁾	$	29.30		$	36.10		$	37.55		$	34.61		$	39.67
General and administrative ⁽⁵⁾		(2.73	)		(2.52	)		(2.45	)		(2.84	)		(2.49	)
Cash interest ⁽⁵⁾		(5.89	)		(6.36	)		(7.70	)		(6.75	)		(8.06	)
Realized financial derivatives gain (loss) ⁽⁵⁾		0.16			(1.37	)		(0.35	)		(0.82	)		0.06
Other ⁽³⁾		(2.07	)		(1.64	)		(2.42	)		(1.52	)		(1.13	)
Adjusted funds flow – Canada ⁽⁴⁾	$	18.77		$	24.21		$	24.63		$	22.68		$	28.05
Adjusted funds flow – Discontinued operations ⁽⁴⁾	$	22.63		$	35.51		$	38.96		$	33.47		$	39.86
Adjusted funds flow ⁽⁴⁾	$	20.74		$	30.40		$	32.84		$	28.60		$	34.93

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.

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

2026 Outlook: Focused Canadian Operations

Baytex enters 2026 as a focused Canadian producer with a high-quality asset base centered on heavy oil operations and an attractive position in the Pembina Duvernay.

Our 2026 budget, released in December 2025, targets annual production of 67,000 to 69,000 boe/d, representing 3% to 5% organic growth year-over-year, with E&D expenditures of $550 to $625 million. This plan is designed to deliver disciplined growth while investing in the long-term infrastructure and exploration to support future value creation. We have significant inventory depth and optionality across our portfolio to support our current plan and potentially accelerate growth beyond these levels.

We are efficiently executing our first quarter capital program with seven rigs currently active across our portfolio. Production in Q1/2026 is forecast to average 68,000 to 69,000 boe/d, with production increasing to approximately 70,000 boe/d as we exit 2026.

Our heavy oil assets comprise 750,000 net acres and 1,100 drilling locations, supporting approximately 12 years of drilling at our current pace of development. We currently have five drilling rigs active across our heavy oil fairway targeting the Clearwater at Peavine and the broader Mannville stack in Lloydminster. We expect to bring 91 heavy oil wells onstream in 2026.

Our 2026 program will see increased exploration activity, including stratigraphic tests, step-out wells and 3-D seismic, to expand our development inventory and test new play concepts across our extensive heavy oil fairway. In addition, we are advancing two waterflood pilot projects at Peavine, blending the attractive capital efficiencies of multi-lateral primary development with the potential for enhanced recovery and moderated decline rates.

In the Duvernay, we have assembled 91,500 net acres and identified approximately 210 drilling locations. Production is expected to increase 35% to average approximately 11,000 boe/d in 2026, with a target year-end exit rate of 14,000 to 15,000 boe/d. We currently have one rig drilling a four-well pad on our southern acreage. Completion operations are scheduled for the second quarter with the wells expected to be onstream by mid-year. The remaining two pads are expected onstream during the third and fourth quarters.

2025 Results

On December 19, 2025, Baytex completed the divestiture of its U.S. Eagle Ford assets for net proceeds of US$2.2 billion ($3.0 billion in Canadian dollars) after closing adjustments. As a result of the disposition, results from the operated and non-operated Eagle Ford properties have been classified as discontinued operations for the current and comparative periods.

For the full-year 2025, adjusted funds flow⁽¹⁾ totaled $1.5 billion ($1.97 per basic share) and we generated free cash flow⁽²⁾ of $275 million ($0.36 per basic share). In the fourth quarter, we incurred non-recurring, one-time cash tax and severance costs associated with the Eagle Ford divestiture. These expensed items reduced adjusted funds flow by $37 million ($0.05 per basic share). In addition, we reported a net loss of $604 million ($0.78 per basic share), primarily driven by non-cash, one-time items associated with the strategic repositioning of the portfolio. These include a loss on the Eagle Ford disposition, a deferred tax adjustment related to the transaction structure, and an impairment on Viking assets.

Canadian production averaged 65,528 boe/d (89% oil and NGL) in 2025, representing 6% organic growth over 2024 (excluding non-core divestitures). Fourth quarter Canadian production averaged 67,295 boe/d (88% oil and NGL). Exploration and development expenditures in Canada totaled $548 million for the full-year, including $93 million in the fourth quarter, reflecting a highly capital-efficient program.

Accelerated Shareholder Returns

Baytex entered 2026 with a cash position of $857 million (cash less principal amount of Senior Notes that remain outstanding), providing significant financial flexibility to support our commitment to shareholder returns. We intend to prioritize share buybacks while maintaining our current annual dividend of $0.09 per share.

Following the close of the Eagle Ford sale, we re-initiated our share buyback program on December 24, 2025. To date (through March 3, 2026), we have repurchased 30 million shares for $141 million, representing 3.9% of our shares outstanding at an average price of $4.72 per share. Our current Normal Course Issuer Bid (“NCIB”) allows for the purchase of up to 66.2 million shares through the 12-month period ending July 1, 2026.

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

Quarterly Dividend

The Board of Directors has declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2026 for shareholders of record on March 13, 2026.

Additional Information

Our audited consolidated financial statements for the year ended December 31, 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.

Conference Call Tomorrow
9:00 a.m. MST (11:00 a.m. EST)

Baytex will host a conference call tomorrow, March 5, 2026, starting at 9:00am MST (11:00am EST). To participate, please dial toll free in North America 1-844-763-8274 or international 1-647-484-8814. Alternatively, to listen to the conference call online, please enter https://event.choruscall.com/mediaframe/webcast.html?webcastid=SuCq95hl in your web browser.

An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.

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 have a sustaining breakeven of US$52/bbl WTI, are well positioned to navigate market volatility and accelerate shareholder returns and set up for a seamless leadership transition; that Chad Lundberg will succeed Eric Greager as chief executive officer on May 7, 2026; our development plans for 2026, our expected full-year production volumes, expected production growth rate and exploration and development expenditures; that we can accelerate growth beyond these levels; our expected Q1/2026 production rate and 2026 exit production rate; in our heavy oil assets: that we have 12 years of drilling locations at our current pace of development, expect to bring 91 wells on stream in 2026 and types of activity we will carry out; in the Duvernay: our expected average annual and target year-end exit target production rate for 2026, and the timing for completion activities and wells onstream; that we intend to prioritize share buybacks while maintaining our dividend. 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; the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; 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; 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 Corporation 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.

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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 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 will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Corporation’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 Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely.

These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2025, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission on March 4, 2026 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 Corporation’s potential financial position, including, but not limited to, our 2026 guidance for development expenditures; and our intentions of allocating funds to share buybacks and a dividend; 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 Corporation 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 Corporation 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 Corporation’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 free cash flow, operating netback, working capital (surplus) deficiency and total sales, net of blending and other expense) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This press release also contains the terms “adjusted funds flow” and “net (cash) debt” which are considered capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.

Non-GAAP Financial Measures

Total sales, net of blending and other expense

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

Operating netback

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

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

		Three Months Ended									Years Ended December 31
($ thousands)		December 31, 2025			September 30, 2025			December 31, 2024			2025			2024
Petroleum and natural gas sales	$	381,556		$	437,905		$	466,706		$	1,684,648		$	1,874,046
Blending and other expense		(50,039	)		(49,750	)		(80,148	)		(234,990	)		(263,943	)
Total sales, net of blending and other expense	$	331,517		$	388,155		$	386,558		$	1,449,658		$	1,610,103
Royalties		(43,132	)		(53,645	)		(60,396	)		(203,833	)		(261,205	)
Operating expense		(85,708	)		(84,994	)		(78,878	)		(334,317	)		(336,069	)
Transportation expense		(21,314	)		(23,060	)		(21,595	)		(83,697	)		(84,211	)
Operating netback – Canada	$	181,363		$	226,456		$	225,689		$	827,811		$	928,618

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, transaction costs, additions to exploration and evaluation assets, additions to oil and gas properties, and payments on lease obligations.

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

		Three Months Ended									Years Ended December 31
($ thousands)		December 31, 2025			September 30, 2025			December 31, 2024			2025			2024
Cash flows from operating activities	$	227,657		$	472,676		$	468,865		$	1,485,962		$	1,908,264
Change in non-cash working capital		(226	)		(55,961	)		(13,428	)		(18,111	)		17,922
Transaction costs		26,383			–			–			26,383			1,539
Additions to exploration and evaluation assets		–			–			–			(930	)		–
Additions to oil and gas properties		(174,078	)		(270,364	)		(198,177	)		(1,205,141	)		(1,256,633	)
Payments on lease obligations		(3,250	)		(3,663	)		(2,422	)		(13,272	)		(15,510	)
Free cash flow	$	76,486		$	142,688		$	254,838		$	274,891		$	655,582

Working capital (surplus) deficiency

Working capital (surplus) deficiency is calculated as cash, trade receivables, and prepaids and other assets net of trade payables, share-based compensation liability, other long-term liabilities, and dividends payable. Working capital (surplus) deficiency is used by management to measure the Company’s liquidity. At December 31, 2025, the Company had $744.2 million of available credit facility capacity to cover any working capital deficiencies.

The following table summarizes the calculation of working capital (surplus) deficiency.

		As at
($ thousands)		December 31, 2025			September 30, 2025			December 31, 2024
Cash	$	(953,113	)	$	(10,417	)	$	(16,610	)
Trade receivables		(135,230	)		(324,287	)		(387,266	)
Prepaids and other assets		(63,232	)		(75,100	)		(76,468	)
Trade payables		236,373			554,057			512,473
Share-based compensation liability		34,802			24,666			24,732
Other long-term liabilities		–			20,163			20,887
Dividends payable		17,268			17,326			17,598
Working capital (surplus) deficiency	$	(863,132	)	$	206,408		$	95,346

Non-GAAP Financial Ratios

Total sales, net of blending and other expense per boe

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

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 (cash) debt

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

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

		As at
($ thousands)		December 31, 2025			September 30, 2025			December 31, 2024
Credit facilities	$	1,138		$	166,841		$	324,346
Unamortized debt issuance costs – Credit facilities ⁽¹⁾		262			15,504			16,861
Long-term notes		93,834			1,815,230			1,932,890
Unamortized debt issuance costs – Long-term notes ⁽¹⁾		2,113			40,375			47,729
Trade payables		236,373			554,057			512,473
Share-based compensation liability		34,802			24,666			24,732
Dividends payable		17,268			17,326			17,598
Other long-term liabilities		–			20,163			20,887
Cash		(953,113	)		(10,417	)		(16,610	)
Trade receivables		(135,230	)		(324,287	)		(387,266	)
Prepaids and other assets		(63,232	)		(75,100	)		(76,468	)
Net (cash) debt	$	(765,785	)	$	2,244,358		$	2,417,172

(1) Unamortized debt issuance costs were obtained from Note 9 Credit Facilities and Note 10 Long-term Notes from the Consolidated Financial Statements for the year ended December 31, 2025.

Adjusted funds flow

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

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

		Three Months Ended									Years Ended December 31
($ thousands)		December 31, 2025			September 30, 2025			December 31, 2024			2025			2024
Cash flows from operating activities	$	227,657		$	472,676		$	468,865		$	1,485,962		$	1,908,264
Change in non-cash working capital		(226	)		(55,961	)		(13,428	)		(18,111	)		17,922
Asset retirement obligations settled		7,717			5,517			6,449			20,318			28,793
Transaction costs		26,383			–			–			26,383			1,539
Adjusted funds flow	$	261,531		$	422,232		$	461,886		$	1,514,552		$	1,956,518

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.

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

Throughout this press release, “oil and NGL” refers to heavy oil, bitumen, light and medium 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 twelve months ended December 31, 2025. The NI 51-101 product types are included as follows: “Heavy Oil” – heavy oil and bitumen, “Light and Medium Oil” – light and medium oil, tight oil and condensate, “NGL” – natural gas liquids and “Natural Gas” – shale gas and conventional natural gas.

	Three Months Ended December 31, 2025					Twelve Months Ended December 31, 2025
	Heavy Oil (bbl/d)	Light and Medium Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)	Heavy Oil (bbl/d)	Light and Medium Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada – Heavy
Peace River	9,493	8	35	8,974	11,032	9,726	12	32	9,629	11,374
Lloydminster	13,702	16	1	1,465	13,963	12,700	19	–	1,258	12,928
Peavine	18,582	–	–	–	18,582	19,235	–	–	–	19,235
Remaining Properties	802	3	–	660	915	1,034	2	–	680	1,150

Canada – Light
Viking	40	7,213	259	9,388	9,076	74	7,813	205	10,071	9,771
Duvernay	–	4,585	3,594	14,801	10,645	–	3,757	2,767	10,825	8,328
Remaining Properties	9	206	599	13,607	3,082	6	294	520	11,525	2,742

Total Canada	42,628	12,031	4,488	48,895	67,295	42,775	11,897	3,524	43,988	65,528

United States
Eagle Ford	–	42,109	13,524	84,950	69,792	–	48,971	15,491	90,528	79,551

Total	42,628	54,140	18,012	133,845	137,087	42,775	60,868	19,015	134,516	145,079

Baytex Energy Corp.

Baytex Energy Corp. is a Calgary-based energy company committed to driving shareholder value through disciplined execution. It operates a high-quality, high-return portfolio in the Western Canadian Sedimentary Basin, featuring the Pembina Duvernay and heavy oil plays in Alberta and Saskatchewan. These core assets are backed by an extensive drilling inventory and consistently generate strong cash flow. 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 and Investor Relations

Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/286251