Baytex Reports Strong Canadian Reserves Growth and Positive Operational Momentum

Rhea-AI Summary

Baytex (TSX: BTE, NYSE: BTE) reported year-end 2025 reserves growth in Canada and an operations update, following a strategic U.S. asset divestiture and entry into 2026 with net cash.

Key metrics: PDP +12% to 69 MMboe, 1P +15% to 151 MMboe, 2P +9% to 282 MMboe, net cash ~ $857M, 2026 production target of 67,000–69,000 boe/d.

Positive

• PDP reserves increased by 12% to 69 MMboe at year-end 2025
• 1P reserves increased by 15% to 151 MMboe at year-end 2025
• 2P reserves increased by 9% to 282 MMboe at year-end 2025
• Entered 2026 with a net cash position of approximately $857 million
• Repurchased 17.1 million common shares for $78 million (2.2% of shares) through Jan 30, 2026
• Duvernay production expected to rise ~35% to ~11,000 boe/d in 2026

Negative

• 2025 exploration and development expenditures totaled $1,207 million
• Planned 2026 capital program of $550–$625 million maintains high cash deployment
• 2026 production growth target is modest at 3%–5%
• Q1 2026 hedges cover ~60% of net crude exposure with collars limiting upside (US$60–67/bbl)

Key Figures

Q4 2025 production: 137,087 boe/d 2025 production: 145,079 boe/d Canada 2025 production: 65,528 boe/d +5 more

8 metrics

Q4 2025 production 137,087 boe/d Consolidated, 84% oil and NGL in Q4 2025

2025 production 145,079 boe/d Consolidated, 85% oil and NGL for full-year 2025

Canada 2025 production 65,528 boe/d Canada, 89% oil and NGL, 6% growth vs 2024

2025 E&D capex $1,207 million Exploration and development expenditures in 2025

Canada E&D capex $549 million Canadian exploration and development expenditures in 2025

Operating netback $34.61/boe 2025 operating netback used for F&D recycle ratios

Net cash position $857 million Net cash entering 2026 after debt repayment

Share buybacks 17.1 million shares for $78 million Repurchased through Jan 30, 2026 at $4.55 per share

Market Reality Check

Price: $3.37 Vol: Volume 20,621,123 vs 20-d...

normal vol

$3.37 Last Close

Volume Volume 20,621,123 vs 20-day average 19,372,947 (relative volume 1.06) ahead of the reserves update. normal

Technical Shares at $3.37 trade above the 200-day MA of $2.36 and are 7.16% below the 52-week high of $3.63.

Peers on Argus

BTE fell 1.72% while peers were mixed: BKV -2.36%, TALO +1.31%, MNR +0.87%, KRP ...

BTE fell 1.72% while peers were mixed: BKV -2.36%, TALO +1.31%, MNR +0.87%, KRP +0.23%, VET +1.84%, indicating a stock-specific move despite broadly stable sector conditions.

Historical Context

5 past events · Latest: Dec 22 (Positive)

Pattern 5 events

Date	Event	Sentiment	Move	Catalyst
Dec 22	2026 budget & outlook	Positive	+1.0%	2026 capex, 3–5% growth target, improved breakeven and leadership update.
Dec 19	Eagle Ford sale close	Positive	+1.0%	Closed US Eagle Ford sale, moved to net cash and outlined debt repayment.
Dec 15	Tender offer progress	Positive	+2.3%	Confirmed Eagle Ford closing timeline and early tender participation for 2032 notes.
Dec 01	Debt tender & redemption	Neutral	-1.6%	Announced cash tender for 2032 notes and intent to redeem 2030 notes.
Nov 12	Divest Eagle Ford assets	Positive	+13.5%	Agreed to sell Eagle Ford for cash, focus on higher-return Canadian core.

Pattern Detected

Recent corporate actions around the Eagle Ford divestiture and 2026 outlook have generally seen modestly positive price reactions, with the initial sale announcement drawing the strongest move.

Recent Company History

Over the past few months, Baytex has focused on reshaping its portfolio and balance sheet. On Nov 12, 2025, it agreed to sell U.S. Eagle Ford assets, which saw a 13.48% gain. Subsequent updates on the tender offer and closing of the sale in December, plus the 2026 budget and three-year outlook on Dec 22, 2025, produced smaller positive moves between 0.97% and 2.31%. Today’s Canadian reserves growth and operational update extend that Canada-focused narrative and net-cash positioning.

Market Pulse Summary

This announcement highlights solid Canadian reserves growth across PDP, 1P and 2P categories, alongs...

Analysis

This announcement highlights solid Canadian reserves growth across PDP, 1P and 2P categories, alongside a 2025 operating netback of $34.61/boe and a net cash position of $857 million. The company outlines 2026 production targets of 67,000–69,000 boe/d with $550–$625 million of planned exploration and development spending, and continued shareholder returns via buybacks and a $0.09 annual dividend. Investors may focus on execution in the Duvernay and heavy oil programs and future capital allocation disclosures.

Key Terms

boe/d, proved developed producing, proved plus probable, finding and development ("F&D") costs, +1 more

5 terms

boe/d technical

"Consolidated production averaged 137,087 boe/d (84% oil and NGL) in the fourth quarter"

A measure of energy production that converts oil and gas output into a single daily figure — barrels of oil equivalent per day — so different fuels can be compared on the same scale. Think of it like converting miles and kilometers into one unit before comparing distances: investors use boe/d to judge how much total hydrocarbon output a company generates, estimate revenue potential, and compare production efficiency across firms or projects.

proved developed producing technical

"We achieved solid reserves growth in Canada across all three reserves categories, proved developed producing ("PDP"), proved ("1P") and proved plus probable"

Proved developed producing (PDP) describes oil or gas reserves that are confirmed, already connected to production equipment, and actively yielding hydrocarbons. For investors, PDP is like money already in a company's cash register: it represents low-risk, near-term revenue because the wells are drilled, hooked up, and producing, so future income and cash flow estimates based on PDP are more reliable than projections for undeveloped or unproven reserves.

proved plus probable technical

"proved ("1P") and proved plus probable ("2P")"

Proved plus probable is the combined estimate of natural resource reserves that are expected to be recoverable: the "proved" portion is the high‑confidence amount, and the "probable" portion is an additional quantity that is likely but less certain. For investors it signals both the size and reliability of an asset—think of it as the guaranteed part of an inheritance plus an expected bonus—helping assess value, production potential, and risk when comparing projects or companies.

finding and development ("F&D") costs financial

"Finding and development ("F&D") costs, including changes in future development costs"

Finding and development ("F&D") costs are the total expenses a resource company spends to locate a new deposit or reserve and bring it into production, including exploration, appraisal, permitting and construction. Investors care because F&D shows how much capital is needed to replace or grow production—similar to measuring how much it costs a retailer to find a new neighborhood and build a functioning store—which affects future profits, cash flow and the value of the company's assets.

operating netback financial

"F&D recycle ratio of 2.1x based on a 2025 operating netback(1) of $34.61/boe"

Operating netback is a per-unit measure of how much cash a company keeps from selling a product after subtracting direct costs tied to producing and delivering that unit, such as royalties, production taxes, operating expenses and transportation. For investors it’s like the profit margin on one item — a quick way to compare the underlying cash profitability and efficiency of different producers or projects regardless of crude price or output volume.

AI-generated analysis. Not financial advice.

Calgary, Alberta--(Newsfile Corp. - February 2, 2026) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex") is pleased to announce its year-end 2025 reserves and provide an operations update (all amounts in Canadian dollars unless otherwise noted).

Our 2025 performance was highlighted by the strategic divestiture of our U.S. assets, resulting in a significantly strengthened financial position and sharpened focus on our high-return Canadian energy platform. We entered 2026 with a net cash position and remain committed to returning a significant portion of the net proceeds from the U.S. sale (after debt repayment) to shareholders.

Baytex is also providing an update on its 2025 consolidated operations, including U.S. assets up to the December 19, 2025 sale closing. Consolidated production averaged 137,087 boe/d (84% oil and NGL) in the fourth quarter, with annual 2025 production of 145,079 boe/d (85% oil and NGL). Exploration and development expenditures totaled $175 million during the fourth quarter and $1,207 million in 2025.

Production in Canada averaged 67,295 boe/d (88% oil and NGL) in the fourth quarter, with annual 2025 production of 65,528 boe/d (89% oil and NGL), representing a 6% growth rate compared to 2024 (excluding non-core divestitures). For 2026, we are targeting annual production of 67,000 to 69,000 boe/d with exploration and development expenditures of $550 to $625 million.

Year-End 2025 Reserves Highlights Value Creation - Canada

In Canada, we invested $549 million on exploration and development expenditures in a highly capital efficient program. Our Pembina Duvernay and heavy oil development contributed significantly to our year-end 2025 reserves, demonstrating the long-term resiliency and sustainability of our business and its capacity for future value creation.

We achieved solid reserves growth in Canada across all three reserves categories, proved developed producing ("PDP"), proved ("1P") and proved plus probable ("2P").

• PDP reserves increased 12% to 69 MMboe (61 MMboe at year-end 2024), replacing 133% of production.

• 1P reserves increased 15% to 151 MMboe (131 MMboe at year-end 2024), replacing 185% of production.

• 2P reserves increased 9% to 282 MMboe (259 MMboe at year-end 2024), replacing 203% of production.

• Finding and development ("F&D") costs, including changes in future development costs ("FDC") were $17.28/boe for PDP reserves, $16.39/boe for 1P reserves and $16.27/boe for 2P reserves.

• We generated a strong PDP F&D recycle ratio of 2.0x and a 1P and 2P F&D recycle ratio of 2.1x based on a 2025 operating netback⁽¹⁾ of $34.61/boe, reflective of the efficiency of our capital program.

• We maintain a robust reserves life index of 11.5 years based on 2P reserves.

Our 2025 reserves report continues a strong track record of value creation in Canada.

• Our three-year average (2023-2025) production replacement, excluding acquisitions and divestitures, for PDP, 1P, and 2P reserves is 119%, 151% and 169%, respectively.

• Our three-year average (2023-2025) F&D costs, including changes in FDC were $18.12/boe for PDP reserves, $18.74/boe for 1P reserves and $19.76/boe for 2P reserves.

• We generated a strong three-year average (2023-2025) F&D recycle ratio of 2.1x for PDP reserves, 2.0x for 1P reserves, and 1.9x for 2P reserves.

(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.

Operations Update - Driving Performance in Our Canadian Portfolio

We are building on the operational momentum established last year with a 2026 plan that targets 3% to 5% annual production growth while investing in long-term infrastructure, exploration and land to support future growth and inventory expansion.

In the Duvernay, 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 running in the Duvernay, drilling the first well of 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 (4-wells each) are expected to be onstream during the third and fourth quarter. We have also commenced our infrastructure build-out for 2026, including anchor oil batteries and water handling.

Our heavy oil portfolio is expected to deliver stable production and reliable returns. 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. In addition, our 2026 program will see increased exploration activity, including stratigraphic tests, step-out wells and 3-D seismic.

At Peavine, we are drilling the third of thirteen multi-lateral horizontal wells on a single pad. In addition, we intend to undertake two waterflood pilot projects as we look to blend the attractive capital efficiencies of multi-lateral primary development with the potential upside of enhanced recovery and moderated decline rates.

At Lloydminster, our first quarter drilling program will target seven discrete horizons in the Mannville: Cummings, GP, Lloydminster, McLaren, Sparky and both the Upper and Lower Waseca. In northeast Alberta, we recently brought onstream two multi-lateral wells in the Sparky that generated average 30-day initial production rates of 450 bbl/d per well, and a five-well pad in the Upper Waseca that generated average 30-day initial production rates of 150 bbl/d per well.

In the Viking, we are running a largely level-loaded one rig program in 2026 (outside of spring break-up) to maximize efficiencies. We expect to bring 73 net wells onstream in 2026.

Strong Net Cash Position and Shareholder Returns

In December, we repaid our outstanding credit facilities, redeemed all of the US$759 million principal amount of 8.500% Senior Notes due 2030 and US$505 million principal amount of 7.375% Senior Notes due 2032 (of an original US$575 million principal amount outstanding) through a successful tender offer.

We entered 2026 with a net cash position (cash less principal amount of Senior Notes that remain outstanding) of approximately $857 million that provides significant financial flexibility. We intend to return a significant portion to shareholders, prioritizing share buybacks while maintaining our current annual dividend of $0.09 per share.

Our Normal Course Issuer Bid ("NCIB") allows Baytex to purchase up to 66.2 million common shares during the 12-month period ending July 1, 2026. On December 24, 2025, we re-initiated our share buyback program. To-date (through January 30, 2026) we have repurchased 17.1 million common shares for $78 million, representing 2.2% of our shares outstanding, at an average price of $4.55 per share.

Disciplined Risk Management

We employ a disciplined hedging strategy to manage heavy oil basis differential volatility. For 2026, approximately 45% of our net heavy oil basis differential exposure is hedged at a WTI-WCS basis differential of US$13.13/bbl.

We also have WTI hedges in place for the first half of 2026. For Q1/2026 we have entered into hedges on approximately 60% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$67/bbl. For Q2/2026 we have entered into hedges on approximately 50% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$66/bbl.

Year-End 2025 Results

Baytex expects to release its year-end 2025 operating and financial results on March 4, 2026.

Year-End 2025 Reserves

Baytex's year-end 2025 reserves were evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel"), an independent qualified reserves evaluator. All of our oil and gas properties were evaluated in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants ("GLJ") and Sproule ERCE ("Sproule") as of January 1, 2026.

Additional information regarding Baytex's reserves and other oil and gas information will be included in Baytex's Annual Information Form for the year ended December 31, 2025, which is expected to be filed on SEDAR+ and EDGAR on or around March 4, 2026.

The following table sets forth our gross and net reserves volumes at December 31, 2025 by product type and reserves category. Please note that the data in the table may not add due to rounding.

Reserves Summary

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (3)			Conventional Natural Gas (4)			Shale Gas			Total (5)
Reserves Summary		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
Gross (1)
Proved producing		8,466			4,256			38,513			-			51,235			7,003			46,117			18,277			68,970
Proved developed non-producing		-			-			993			-			993			1			236			-			1,033
Proved undeveloped		11,252			18,464			19,254			-			48,970			17,815			28,428			55,041			80,696
Total proved		19,718			22,719			58,760			-			101,197			24,819			74,780			73,318			150,699
Total probable		12,817			10,062			41,149			44,459			108,487			10,837			39,115			32,051			131,185
Proved plus probable		32,535			32,781			99,909			44,459			209,684			35,657			113,896			105,369			281,884
Net (2)
Proved producing		8,029			3,593			33,045			-			44,666			6,115			41,598			16,663			60,492
Proved developed non-producing		-			-			868			-			868			1			219			-			905
Proved undeveloped		10,735			15,798			17,184			-			43,718			15,577			24,806			49,697			71,712
Total proved		18,764			19,391			51,097			-			89,252			21,694			66,623			66,360			133,109
Total probable		11,876			8,065			34,599			35,743			90,282			9,129			34,047			28,442			109,826
Proved plus probable		30,640			27,455			85,696			35,743			179,534			30,823			100,670			94,801			242,936

 

Notes:

(1) "Gross" reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) "Net" reserves means Baytex's gross reserves less all royalties payable to others plus royalty interest reserves.
(3) Natural Gas Liquids includes condensate.
(4) Conventional Natural Gas includes associated, non-associated and solution gas.
(5) 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.

Reserves Reconciliation - Canada

The following table reconciles the year-over-year changes in our Canadian gross reserves volumes by product type and reserves category. Please note that the data in the table may not add due to rounding.

Proved Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		23,604			15,935			55,357			-			94,896			15,797			74,789			48,640			131,265
Extensions		982			7,853			14,174			-			23,008			8,994			13,463			26,434			38,652
Technical Revisions		(664	)		406			6,488			-			6,231			1,562			1,854			2,590			8,533
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions		(355	)		-			(147	)		-			(502	)		(66	)		(1,442	)		-			(809	)
Economic Factors		(950	)		(104	)		(1,503	)		-			(2,557	)		(140	)		(1,830	)		(395	)		(3,068	)
Production		(2,900	)		(1,371	)		(15,608	)		-			(19,879	)		(1,328	)		(12,054	)		(3,951	)		(23,874	)
December 31, 2025		19,718			22,719			58,760			-			101,197			24,819			74,780			73,318			150,699

 

Probable Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		13,644			11,406			34,190			44,489			103,729			11,400			38,344			37,041			127,692
Extensions		89			(1,559	)		10,144			-			8,673			(944	)		6,534			(4,694	)		8,035
Technical Revisions		(1,042	)		291			(2,996	)		-			(3,747	)		493			(5,191	)		(22	)		(4,122	)
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions		(332	)		-			(256	)		-			(587	)		(33	)		(700	)		-			(737	)
Economic Factors		458			(76	)		67			(30	)		419			(78	)		129			(273	)		317
Production		-			-			-			-			-			-			-			-			-
December 31, 2025		12,817			10,062			41,149			44,459			108,487			10,837			39,115			32,051			131,185

 

Proved Plus Probable Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		37,248			27,341			89,547			44,489			198,625			27,197			113,133			85,680			258,957
Extensions		1,070			6,293			24,317			-			31,681			8,050			19,997			21,740			46,687
Technical Revisions		(1,706	)		698			3,492			-			2,484			2,055			(3,337	)		2,568			4,411
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions		(687	)		-			(403	)		-			(1,090	)		(99	)		(2,142	)		-			(1,546	)
Economic Factors		(491	)		(180	)		(1,436	)		(30	)		(2,137	)		(219	)		(1,701	)		(668	)		(2,751	)
Production		(2,900	)		(1,371	)		(15,608	)		-			(19,879	)		(1,328	)		(12,054	)		(3,951	)		(23,874	)
December 31, 2025		32,535			32,781			99,909			44,459			209,684			35,657			113,896			105,369			281,884

 

Notes:

(1) "Gross" reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Natural gas liquids includes condensate.
(3) Conventional natural gas includes associated, non-associated and solution gas.
(4) 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.

Reserves Reconciliation - Total Company

The following table reconciles the year-over-year changes in our gross reserves volumes by product type and reserves category. Please note that the data in the table may not add due to rounding.

Proved Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		23,604			168,200			55,357			-			247,161			91,923			74,789			339,775			408,177
Extensions		982			8,864			14,174			-			24,019			9,390			13,463			28,378			40,383
Technical Revisions		(664	)		406			6,488			-			6,231			1,562			1,854			2,590			8,533
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions (5)		(355	)		(135,842	)		(147	)		-			(136,344	)		(70,493	)		(1,442	)		(260,036	)		(250,417	)
Economic Factors		(950	)		(104	)		(1,503	)		-			(2,557	)		(140	)		(1,830	)		(395	)		(3,068	)
Production (6)		(2,900	)		(18,805	)		(15,608	)		-			(37,313	)		(7,423	)		(12,054	)		(36,994	)		(52,910	)
December 31, 2025		19,718			22,719			58,760			-			101,197			24,819			74,780			73,318			150,699

 

Probable Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		13,644			84,798			34,190			44,489			177,121			42,813			38,344			152,995			251,824
Extensions		89			(2,571	)		10,144			-			7,661			(1,340	)		6,534			(6,638	)		6,304
Technical Revisions		(1,042	)		291			(2,996	)		-			(3,747	)		493			(5,191	)		(22	)		(4,122	)
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions (5)		(332	)		(72,381	)		(256	)		-			(72,968	)		(31,051	)		(700	)		(114,010	)		(123,137	)
Economic Factors		458			(76	)		67			(30	)		419			(78	)		129			(273	)		317
Production (6)		-			-			-			-			-			-			-			-			-
December 31, 2025		12,817			10,062			41,149			44,459			108,487			10,837			39,115			32,051			131,185

 

Proved Plus Probable Reserves - Gross Volumes ⁽¹⁾ (Forecast Prices)

		Light and Medium Oil			Tight Oil			Heavy Oil			Bitumen			Total Oil			Natural Gas Liquids (2)			Conventional Natural Gas (3)			Shale Gas			Total (4)
		(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(MMcf)			(MMcf)			(Mboe)
December 31, 2024		37,248			252,997			89,547			44,489			424,281			134,736			113,133			492,770			660,001
Extensions		1,070			6,293			24,317			-			31,681			8,050			19,997			21,740			46,687
Technical Revisions		(1,706	)		698			3,492			-			2,484			2,055			(3,337	)		2,568			4,411
Acquisitions		-			-			-			-			-			-			-			-			-
Dispositions (5)		(687	)		(208,223	)		(403	)		-			(209,313	)		(101,544	)		(2,142	)		(374,047	)		(373,554	)
Economic Factors		(491	)		(180	)		(1,436	)		(30	)		(2,137	)		(219	)		(1,701	)		(668	)		(2,751	)
Production (6)		(2,900	)		(18,805	)		(15,608	)		-			(37,313	)		(7,423	)		(12,054	)		(36,994	)		(52,910	)
December 31, 2025		32,535			32,781			99,909			44,459			209,684			35,657			113,896			105,369			281,884

 

Notes:

(1) "Gross" reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
(2) Natural gas liquids includes condensate.
(3) Conventional natural gas includes associated, non-associated and solution gas.
(4) 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.
(5) Dispositions includes the sale of Baytex's U.S. assets on December 19, 2025.
(6) Production includes Baytex's U.S. assets to December 19, 2025.

Future Development Costs

The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the reserves categories noted below.

Future Development Costs ($ millions)	Proved Reserves	Proved Plus Probable Reserves
2026	359	442
2027	505	618
2028	511	694
2029	343	657
2030	146	248
Remainder	51	773
Total FDC undiscounted	1,915	3,432

 

Efficiency of Capital Development Program - Canada

Based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, the efficiency of our Canadian exploration and development program is summarized in the following table.

	2025	2024	2023	3 Year
Proved Developed Producing Reserves
Exploration and development expenditures ($ millions)	548.4	489.5	463.2	1,501.0
Reserves additions (MMboe) (1)	31.7	26.8	24.3	82.9
F&D costs ($/boe) (2)	17.28	18.25	19.06	18.12
Production replacement (3)	133%	115%	109%	119%
Recycle ratio (4)	2.0x	2.2x	2.0x	2.1x
Proved Reserves
Exploration and development expenditures ($ millions)	548.4	489.5	463.2	1,501.0
Change in future development costs ($ millions)	174.5	238.5	60.3	473.3
Total F&D capital ($ millions)	722.9	728.0	523.5	1,974.3
Reserves additions (MMboe) (1)	44.1	39.1	22.1	105.3
F&D costs ($/boe) (2)	16.39	18.60	23.70	18.74
Production replacement (3)	185%	167%	99%	151%
Recycle ratio (4)	2.1x	2.1x	1.6x	2.0x
Proved Plus Probable Reserves
Exploration and development expenditures ($ millions)	548.4	489.5	463.2	1,501.0
Change in future development costs ($ millions)	238.4	336.3	252.6	827.3
Total F&D capital ($ millions)	786.7	825.8	715.8	2,328.3
Reserves additions (MMboe) (1)	48.3	40.4	29.1	117.8
F&D costs ($/boe) (2)	16.27	20.43	24.61	19.76
Production replacement (3)	203%	173%	130%	169%
Recycle ratio (4)	2.1x	1.9x	1.6x	1.9x

 

Notes:

(1) Reserves additions includes extensions, technical revisions and economic factors.
(2) F&D costs are calculated on a per boe basis by dividing the aggregate of the change in FDC from the prior year for the particular reserves category and the costs incurred on E&D activities in the year by the change in reserves from the prior year for the reserve category.
(3) Production replacement is calculated by dividing reserves additions by annual production.
(4) Recycle ratio is calculated by dividing operating netback on a per boe basis by F&D costs.

Forecast Prices and Costs

The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values of future net revenues at December 31, 2025. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2026.

Year	WTI Crude Oil US$/bbl	Edmonton Light Crude Oil $/bbl	Western Canadian Select $/bbl	Henry Hub US$/MMbtu	AECO Spot $/MMbtu	Inflation Rate %/Yr	Exchange Rate $US/$Cdn
2025 act.	65.50	85.65	75.05	3.55	1.85	2.1	0.720
2026	59.92	77.54	65.13	3.74	3.00	-	0.730
2027	65.10	83.60	70.43	3.78	3.30	2.0	0.740
2028	70.28	90.17	76.90	3.85	3.49	2.0	0.740
2029	71.93	92.32	78.71	3.93	3.58	2.0	0.740
2030	73.37	94.17	80.29	4.01	3.65	2.0	0.740
2031	74.84	96.06	81.90	4.09	3.72	2.0	0.740
2032	76.34	97.98	83.53	4.17	3.80	2.0	0.740
2033	77.87	99.93	85.20	4.26	3.88	2.0	0.740
2034	79.42	101.93	86.91	4.34	3.95	2.0	0.740
2035	81.01	103.97	88.65	4.43	4.03	2.0	0.740
Thereafter	Escalation rate of 2.0%					2.0	0.740

 

Net Present Value of Reserves ⁽¹⁾ (Forecast Prices and Costs)

The following table summarizes the McDaniel estimate of the net present value before income taxes of the future net revenue attributable to our reserves.

Reserves at December 31, 2025 ($ millions, discounted at)	0%	5%	10%	15%
Proved developed producing	141	647	729	725
Proved developed non-producing	28	21	17	13
Proved undeveloped	1,204	801	538	359
Total proved	1,373	1,469	1,283	1,097
Probable	3,419	1,952	1,258	879
Total Proved Plus Probable (before tax)	4,792	3,420	2,541	1,976

 

Note:

(1) Includes abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities.

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 high return energy platform; we are committed to returning a significant portion of the net proceeds from the U.S. sale to shareholders, prioritizing share buybacks and maintaining an annual dividend of $0.09 per share; our expected 2026 full-year production volumes and exploration and development expenditures; our 2026 plan targets 3-6% production growth, and investment in long-term infrastructure, exploration and land to support future growth and inventory expansion; for 2026 in the Duvernay, our expected production growth and exit production rate, and plans related to drilling, completion and on-streaming of wells and plans related to our infrastructure build out; for 2026 in Heavy oil, our plans with respect to drilling and exploration activity including our intention to undertake two waterflood pilots at Peavine and target seven discrete zones in the Mannville at Lloydminster; for 2026 in the Viking our plans with respect to drilling and bringing wells on-stream; the expected release date of our year-results; future development costs, F&D and FD&A; forecast prices for oil and natural gas; forecast inflation and exchange rates; and the net present value before income taxes of the future net revenue attributable to our reserves. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future.

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

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices and the volatility of oil and natural gas prices and price differentials; 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 production guidance, exploration and development expenditures guidance; 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; 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; 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.

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 or around 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 intention to allocate cash to shareholder returns through a share buyback 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 operating netback, which is a financial measure that does not have any standardized meaning prescribed by IFRS. While this measure is commonly used in the oil and gas industry, our determination of this measure may not be comparable with calculations of similar measures presented by other reporting issuers.

Non-GAAP Financial Ratios

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.

Advisory Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with NI 51-101. Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2025, which is expected to be filed on March 4, 2026. Listed below are cautionary statements that are specifically required by NI 51-101:

• The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one boe (6 mcf/bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

• With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

• This press release contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.

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

 

This press release contains metrics commonly used in the oil and natural gas industry, such as "finding and development costs", "recycle ratio", "production replacement", and "reserves life index". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included in this press release to provide readers with additional measures to evaluate Baytex's performance, however, such measures are not reliable indicators of Baytex's future performance and future performance may not compare to Baytex's performance in previous periods and therefore such metrics should not be unduly relied upon.

Finding and development costs are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the prior year for the particular reserves category and the costs incurred on exploration and development activities in the year by the change in reserves from the prior year for the reserve category.

Recycle ratio is calculated by dividing operating netback on a per boe basis by finding and development costs for the particular reserves category.

Production replacement is calculated by dividing reserves additions, including extensions, technical revisions and economic factors for the particular reserves category, by annual production.

Reserves life index is calculated by taking the total quantity of reserves on a boe basis divided by annualized Q4/2025 production (boe/d) in Canada.

Notice to United States Readers

The petroleum and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" (each as defined in SEC rules). Canadian securities laws require oil and gas issuers disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves". Additionally, NI 51-101 defines "proved reserves" and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this press release may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.

In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments. The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments.

Moreover, Baytex has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. As a consequence of the foregoing, Baytex's reserve estimates and production volumes in this press release may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

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/282403

FAQ

What net cash position did Baytex (BTE) report entering 2026?

Baytex entered 2026 with approximately $857 million in net cash. According to the company, this follows repayment of credit facilities and tender offers that reduced senior notes, providing flexibility for buybacks.

How much did Baytex (BTE) repurchase in its share buyback through January 30, 2026?

Baytex repurchased 17.1 million common shares for $78 million through January 30, 2026. According to the company, this represents about 2.2% of shares outstanding at an average price of $4.55 per share.

What reserve gains did Baytex (BTE) report for Canada at year-end 2025?

Baytex reported Canadian reserve growth with PDP +12% (69 MMboe), 1P +15% (151 MMboe), and 2P +9% (282 MMboe). According to the company, these figures reflect 2025 development activity and McDaniel evaluation.

What is Baytex (BTE)’s 2026 production and capital guidance?

Baytex targets 67,000–69,000 boe/d production in 2026 with $550–$625 million of exploration and development spending. According to the company, the plan targets 3%–5% annual growth and infrastructure investment.

How has Baytex (BTE) hedged its oil exposure for early 2026?

For Q1 2026 Baytex hedged about 60% of net crude exposure with two-way collars (average floor US$60/bbl, ceiling US$67/bbl). According to the company, collars protect downside while capping some upside in early 2026.