Baytex Reports Third Quarter 2026 Results; Announces Increased 2026 Capital Plan, 2027 Guidance and Accelerated Three-Year Growth Outlook

Q: What production and capital spending does Baytex Energy expect in 2027?

Baytex expects average production of 76,000–79,000 boe/d in 2027, with exploration and development expenditures of $775–$850 million. The production range represents expected annual growth of 7%–11%. The company also targets approximately 83,000 boe/d in Q4/2027, representing 15% growth from Q4/2026.

Q: How much stock did Baytex Energy repurchase in the third quarter of 2026?

Baytex repurchased 24 million common shares for $149 million during Q3/2026, representing 3.4% of shares outstanding. It also paid a quarterly cash dividend of $16 million, or $0.0225 per share.

Q: When will Baytex Energy bring its remaining 2026 Duvernay wells onstream?

Baytex plans to bring the remaining six Duvernay wells onstream in 2027. Its expanded 2026 program calls for 19 wells drilled and 13 wells onstream. Shorter drilling and completion cycle times allow two additional wells to be drilled in Q4/2026.

Q: What early production did Baytex Energy report from its second 2026 Duvernay pad?

The five-well pad achieved average 30-day initial production of 1,489 boe/d per well, with 87% liquids. It was brought onstream in late August on northern Pembina acreage. The third pad, comprising four wells on the same acreage, was being brought onstream.

Baytex targets Duvernay production of 25,000 barrels of oil equivalent per day in the second half of 2028, one and a half years earlier.

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(Moderate)

Rhea-AI Sentiment

(Positive)How Sentiment works

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How Sentiment works How the balance works

Rhea-AI Summary

Baytex Energy (BTE) reported third-quarter production growth and increased its 2026 capital plan while outlining higher production targets through 2029.

Production reached 71,606 barrels of oil equivalent per day, up 5% from Q3/2025. Net income was $160 million, or $0.23 per basic share; adjusted funds flow was $332 million and free cash flow was $139 million. Baytex repurchased 24 million shares for $149 million and ended September with $522 million in net cash. Dollar amounts are Canadian unless identified otherwise.

Baytex expects 2026 development spending of $665 million, versus $625 million previously. Its 2027 plan calls for $775–$850 million of spending and production of 76,000–79,000 barrels of oil equivalent per day. The company targets 8%–10% annual production growth during 2027–2029, reaching approximately 92,000 barrels per day on an oil-equivalent basis in 2029, and a WTI US$50/bbl breakeven in 2027.

25 points · 0 major

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0 major · 11 points

Hollow bars mark forward-looking points. How the balance works

Positive

Moderate pointQ3 production of 71,606 boe/d, meaning barrels of oil equivalent daily, rose 5% from Q3/2025.
Moderate pointQ3 net income of $160.268 million exceeded $31.968 million a year earlier, but fell from $174.869 million sequentially.
Moderate pointQ3 Canadian petroleum and natural gas sales of $605.859 million exceeded $437.905 million a year earlier.
Moderate pointQ3 Canadian adjusted funds flow of $331.884 million increased from $151.847 million in Q3/2025.
Moderate point24 million shares repurchased for $149 million represented 3.4% of outstanding shares.
Moderate point. Forward-looking: it has not happened yet and may not happen.2027 production guidance of 76,000–79,000 boe/d implies company-expected annual growth of 7%–11%.
Moderate point. Forward-looking: it has not happened yet and may not happen.Q4/2027 production target of approximately 83,000 boe/d represents expected growth of 15% from Q4/2026.
Moderate point. Forward-looking: it has not happened yet and may not happen.2027–2029 production growth target of 8%–10% annually reaches approximately 92,000 boe/d in 2029.
Moderate point. Forward-looking: it has not happened yet and may not happen.WTI US$50/bbl breakeven is targeted for 2027 through improved costs and capital efficiency.
Moderate pointDuvernay Q3 production of 12,806 boe/d increased 26% from Q3/2025.
Moderate point. Forward-looking: it has not happened yet and may not happen.Duvernay production target of 25,000 boe/d moves to H2/2028, one and a half years earlier.
Moderate pointQ3 operating expense of $12.81/boe declined from $13.55/boe in Q3/2025.
Moderate pointQ3 net cash interest income of $0.540 million replaced $39.906 million of expense a year earlier.
Moderate pointNine-month net income of $267.811 million exceeded $253.108 million in 2025.
Moderate pointNine-month free cash flow of $268.256 million increased from $198.405 million in 2025.

10 minor points

Minor pointDuvernay drilling and completion costs of $930/ft of completed lateral declined 11% versus 2025.
Minor pointDuvernay acquisitions added 15,000 acres, increasing land holdings 16% in 2026 to 106,000 net acres.
Minor point. Forward-looking: it has not happened yet and may not happen.Over 15 years of Duvernay inventory is expected to maintain production once 25,000 boe/d is achieved.
Minor point. Forward-looking: it has not happened yet and may not happen.Two additional Duvernay wells are planned for Q4/2026, bringing planned 2026 drilling to 19 wells.
Minor point. Forward-looking: it has not happened yet and may not happen.Five additional Clearwater wells bring the planned 2026 drilling program to 31 wells.
Minor point. Forward-looking: it has not happened yet and may not happen.Enhanced oil recovery investment targets lower decline rates and sustaining capital needs; waterflood pilots are ongoing.
Minor point. Forward-looking: it has not happened yet and may not happen.Gemini thermal project advancement targets a financial investment decision in H2/2027.
Minor point. Forward-looking: it has not happened yet and may not happen.15% annual total shareholder return is the company target at a mid-cycle WTI price of US$70/bbl.
Minor pointQ3 transportation expense of $3.50/boe declined from $3.68/boe in Q3/2025.
Minor pointQ3 administrative expense of $1.89/boe declined from $2.52/boe in Q3/2025.

Negative

Moderate point. Forward-looking: it has not happened yet and may not happen.2026 exploration and development spending guidance of $665 million increased from $625 million.
Moderate point. Forward-looking: it has not happened yet and may not happen.2027 exploration and development spending of $775–$850 million is planned.
Moderate pointQ3 total adjusted funds flow of $331.884 million fell from $422.232 million, including discontinued operations, a year earlier.
Moderate pointQ3 operating cash flow of $283.034 million fell from $472.676 million in Q3/2025.
Moderate pointNine-month realized financial derivatives losses of $107.627 million exceeded $20.648 million in 2025.

6 minor points

Minor point. Forward-looking: it has not happened yet and may not happen.2027–2029 annual exploration and development spending is projected at approximately $800 million.
Minor pointQ3 free cash flow of $138.506 million fell from $142.688 million in Q3/2025.
Minor pointNet cash of $522.367 million declined from $566.286 million at June 30, 2026.
Minor pointQ3 cash share-based compensation of $9.166 million increased from $8.440 million in Q3/2025.
Minor pointNine-month total adjusted funds flow of $737.442 million declined from $1,253.021 million, including discontinued operations, in 2025.
Minor pointNine-month operating cash flow of $636.089 million declined from $1,258.305 million in 2025.

Key Figures

Third-quarter production: 71,606 boe/d Adjusted funds flow: $332 million ($0.48 per basic share) Free cash flow: $139 million ($0.20 per basic share) +5 more

Third-quarter production: 71,606 boe/d; Q3 2026; up 5% from Q3 2025
Adjusted funds flow: $332 million ($0.48 per basic share); Q3 2026
Free cash flow: $139 million ($0.20 per basic share); Q3 2026
Share repurchases: 24 million shares for $149 million; Q3 2026
Net cash: $522 million; At the end of Q3 2026
Exploration and development expenditures: $665 million; 2026 expected; increased from $625 million previously
Production guidance: 76,000 to 79,000 boe/d; 2027 average; 7% to 11% annual growth
Three-year production growth outlook: 8% to 10% annual growth to approximately 92,000 boe/d; 2027 to 2029; production level stated for 2029

Previous Earnings Reports

2 past events · Latest: Jul 30

Same Type 2 events

Jul 30
Earnings report

24h Move

+7.0%

Raised 2026 production guidance after production exceeded the prior range, with spending unchanged.
May 07
Earnings report

24h Move

-0.6%

Raised production guidance and expanded the three-year growth outlook alongside Q1 operating and financial results.

24h Move is the share-price change in the day after each event; other market factors may also have contributed.

Key Terms

sagd, waterflood, polymer flood, enhanced oil recovery, +1 more

5 terms

sagd technical

"Gemini thermal modular SAGD project"

A steam-assisted gravity drainage (SAGD) is an oil extraction method that uses injected steam to heat thick, heavy crude underground so it becomes flowable and can be pumped to the surface through a second, lower well — think of warming cold honey so it pours more easily. Investors care because SAGD projects can unlock large oil reserves but are capital- and energy-intensive, affecting production costs, profitability, and environmental liabilities such as higher greenhouse gas emissions.

waterflood technical

"Waterflood pilots at Peavine and Morinville are ongoing"

Waterflood is a method oil producers use to get more oil out of an underground reservoir by pumping water into the ground to push remaining oil toward production wells. It matters to investors because it can raise short‑term output, extend the life of a field and change the cost and value of reserves — like squeezing extra syrup from a sponge by flushing it with water, improving how much product a given asset can deliver.

polymer flood technical

"Lloydminster polymer flood projects are being developed"

A polymer flood is an enhanced oil recovery (EOR) technique in which water-soluble polymers are added to injection water to increase its viscosity and improve the sweep of oil through a reservoir. By making the injected fluid thicker, the polymer reduces channeling and fingering—uneven flow paths that leave oil behind—so a larger volume of the reservoir is pushed toward production wells; it is typically used after primary and secondary recovery stages and requires chemical compatibility with reservoir rock and fluids and economic evaluation of added costs and handling needs.

enhanced oil recovery technical

"Enhanced oil recovery investment to reduce decline rate"

Enhanced oil recovery is a set of techniques used to extract additional oil from a reservoir after the easy-to-reach portion has been produced, for example by injecting water, gas or chemicals to push or loosen remaining oil—like rinsing a sponge to get the last drops. It matters to investors because it can significantly increase a field’s output and cash flow, extend the life of assets, and change cost, environmental and regulatory risk profiles for an oil project.

ifrs financial

"does not have any standardized meaning prescribed by IFRS"

International Financial Reporting Standards (IFRS) are a set of common accounting rules used by many companies worldwide to prepare financial statements, so numbers like revenue, profit and assets are measured in the same way across borders. For investors, IFRS matters because it makes it easier to compare the financial health and performance of different companies—like using the same ruler to measure different objects—reducing surprises and helping informed investment decisions.

AI-generated analysis. How Rhea-AI works. Not financial advice.

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11/05/2026 - 05:03 PM EST

Calgary, Alberta--(Newsfile Corp. - November 5, 2026) - Baytex Energy Corp. (TSX: BTE) (NYSE: BTE) ("Baytex" or the "Company") reports its operating and financial results for the three and nine months ended September 30, 2026 (all amounts are in Canadian dollars unless otherwise noted).

"Third-quarter results were highlighted by strong safety performance, record Duvernay production and continued execution across our heavy oil portfolio," said Chad Lundberg, President and Chief Executive Officer. "With the strength of our business we are accelerating development across an opportunity-rich portfolio through the remainder of 2026 and into 2027. The updated three-year outlook is significantly enhanced through disciplined capital allocation, resulting in production growth increasing to 8% to 10% while an improved cost structure and capital efficiencies achieve the WTI US$50/bbl breakeven target in 2027."

Third Quarter Highlights

Delivered production of 71,606 boe/d (89% oil and NGL), up 5% from Q3/2025 and in line with the full-year plan.
Record Duvernay production of 12,806 boe/d (80% oil and NGL), up 26% compared to Q3/2025, and achieved drill and completion costs of $930/ft of completed lateral through efficiencies and cost savings - down 11% from 2025.
Completed tuck-in acquisitions adding 15,000 acres to core Duvernay, increasing total land position by 16% in 2026.
Generated adjusted funds flow⁽¹⁾ of $332 million ($0.48 per basic share) and cash flows from operating activities of $283 million ($0.41 per basic share).
Delivered free cash flow⁽²⁾ of $139 million ($0.20 per basic share) after exploration and development expenditures of $186 million and net income from continuing operations of $160 million ($0.23 per basic share).
Repurchased 24 million common shares (3.4% of shares outstanding) for $149 million and paid the quarterly cash dividend of $16 million ($0.0225 per share), while exiting the quarter with net cash⁽¹⁾ of $522 million.

(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and may not be comparable with the calculation of similar measures presented by other entities. Refer to Specified Financial Measures section in this press release for further information.

2027 Budget and Three-Year Plan Highlights

The updated outlook reflects improved capital efficiency, lower operating costs and a lower decline rate.

2026 exploration and development expenditures are now expected to be $665 million (up from $625 previously) with accelerated Duvernay, heavy oil and enhanced oil recovery development.
2027 production is expected to average 76,000 to 79,000 boe/d (7% to 11% annual growth) and ~83,000 boe/d in Q4/2027, reflecting 15% growth from Q4/2026, with exploration and development expenditures of $775 - $850 million.
Improved three-year outlook (2027 to 2029) reflects 8% - 10% annual production growth to ~92,000 boe/d in 2029, with annual exploration and development expenditures of approximately $800 million.
With improved costs and cycle times, Duvernay growth to 25,000 boe/d is achieved in the second half of 2028, one and a half years earlier than the previous, leaving over 15 years of hold flat inventory once 25,000 boe/d is achieved.
Enhanced oil recovery investment to reduce decline rate and sustaining capital requirements. Waterflood pilots at Peavine and Morinville are ongoing and Lloydminster polymer flood projects are being developed in 2026 and 2027.
The Gemini thermal modular SAGD project is being advanced towards a target financial investment decision in H2'2027, to further enhance the three-year plan.
Industry-leading financial position supports continued shareholder returns through production growth, share repurchases and a base dividend, targeting a 15% annual total shareholder return at a mid-cycle price of WTI US$70/bbl.

		Three Months Ended									Nine Months Ended
		September 30, 2026			June 30, 2026			September 30, 2025			September 30, 2026			September 30, 2025
FINANCIAL (thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales - Canada	$	605,859		$	639,943		$	437,905		$	1,698,756		$	1,303,092
Adjusted funds flow⁽¹⁾		331,884			254,433			422,232			737,442			1,253,021
Per share - basic		0.48			0.35			0.55			1.02			1.63
Per share - diluted		0.47			0.35			0.55			1.02			1.62
Free cash flow ⁽²⁾		138,506			128,045			142,688			268,256			198,405
Per share - basic		0.20			0.18			0.19			0.37			0.26
Per share - diluted		0.20			0.18			0.18			0.37			0.26
Cash flows from operating activities		283,034			230,852			472,676			636,089			1,258,305
Per share - basic		0.41			0.32			0.62			0.88			1.64
Per share - diluted		0.40			0.32			0.61			0.88			1.63
Net income		160,268			174,869			31,968			267,811			253,108
Per share - basic		0.23			0.24			0.04			0.37			0.33
Per share - diluted		0.23			0.24			0.04			0.37			0.33
Dividends declared		15,578			16,144			17,326			48,328			51,919
Per share		0.0225			0.0225			0.0225			0.0675			0.0675

Capital Expenditures
Exploration and development expenditures	$	186,429		$	122,242		$	270,364		$	453,683		$	1,031,993
Acquisitions and (divestitures)		11,827			(5,893	)		15,770			948			15,229
Total oil and natural gas capital expenditures	$	198,256		$	116,349		$	286,134		$	454,631		$	1,047,222

Net (Cash) Debt
Credit facilities	$	-		$	-		$	182,345		$	-		$	182,345
Long-term notes		91,011			91,107			1,855,605			91,011			1,855,605
Total debt ⁽³⁾		91,011			91,107			2,037,950			91,011			2,037,950
Working capital (surplus) deficiency ⁽²⁾		(613,378	)		(657,393	)		206,408			(613,378	)		206,408
Net (cash) debt⁽¹⁾	$	(522,367	)	$	(566,286	)	$	2,244,358		$	(522,367	)	$	2,244,358

Shares Outstanding - basic (thousands)
Weighted average		695,878			721,197			768,317			721,223			769,481
End of period		684,800			708,888			768,317			684,800			768,317

BENCHMARK PRICES
Crude oil
WTI (US$/bbl)	$	85.79		$	92.79		$	64.93		$	83.50		$	66.70
Edmonton par ($/bbl)		119.21			132.26			86.20			114.99			88.54
Edmonton par differential to WTI (US$/bbl)		(0.57	)		2.80			(2.35	)		(0.46	)		(3.40	)
WCS heavy oil ($/bbl)		100.59			108.16			75.14			95.95			77.80
WCS differential to WTI (US$/bbl)		(13.88	)		(14.62	)		(10.38	)		(14.21	)		(11.08	)
Natural gas
NYMEX (US$/MMbtu)	$	2.95		$	2.90		$	3.07		$	3.63		$	3.39
AECO ($/Mcf)		1.54			1.51			1.00			1.85			1.70

CAD/USD average exchange rate		1.3988			1.3836			1.3774			1.3847			1.3988

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

		Three Months Ended									Nine Months Ended
		September 30, 2026			June 30, 2026			September 30, 2025			September 30, 2026			September 30, 2025
OPERATING
Daily Production
Light oil and condensate (bbl/d)		14,891			12,236			12,605			12,998			11,852
Heavy oil (bbl/d)		44,341			46,349			45,269			45,197			42,825
NGL (bbl/d)		4,719			4,409			3,485			4,500			3,199
Total liquids (bbl/d)		63,951			62,994			61,359			62,695			57,876
Natural gas (Mcf/d)		45,926			49,502			40,961			48,529			42,335
Total Canada (boe/d) ⁽¹⁾		71,606			71,243			68,185			70,784			64,932
Discontinued operations (boe/d) ⁽¹⁾		-			-			82,765			-			82,839
Oil equivalent (boe/d)⁽¹⁾		71,606			71,243			150,950			70,784			147,771

Adjusted Funds Flow (thousands of Canadian dollars)
Total sales, net of blending and other expense ⁽²⁾	$	551,479		$	564,875		$	388,155		$	1,493,387		$	1,118,141
Royalties		(94,469	)		(90,378	)		(53,645	)		(236,436	)		(160,701	)
Operating expense		(84,377	)		(89,843	)		(84,994	)		(255,464	)		(248,609	)
Transportation expense		(23,078	)		(25,932	)		(23,060	)		(72,144	)		(62,383	)
Operating netback - Canada⁽²⁾	$	349,555		$	358,722		$	226,456		$	929,343		$	646,448
General and administrative expense		(12,445	)		(16,480	)		(15,824	)		(51,224	)		(50,985	)
Cash share-based compensation		(9,166	)		(4,317	)		(8,440	)		(31,496	)		(9,716	)
Net cash interest income (expense)		540			702			(39,906	)		3,996			(124,977	)
Realized financial derivatives gain (loss)		5,808			(84,146	)		(8,580	)		(107,627	)		(20,648	)
Other ⁽³⁾		(2,408	)		(48	)		(1,859	)		(4,464	)		(13,746	)
Adjusted funds flow - Canada ⁽⁴⁾	$	331,884		$	254,433		$	151,847		$	738,528		$	426,376
Adjusted funds flow - Discontinued operations ⁽⁴⁾		-			-			270,385			(1,086	)		826,645
Adjusted funds flow ⁽⁴⁾	$	331,884		$	254,433		$	422,232		$	737,442		$	1,253,021

Adjusted Funds Flow (per boe)
Total sales, net of blending and other expense ⁽²⁾	$	83.71		$	87.13		$	61.88		$	77.28		$	63.08
Royalties ⁽⁵⁾		(14.34	)		(13.94	)		(8.55	)		(12.24	)		(9.07	)
Operating expense ⁽⁵⁾		(12.81	)		(13.86	)		(13.55	)		(13.22	)		(14.02	)
Transportation expense ⁽⁵⁾		(3.50	)		(4.00	)		(3.68	)		(3.73	)		(3.52	)
Operating netback - Canada ⁽²⁾	$	53.06		$	55.33		$	36.10		$	48.09		$	36.47
General and administrative expense ⁽⁵⁾		(1.89	)		(2.54	)		(2.52	)		(2.65	)		(2.88	)
Cash share-based compensation⁽⁵⁾		(1.39	)		(0.66	)		(1.35	)		(1.63	)		(0.55	)
Net cash interest income (expense) ⁽⁵⁾		0.08			0.11			(6.36	)		0.21			(7.05	)
Realized financial derivatives gain (loss) ⁽⁵⁾		0.88			(12.98	)		(1.37	)		(5.57	)		(1.16	)
Other ⁽³⁾⁽⁵⁾		(0.37	)		(0.01	)		(0.30	)		(0.23	)		(0.78	)
Adjusted funds flow - Canada ⁽⁴⁾	$	50.37		$	39.25		$	24.20		$	38.22		$	24.05
Adjusted funds flow - Discontinued operations ⁽⁴⁾		-			-			35.51			-			36.55
Adjusted funds flow ⁽⁴⁾	$	50.37		$	39.25		$	30.40		$	38.16		$	31.06

Notes:
(1) Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.
(3) Other is comprised of realized foreign exchange gain or loss, cash other income or expense and current income tax expense or recovery. Refer to the Q3/2026 MD&A for further information on these amounts.
(4) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5) Calculated as royalties, operating expense, transportation expense, general and administrative expense, cash share-based compensation, net cash interest income or expense, realized financial derivatives gain or loss, or other, divided by barrels of oil equivalent production volume for the applicable period for continuing operations.

Third Quarter 2026 Results

Q3 Production and Capital Consistent with Full-Year Plan

Third-quarter production of 71,606 boe/d (89% oil and NGL) and exploration and development expenditures of $186 million were in line with our full-year plan.

Strong realized pricing and efficient execution of the capital program generated adjusted funds flow⁽¹⁾of $332 million ($0.48 per basic share) and free cash flow⁽²⁾ of $139 million ($0.20 per basic share). Net income was $160 million ($0.23 per basic share).

(1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(2) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this press release for further information.

Duvernay

The second Duvernay pad of 2026 (five wells) was brought onstream in late August. This pad generated average 30-day initial production rates of 1,489 boe/d per well, 87% liquids (973 bbl/d of oil, 317 bbl/d of NGLs and 1,190 mcf/d of natural gas). The third Duvernay pad of 2026 (four wells) is currently being brought onstream. Both pads are on our northern Pembina acreage.

Improved drilling and completions performance has shortened cycle times and reduced costs, contributing to a lower corporate breakeven and enhanced free cash flow generation. Drill and completion costs for 2026 full-length wells of $930/ft of completed lateral surpassed budget expectations and improved by 11% relative to 2025. The resulting cycle time improvement allows for two additional drills in Q4/2026, increasing total wells drilled in 2026 to 19 with 13 wells onstream. The remaining 6 wells will be brought onstream in 2027.

Tuck-in acquisitions completed during the year have increased our Duvernay land holdings to 106,000 net acres, an increase of 16%.

Heavy Oil

Five drill rigs ran in Q3/2026 with 25.5 net wells onstream; 9.0 net Clearwater wells at Peavine, 5.6 net wells at Peace River and 10.9 net wells at Lloydminster.

At Peavine, strong new well performance continued with wells brought onstream during the quarter establishing an average 30-day initial production rate of 408 bbl/d per well. One rig has been active on the Peavine lands in 2026. As a result of efficient operations, five wells have been added to the fourth quarter drilling program for a total of 31 wells planned in the Clearwater for 2026.

At Lloydminster, two rigs focused on the Mannville stack in northeast Alberta were running during the third quarter. Six upper and lower Waseca multi-lateral horizontal wells were brought onstream and established an average 30-day initial production rate of 186 bbl/d per well. One step-out circulation string horizontal trial was brought onstream from the GP formation and established a 30-day initial production rate of 165 bbl/d.

One rig has been active at Peace River since mid-July. Five Bluesky wells brought onstream during the third quarter established average 30-day initial production rates of 225 bbl/d per well. A total of 13.6 net wells are planned on Peace River lands in 2026, including four additional drills added to the fourth quarter program with efficiency gains to-date.

There is one rig drilling at Morinville with plans to bring 4.3 net Clearwater equivalent multi-lateral horizontal wells onstream during Q4/2026.

A total of 108.9 net heavy oil wells will be brought onstream in 2026.

Polymer Flood Development at Lloydminster and Waterflood Pilots on Injection

The expanded fourth-quarter program includes $13 million for additional polymer flood development at Lloydminster. This project is expected to be on production in Q2/2027.

At Peavine, water injection is underway across two pilot areas with five patterns currently on injection at expected rates and a sixth expected to be on injection in Q4/2026, a response is expected by mid-2027. In addition, a waterflood pilot is underway at Morinville, targeting the Rex formation (a Clearwater equivalent), with drilling completed and injection scheduled to begin in Q4/2026.

Current primary development at Peavine and Morinville maintains optionality for future waterflood development. Successful polymer floods and waterflood will moderate corporate production decline and lower sustaining capital requirements.

Portfolio Optimization Transactions

Several acquisition and divestiture transactions were completed for net consideration of $12 million. Total Duvernay land holdings have increased by 16% to 106,000 net acres through acquisitions contiguous to the core Pembina position. A tuck-in acquisition was completed in northeast Alberta, adding approximately 200 bbl/d of heavy oil production and five sections of multi-zone potential Mannville lands. High operating cost heavy oil assets producing approximately 275 bbl/d were sold for proceeds of $7 million.

Delivering Shareholder Returns

A total of $165 million was returned to shareholders during the third quarter, as 24 million common shares repurchased for $149 million, at an average price of $6.18 per share, and a quarterly cash dividend of $16 million ($0.0225 per share) was paid. Since the disposition of the U.S. business in December 2025 and through October 30, 2026, 91.7 million common shares have been repurchased for $527.9 million, representing 12% of shares outstanding, at an average price of $5.75 per share.

A Normal Course Issuer Bid ("NCIB") is in place with the Toronto Stock Exchange and allows the purchase of up to 70.9 million common shares (10% of Baytex's public float) during the 12-month period commencing July 2, 2026 and ending July 1, 2027.

Quarterly Dividend

The Board of Directors declared a quarterly cash dividend of $0.0225 per share, payable January 4, 2027 to shareholders of record on December 15, 2026.

Outlook: Accelerated Growth, Investing in Organic Opportunities, Delivering Shareholder Returns

Accelerated 2026 Development

2026 exploration and development expenditures of $665 million reflect accelerated Duvernay and heavy oil development along with expanded polymer flood development at Lloydminster. The incremental exploration and development expenditures are not expected to contribute to production in 2026. Annual production guidance remains 71,000 boe/d which equates to Q4/2026 production of 72,000 boe/d.

Higher benchmark prices have resulted in updated annual guidance for the average royalty rate to approximately 16% (previously 15%). Updated operating costs of approximately $13.30/boe (previously $13.75 - $14.25) reflects operating cost savings achieved in 2026 and increased production. Transportation costs are expected to be approximately $3.75/boe for 2026 (previously $3.40 - $3.60/boe).

The following table compares our 2026 revised annual guidance to our previously announced guidance.

	2026 Annual Guidance	Revised Annual Guidance
Exploration and development expenditures ⁽¹⁾	~ $625 million	~ $665 million
Production (boe/d)⁽²⁾	~ 71,000	No change

Expenses:
Average royalty rate ⁽³⁾⁽⁴⁾	15%	16 %
Operating⁽³⁾⁽⁵⁾	$13.75 - $14.25/boe	$13.30/boe
Transportation⁽³⁾⁽⁵⁾	$3.40 - $3.60/boe	$3.75/boe

Leasing expenditures⁽³⁾	$7 million	No change
Asset retirement obligations settled⁽³⁾	$20 million	No change

(1) As announced on May 7, 2026.
(2) As announced July 30, 2026.
(3) As announced on December 22, 2025.
(4) 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.
(5) Calculated as royalties, operating expense, or transportation expense divided by barrels of oil equivalent production volume for the applicable period.

2027 Capital Program Driving 7% - 11% Production Growth

For 2027, exploration and development expenditures guidance of $775 million to $850 million is expected to generate annual production of 76,000 to 79,000 boe/d (7% to 11% growth) while also advancing medium and long-term opportunities within the portfolio. The plan achieves the sustaining capital breakeven target of WTI US$50/bbl in 2027, reflecting an improved cost structure and capital efficiency. The 2027 capital program also includes investments in long-term infrastructure and enhanced oil recovery projects, delineation of heavy oil inventory and advances the Gemini thermal project. Approximately 60% of the program is allocated to the second half of the year.

Initially, $150 million has been allocated to share repurchases under the NCIB in 2027 with the flexibility to adjust depending on market conditions. The annual dividend is expected to be maintained at $0.09 per share ($0.0225 per share paid quarterly), subject to Board of Directors approval.

Three-Year Growth Outlook with Improving Profitability

The updated three-year outlook (2027 to 2029) targets 8% - 10% annual production growth with improving profitability through a lower cost structure, reduced corporate declines, lower sustaining capital requirements and a lower corporate breakeven price. These improvements support stronger free cash flow generation. High-impact organic opportunities which are additive to this outlook, including Clearwater waterflood and thermal, are also being advanced. Average annual exploration and development expenditures of approximately $800 million are expected to result in production of 92,000 boe/d in 2029.

A projected net cash financial position through the outlook period at a mid-cycle price of WTI US$70/bbl, supports the 15% annual total shareholder return target through production growth, share repurchases and the base dividend.

Duvernay

The transition to full-scale commercial development in the Duvernay will be completed with plans to bring 21 wells onstream in 2027 compared to 13 wells onstream in 2026. This pace of activity represents an optimized single-rig drilling program designed to deliver production growth of 64%, average annual production of approximately 18,000 boe/d and a targeted fourth quarter average production rate of 22,000 to 23,000 boe/d. Approximately 40% of the 2027 capital program is allocated to the Duvernay. Infrastructure investments include infield gathering systems, anchor oil batteries, fluid handling, and water infrastructure.

Operating the Duvernay to maximize efficiency is a priority in the three-year plan. The single-rig drilling program is expected to generate 35% annual production growth and produce 25,000 boe/d production in the second half of 2028, one and a half years ahead of the prior plan. Consistent with our prior three-year plan, infrastructure spending for full field development on water handling, anchor batteries, and gathering systems is still expected to be completed by year-end 2028.

Viking

The capital program includes continued light oil development in the Viking with plans to bring 66.1 net wells on production in 2027 with approximately 70 net wells drilled per year through the three-year plan. The Viking is highly repeatable and has strong operating netbacks, contributing meaningful free cash flow within our portfolio.

Heavy Oil

The 2027 heavy oil development program is focused on efficient development, advancing a deep inventory set and further investment in enhanced oil recovery. A total of 130 heavy oil wells are expected to be brought onstream, supporting modest production growth to approximately 48,000 boe/d while generating strong free cash flow.

The 2027 plan includes five rigs running across the heavy oil fairway. At Peavine, multi-lateral horizontal Clearwater development is expected to bring 32 wells onstream while leaving optionality for waterflood development. Development at Lloydminster, primarily within the Mannville stack in northeast Alberta, includes plans to bring 78 wells onstream using a combination of open-hole, multi-lateral and circulation string wells. Multi-lateral horizontal drilling at Peace River will target the Bluesky and Spirit River formations with plans to bring approximately 20 wells onstream.

The three-year heavy oil development plan focuses on the Clearwater at Peavine, the Mannville stack in northeast Alberta, and Spirit River and Bluesky at Peace River. Active development across the heavy oil portfolio is expected to deliver modest production growth and meaningful asset level free cash flow. Exploration activity, including targeted appraisal wells and seismic programs, are planned to expand inventory and support future development.

Enhanced Oil Recovery and Modular SAGD

In 2027, $35 million is allocated to expanded polymer flood development at Lloydminster. Investment in enhanced oil recovery will continue through the three-year plan with the goal of moderating decline and lower sustaining capital requirements.

Gemini thermal has been in the portfolio for more than a decade. A successful pilot was completed in 2014 and there is regulatory approval in place for a 5,000 bbl/d first phase of development. The 2027 capital plan includes $10 million to advance technical characterization of the reservoir and for engineering and design of a central processing facility. The three-year plan will be updated to reflect incremental development plans for Gemini thermal following a final investment decision, targeted for the second half of 2027.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and nine months ended September 30, 2026, and the related Management's Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR+ at www.sedarplus.ca and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Tomorrow
10:00 a.m. AT (11:00 a.m. ET)

Baytex will host a conference call tomorrow, November 6, 2026, starting at 10:00am AT (11:00am ET). To participate, please dial toll free in North America 1-833-821-2925 or international 1-647-846-2449. Alternatively, to listen to the conference call online, please enter https://event.choruscall.com/mediaframe/webcast.html?webcastid=jGHCxsPD in your web browser. To register, visit our website at https://www.baytexenergy.com/investors/events-presentations.

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: annual production growth of 8 to 10% in the three year outlook; the timing to achieve a break-even target of US$50/bbl WTI; expected exploration and development expenditures for 2026 through 2029 and production for 2026, 2027, Q4/2027 and 2029 and associated comparative growth rates; that Duvernay production will be 25,000 per day by H2/2028 and the amount of hold flat inventory remaining; plans for waterflood and polymer flood development in 2026 and 2027 and potential final investment decision on our Gemini project in H2/2027; anticipated benefits of our Gemini project including our expectations that SAGD will expand our resource with long-life low decline production; targeted annual total shareholder return of 15% at US$70 WTI; plans with respect to wells to be drilled or brought on-stream in Duvernay and Heavy Oil; our 2026 guidance, including exploration and development expenditures, production, average royalty rate, and expenses (operating and transportation); the timing and allocation of our 2027 exploration and development spending, the initial allocation of $150 million to the NCIB in 2027 and expectations that the quarterly dividend will be maintained; Baytex's 3-year outlook including production growth rate, impact on profitability, cost structure, declines, sustaining capital requirements, breakevens, and free cash flow generation; through the outlook, the projected net cash position and 15% total shareholder return through growth, share buybacks and a dividend; 2027 plans with respect to, production growth from heavy oil and the Duvernay, expectations regarding free cash flow generation from heavy oil, Baytex's net cash position and expectations for excess free cash flow; for 2027 and the three year outlook, planned and potential exploration, development and production activities, including production rates, number of wells expected to be drilled and brought on stream in certain areas, spending on infrastructure, enhanced oil recovery and modular SAGD. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future.

These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy crude oil prices; well production rates and reserve volumes; success obtained drilling new wells; the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; our ability to successfully market oil and natural gas; that we will have sufficient financial resources in the future to pursue our development plans and provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices (including as a result of tariffs); risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum products; 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 a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Any decision to pay dividends on the Common Shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith) or acquire Common Shares pursuant to a share buyback (including through the current Normal Course Issuer Bid) will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely.

These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2025, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings. The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations and such information may not be appropriate for other purposes.

This press release contains information that may be considered a financial outlook under applicable securities laws about the Company's potential financial position, including, but not limited to: our 2026 guidance for development expenditures; that we can maintain a net cash position and target a 15% annual total shareholder return through our 3 year outlook; and our intentions regarding the allocation of $150 million to our NCIB in 2027 and the intent to maintain a quarterly 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 Company and the resulting financial results will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about the Company's potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.

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

Specified Financial Measures

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

Non-GAAP Financial Measures

Total sales, net of blending and other expense - Canada

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

Operating netback - Canada

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

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

		Three Months Ended									Nine Months Ended
($ thousands)		September 30, 2026			June 30, 2026			September 30, 2025			September 30, 2026			September 30, 2025
Petroleum and natural gas sales	$	605,859		$	639,943		$	437,905		$	1,698,756		$	1,303,092
Blending and other expense		(54,380	)		(75,068	)		(49,750	)		(205,369	)		(184,951	)
Total sales, net of blending and other expense	$	551,479		$	564,875		$	388,155		$	1,493,387		$	1,118,141
Royalties		(94,469	)		(90,378	)		(53,645	)		(236,436	)		(160,701	)
Operating expense		(84,377	)		(89,843	)		(84,994	)		(255,464	)		(248,609	)
Transportation expense		(23,078	)		(25,932	)		(23,060	)		(72,144	)		(62,383	)
Operating netback - Canada	$	349,555		$	358,722		$	226,456		$	929,343		$	646,448

Free cash flow

We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties, and payments on lease obligations.

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

		Three Months Ended									Nine Months Ended
($ thousands)		September 30, 2026			June 30, 2026			September 30, 2025			September 30, 2026			September 30, 2025
Cash flows from operating activities	$	283,034		$	230,852		$	472,676		$	636,089		$	1,258,305
Change in non-cash working capital		44,330			21,648			(55,961	)		92,281			(17,885	)
Additions to exploration and evaluation assets		(1,107	)		-			-			(2,844	)		(930	)
Additions to oil and gas properties		(185,322	)		(122,242	)		(270,364	)		(450,839	)		(1,031,063	)
Payments on lease obligations		(2,429	)		(2,213	)		(3,663	)		(6,431	)		(10,022	)
Free cash flow	$	138,506		$	128,045		$	142,688		$	268,256		$	198,405

Working capital (surplus) deficiency

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

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

		As at
($ thousands)		September 30, 2026			June 30, 2026			September 30, 2025
Cash	$	(652,602	)	$	(720,337	)	$	(10,417	)
Trade receivables		(244,000	)		(188,260	)		(324,287	)
Prepaids and other assets		(58,498	)		(60,714	)		(75,100	)
Inventory		(1,624	)		(8,756	)		-
Trade payables		289,861			275,032			554,057
Share-based compensation liability		37,907			29,498			24,666
Dividends payable		15,578			16,144			17,326
Other long-term liabilities		-			-			20,163
Working capital (surplus) deficiency	$	(613,378	)	$	(657,393	)	$	206,408

Non-GAAP Financial Ratios

Total sales, net of blending and other expense per boe

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

Operating netback per boe

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

Capital Management Measures

Net (cash) debt

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

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

		As at
($ thousands)		September 30, 2026			June 30, 2026			September 30, 2025
Credit facilities	$	-		$	-		$	166,841
Unamortized debt issuance costs - Credit facilities ⁽¹⁾		-			-			15,504
Long-term notes		89,201			89,229			1,815,230
Unamortized debt issuance costs - Long-term notes ⁽¹⁾		1,810			1,878			40,375
Trade payables		289,861			275,032			554,057
Share-based compensation liability		37,907			29,498			24,666
Dividends payable		15,578			16,144			17,326
Other long-term liabilities		-			-			20,163
Cash		(652,602	)		(720,337	)		(10,417	)
Trade receivables		(244,000	)		(188,260	)		(324,287	)
Prepaids and other assets		(58,498	)		(60,714	)		(75,100	)
Inventory		(1,624	)		(8,756	)		-
Net (cash) debt	$	(522,367	)	$	(566,286	)	$	2,244,358

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

Adjusted funds flow

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

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

		Three Months Ended							Nine Months Ended
($ thousands)		September 30, 2026		June 30, 2026		September 30, 2025			September 30, 2026		September 30, 2025
Cash flow from operating activities	$	283,034	$	230,852	$	472,676		$	636,089	$	1,258,305
Change in non-cash working capital		44,330		21,648		(55,961	)		92,281		(17,885	)
Asset retirement obligations settled		4,520		1,933		5,517			9,072		12,601
Adjusted funds flow	$	331,884	$	254,433	$	422,232		$	737,442	$	1,253,021

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

This press release discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers to Baytex's proved, probable and unbooked locations. Proved locations and probable locations account for drilling locations in our inventory that have associated proved and/or probable reserves. Unbooked locations are internal estimates based on our acreage and an assumption as to the number of wells that can be drilled per section based on preliminary development plans. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Unbooked locations do not have attributed reserves. Risked unbooked locations are based on the chance of commerciality, which incorporates contingencies including geologic uncertainty, economic status, regulatory approvals, infrastructure and market considerations, timing of production and development. There is no certainty that we will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The wells developed will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relatively close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that 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 risked 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 risked unbooked locations.

Throughout this press release, "oil and NGL" refers to heavy crude oil, bitumen, light and medium crude oil, tight oil, condensate and natural gas liquids ("NGL") product types as defined by NI 51-101. The following table shows Baytex's disaggregated production volumes for the three and nine months ended September 30, 2026 and 2025. The NI 51-101 product types are included as follows: "Heavy Crude Oil" - heavy crude oil and bitumen, "Light and Medium Crude Oil" - light and medium crude oil, tight oil and condensate, "NGL" - natural gas liquids and "Natural Gas" - shale gas and conventional natural gas.

	Three Months Ended September 30, 2026					Three Months Ended September 30, 2025
	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada - Heavy
Peace River	9,699	11	19	7,871	11,040	9,900	13	38	10,079	11,631
Lloydminster	15,603	6	-	1,185	15,807	13,260	26	1	1,224	13,491
Peavine	18,581	-	-	-	18,581	20,953	-	-	-	20,953
Remaining Properties	426	1	-	437	500	1,094	3	-	648	1,205

Canada - Light
Viking	28	8,243	251	8,453	9,931	56	7,500	210	9,832	9,404
Duvernay	-	6,392	3,792	15,730	12,806	-	4,824	3,068	13,758	10,185
Remaining Properties	4	238	657	12,250	2,941	6	239	168	5,420	1,316

Total Canada	44,341	14,891	4,719	45,926	71,606	45,269	12,605	3,485	40,961	68,185

United States
Eagle Ford	-	-	-	-	-	-	52,330	15,582	89,115	82,765

Total	44,341	14,891	4,719	45,926	71,606	45,269	64,935	19,067	130,076	150,950


	Nine Months Ended September 30, 2026					Nine Months Ended September 30, 2025
	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada - Heavy
Peace River	9,674	8	22	8,270	11,082	9,805	13	30	9,850	11,490
Lloydminster	15,718	6	-	1,210	15,926	12,362	20	-	1,188	12,580
Peavine	19,232	-	-	-	19,232	19,455	-	-	-	19,455
Remaining Properties	544	2	-	586	644	1,113	2	-	687	1,229

Canada - Light
Viking	23	8,185	254	9,279	10,009	85	8,015	187	10,302	10,004
Duvernay	-	4,480	3,434	13,437	10,154	-	3,478	2,488	9,485	7,547
Remaining Properties	6	317	790	15,747	3,737	5	324	494	10,823	2,627

Total Canada	45,197	12,998	4,500	48,529	70,784	42,825	11,852	3,199	42,335	64,932

United States
Eagle Ford	-	-	-	-	-	-	51,284	16,154	92,407	82,839

Total	45,197	12,998	4,500	48,529	70,784	42,825	63,136	19,353	134,742	147,771

Baytex Energy Corp.

Baytex Energy Corp. is a Calgary-based energy company committed to driving shareholder value through disciplined execution. The Company operates in the Western Canadian Sedimentary Basin, featuring the Duvernay and heavy oil plays in Alberta and Saskatchewan. Baytex's common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit our website at www.baytexenergy.com or contact:

Chad Lundberg	Chad Kalmakoff	Chris Lessoway
President and Chief Executive Officer	Chief Financial Officer	Vice President, Finance and Treasurer
Baytex Energy Corp.	Baytex Energy Corp.	Baytex Energy Corp.

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

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FAQ

AI-generated questions and answers. How Rhea-AI works. Not financial advice.

What production and capital spending does Baytex Energy expect in 2027?

Baytex expects average production of 76,000–79,000 boe/d in 2027, with exploration and development expenditures of $775–$850 million. The production range represents expected annual growth of 7%–11%. The company also targets approximately 83,000 boe/d in Q4/2027, representing 15% growth from Q4/2026.

How much stock did Baytex Energy repurchase in the third quarter of 2026?

Baytex repurchased 24 million common shares for $149 million during Q3/2026, representing 3.4% of shares outstanding. It also paid a quarterly cash dividend of $16 million, or $0.0225 per share.

When will Baytex Energy bring its remaining 2026 Duvernay wells onstream?

Baytex plans to bring the remaining six Duvernay wells onstream in 2027. Its expanded 2026 program calls for 19 wells drilled and 13 wells onstream. Shorter drilling and completion cycle times allow two additional wells to be drilled in Q4/2026.

What early production did Baytex Energy report from its second 2026 Duvernay pad?

The five-well pad achieved average 30-day initial production of 1,489 boe/d per well, with 87% liquids. It was brought onstream in late August on northern Pembina acreage. The third pad, comprising four wells on the same acreage, was being brought onstream.

Baytex Reports Third Quarter 2026 Results; Announces Increased 2026 Capital Plan, 2027 Guidance and Accelerated Three-Year Growth Outlook