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Baytex Energy Corp.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2026 and 2025

Dated November 5, 2026

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2026. This information is provided as of November 5, 2026. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and nine months ended September 30, 2026 ("Q3/2026" and "YTD 2026") have been compared with the results for the three and nine months ended September 30, 2025 ("Q3/2025" and "YTD 2025"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2026, its audited comparative consolidated financial statements for the years ended December 31, 2025 and 2024, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2025. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

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

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

BAYTEX ENERGY CORP.

Baytex Energy Corp. is a Canadian oil and natural gas company based in Calgary, Alberta. Baytex has oil and natural gas assets in Western Canada primarily comprised of heavy oil assets in Peace River and Lloydminster along with Duvernay and Viking light oil assets.

PRESENTATION OF CONTINUING AND DISCONTINUED OPERATIONS

In Q4/2025, we completed the disposition of the operated and non-operated Eagle Ford assets which comprised the U.S. operating segment. This operating segment represented a geographical area of operations and its results are classified as discontinued operations. The financial results for the three and nine months ended September 30, 2026 and September 30, 2025 are disaggregated between continuing and discontinued operations in the table below.

In this MD&A, references to "Canada", "Canadian operations" and similar terms refer to the continuing operations of Baytex Energy Corp. and references to "U.S. operations", "Eagle Ford" and similar terms refer to the discontinued operations.


	Three Months Ended September 30
	2026						2025
	Continuing		Discontinued		Total		Continuing		Discontinued		Total

Revenue, net of royalties
Petroleum and natural gas sales	$	605,859	$	—	$	605,859	$	437,905	$	489,743	$	927,648
Royalties	(94,469)		—		(94,469)		(53,645)		(127,585)		(181,230)
	511,390		—		511,390		384,260		362,158		746,418

Expenses
Operating	84,377		—		84,377		84,994		75,290		160,284
Transportation	23,078		—		23,078		23,060		12,235		35,295
Blending and other	54,380		—		54,380		49,750		—		49,750
General and administrative	12,445		—		12,445		15,824		4,912		20,736

Exploration and evaluation	50		—		50		127		—		127
Depletion and depreciation	131,138		—		131,138		126,218		202,875		329,093

Share-based compensation	9,166		—		9,166		8,440		2,297		10,737
Net financing and interest expense	4,669		—		4,669		47,062		5,374		52,436
Financial derivatives (gain) loss	(10,880)		—		(10,880)		5,039		—		5,039
Foreign exchange loss	368		—		368		36,921		—		36,921
Gain on dispositions	(7,906)		—		(7,906)		(1,591)		—		(1,591)
Other expense (income)	1,883		—		1,883		702		(119)		583
	302,768		—		302,768		396,546		302,864		699,410
Net income (loss) before income taxes	208,622		—		208,622		(12,286)		59,294		47,008

Income taxes
Current income tax expense (recovery)	25		—		25		1,076		(6,809)		(5,733)
Deferred income tax expense	48,329		—		48,329		15,089		5,684		20,773
	48,354		—		48,354		16,165		(1,125)		15,040
Net income (loss)	$	160,268	$	—	$	160,268	$	(28,451)	$	60,419	$	31,968


	Nine Months Ended September 30
	2026						2025
	Continuing		Discontinued		Total		Continuing		Discontinued		Total

Revenue, net of royalties
Petroleum and natural gas sales	$	1,698,756	$	—	$	1,698,756	$	1,303,092	$	1,510,265	$	2,813,357
Royalties	(236,436)		—		(236,436)		(160,701)		(405,856)		(566,557)
	1,462,320		—		1,462,320		1,142,391		1,104,409		2,246,800

Expenses
Operating	255,464		—		255,464		248,609		220,398		469,007
Transportation	72,144		—		72,144		62,383		36,331		98,714
Blending and other	205,369		—		205,369		184,951		—		184,951
General and administrative	51,224		—		51,224		50,985		17,577		68,562

Exploration and evaluation	1,525		—		1,525		691		—		691
Depletion and depreciation	383,773		—		383,773		360,965		610,210		971,175

Share-based compensation	36,353		—		36,353		9,716		3,339		13,055
Net financing and interest expense	12,282		—		12,282		144,498		14,897		159,395
Financial derivatives loss	118,433		—		118,433		35,995		—		35,995
Foreign exchange loss (gain)	1,986		—		1,986		(67,543)		—		(67,543)
Gain on dispositions	(10,184)		(19,720)		(29,904)		(1,028)		—		(1,028)
Other expense (income)	5,644		—		5,644		5,801		(3,344)		2,457
	1,134,013		(19,720)		1,114,293		1,036,023		899,408		1,935,431
Net income before income taxes	328,307		19,720		348,027		106,368		205,001		311,369

Income taxes
Current income tax expense (recovery)	25		1,086		1,111		8,061		(7,095)		966
Deferred income tax expense	79,105		—		79,105		41,095		16,200		57,295
	79,130		1,086		80,216		49,156		9,105		58,261
Net income	$	249,177	$	18,634	$	267,811	$	57,212	$	195,896	$	253,108

THIRD QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q3/2026. Production of 71,606 boe/d and exploration and development expenditures of $186.4 million for Q3/2026 were consistent with our full-year plan. During the quarter, we brought 46.9 net wells on production and continued to advance our 2026 development program, which is focused on our heavy oil and Duvernay properties.

We generated adjusted funds flow(1) of $331.9 million and cash flows from operating activities of $283.0 million, compared to adjusted funds flow from continuing operations of $151.8 million and cash flows from operating activities from continuing operations of $178.9 million in Q3/2025.

We generated free cash flow(2) of $138.5 million in Q3/2026, reflecting the disciplined execution of our exploration and development programs while maintaining a strong net cash(1) position of $522.4 million at period end. During the quarter, we repurchased 24.1 million common shares for $152.0 million under our normal course issuer bid and declared a quarterly dividend of $0.0225 per share.

Net cash(1) was $522.4 million at September 30, 2026 compared to $765.8 million at December 31, 2025. The change reflects free cash flow generated during the period offset by shareholder returns, including share repurchases and dividends.

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

GUIDANCE

We continue to execute our 2026 plan and anticipate full year 2026 production of approximately 71,000 boe/d. Guidance for exploration and development expenditures, average royalty rate, operating expense, and transportation expense has been revised to reflect year-to-date results and our expectation for the fourth quarter.

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


	2026 Annual Guidance	Revised Annual Guidance		YTD 2026 Results
Exploration and development expenditures (1)	~ $625 million	~ $665 million		$453.7 million
Production (boe/d) (2)	~ 71,000	No change		70,784

Expenses:
Average royalty rate (3)(4)	15%	16	%	15.8	%
Operating (3)(5)	$13.75 - $14.25/boe	$13.30/boe		$13.22/boe
Transportation (3)(5)	$3.40 - $3.60/boe	$3.75/boe		$3.73/boe




Leasing expenditures (3)	$7 million	No change		$6.4 million
Asset retirement obligations settled (3)	$20 million	No change		$9.1 million

(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 MD&A for further information.

(5)Refer to the Operating Expense and Transportation Expense sections of this MD&A for description of the composition of these measures.

RESULTS OF OPERATIONS

Production


	Three Months Ended September 30						Nine Months Ended September 30
	2026		2025		Change		2026		2025		Change
Daily Production
Liquids (bbl/d)
Light oil and condensate	14,891		12,605		18%		12,998		11,852		10%
Heavy oil	44,341		45,269		(2)%		45,197		42,825		6%
Natural Gas Liquids (NGL)	4,719		3,485		35%		4,500		3,199		41%
Total liquids (bbl/d)	63,951		61,359		4%		62,695		57,876		8%
Natural gas (mcf/d)	45,926		40,961		12%		48,529		42,335		15%
Daily production (boe/d) - continuing operations	71,606		68,185		5%		70,784		64,932		9%
Daily production (boe/d) - discontinued operations	—		82,765		(100)%		—		82,839		(100)%
Total production (boe/d)	71,606		150,950		(53)%		70,784		147,771		(52)%

Production Mix - continuing operations
Light oil and condensate	20	%	19	%	1	%	19	%	18	%	1	%
Heavy oil	62	%	66	%	(4)	%	64	%	66	%	(2)	%
NGL	7	%	5	%	2	%	6	%	5	%	1	%
Natural gas	11	%	10	%	1	%	11	%	11	%	—	%

Production from continuing operations of 71,606 boe/d for Q3/2026 and 70,784 boe/d for YTD 2026 increased 5% and 9% respectively compared to 68,185 boe/d for Q3/2025 and 64,932 boe/d for YTD 2025 with strong performance from both our heavy oil and Duvernay development programs over the last year.

Total production of 70,784 boe/d for YTD 2026 is consistent with annual guidance of approximately 71,000 boe/d for 2026.

COMMODITY PRICES

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

Benchmark Prices


	Three Months Ended September 30			Nine Months Ended September 30
	2026	2025	Change	2026	2025	Change

WTI oil (US$/bbl) (1)	85.79	64.93	20.86	83.50	66.70	16.80
Edmonton par oil ($/bbl) (2)	119.21	86.20	33.01	114.99	88.54	26.45
Edmonton par oil differential to WTI (US$/bbl)	(0.57)	(2.35)	1.78	(0.46)	(3.40)	2.94
WCS heavy oil ($/bbl) (3)	100.59	75.14	25.45	95.95	77.80	18.15
WCS heavy oil differential to WTI (US$/bbl)	(13.88)	(10.38)	(3.50)	(14.21)	(11.08)	(3.13)
AECO 7A natural gas price ($/mcf) (4)	1.54	1.00	0.54	1.85	1.70	0.15
AECO 5A natural gas price ($/mcf) (5)	1.57	0.63	0.94	1.74	1.50	0.24
CAD/USD average exchange rate	1.3988	1.3774	0.0214	1.3847	1.3988	(0.0141)

(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.

(2)Edmonton par refers to the average posting price for the benchmark MSW crude oil.

(3)WCS refers to the average posting price for the benchmark WCS heavy oil.

(4)AECO 7A refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").

(5)AECO 5A refers to the AECO arithmetic average daily index price published by the CGPR.

Crude Oil

In March 2026, oil prices increased sharply and have remained volatile due to the conflict in Iran and related supply disruptions. The WTI benchmark price averaged US$85.79/bbl for Q3/2026 and US$83.50/bbl for YTD 2026 compared to US$64.93/bbl for Q3/2025 and US$66.70/bbl for YTD 2025.

Prices for Canadian oil trade at a discount to WTI due to limited egress to diversified markets and the cost of transportation from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on demand for heavy oil as well as production and inventory levels in Western Canada.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $119.21/bbl during Q3/2026 and $114.99/bbl for YTD 2026 compared to $86.20/bbl during Q3/2025 and $88.54/bbl for YTD 2025. Edmonton par differentials strengthened in 2026 as Canadian light oil benefited from tighter global light crude and refined product markets. Edmonton par traded at a discount to WTI of US$0.57/bbl for Q3/2026 and US$0.46/bbl for YTD 2026, compared to discounts of US$2.35/bbl for Q3/2025 and US$3.40/bbl for YTD 2025.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark averaged $100.59/bbl for Q3/2026 and $95.95/bbl for YTD 2026 compared to $75.14/bbl for Q3/2025 and $77.80/bbl for YTD 2025. The WCS heavy oil differential to WTI was US$13.88/bbl in Q3/2026 and US$14.21/bbl for YTD 2026 which was wider compared to US$10.38/bbl for Q3/2025 and US$11.08/bbl for YTD 2025 reflecting higher Western Canadian supply and increased competition from other heavy and sour crude barrels delivered to the U.S. Gulf Coast.

Natural Gas

We compare our natural gas pricing to the AECO 7A benchmark which averaged $1.54/mcf during Q3/2026 and $1.85/mcf during YTD 2026 compared to $1.00/mcf for Q3/2025 and $1.70/mcf for YTD 2025. Natural gas prices in Canada remain low due to increasing production combined with egress constraints and slow ramp-up of LNG related demand.

Average Realized Sales Prices


	Three Months Ended September 30						Nine Months Ended September 30
	2026		2025		Change		2026		2025		Change

Light oil and condensate ($/bbl) (1)	$	118.44	$	85.53	$	32.91	$	112.19	$	87.32	$	24.87
Heavy oil, net of blending and other expense ($/bbl) (2)	91.26		67.05		24.21		84.57		68.17		16.40
NGL ($/bbl) (1)	24.62		22.62		2.00		24.59		24.47		0.12
Natural gas ($/mcf) (1)	1.47		0.65		0.82		1.63		1.49		0.14
Total sales, net of blending and other expense ($/boe) (2) - continuing operations	$	83.71	$	61.88	$	21.83	$	77.28	$	63.08	$	14.20
Total sales ($/boe) - discontinued operations	—		64.32		(64.32)		—		66.78		(66.78)
Total sales, net of blending and other expense ($/boe) (2)	$	83.71	$	63.22	$	20.49	$	77.28	$	65.15	$	12.13

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

Our total sales, net of blending and other expense per boe for continuing operations was $83.71/boe for Q3/2026 and $77.28/boe for YTD 2026 compared to $61.88/boe for Q3/2025 and $63.08/boe for YTD 2025. The increase is primarily due to higher benchmark oil pricing relative to both periods of 2025.

Our realized light oil and condensate price for continuing operations represents a discount to the Edmonton par price of $0.77/bbl for Q3/2026 and $2.80/bbl for YTD 2026 compared to a discount of $0.67/bbl in Q3/2025 and $1.22/bbl in YTD 2025. The narrower discount in Q3/2026 is more reflective of normal operations compared to the wider discount in YTD 2026 which reflects the timing of production along with the increase in benchmark oil prices later in Q1 2026.

Our realized heavy oil price, net of blending and other expense for continuing operations was higher in Q3/2026 and YTD 2026 compared to the same periods of 2025 which reflects the increase in WCS benchmark pricing. Our realized pricing for Q3/2026 and YTD 2026 represents a discount to the WCS benchmark of $9.33/bbl and $11.38/bbl respectively compared to $8.09/bbl Q3/2025 and $9.63/bbl for YTD 2025 which reflects higher blending costs.

Our realized NGL price as a percentage of WTI varies based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Expressed in Canadian dollars, our realized NGL price for continuing operations was 21% of WTI in Q3/2026 and YTD 2026 compared to 25% of WTI in Q3/2025 and 26% in YTD 2025, reflecting lower market prices for propane and butane during 2026 relative to 2025.

We compare our Canadian realized natural gas price to the AECO benchmark price. A portion of our natural gas sales is based on the daily index prices which fluctuate independently from the associated monthly index prices. Our realized natural gas price for continuing operations of $1.47/mcf for Q3/2026 and $1.63/mcf for YTD 2026 was higher than $0.65/mcf for Q3/2025 and $1.49/mcf for YTD 2025, consistent with the increase in AECO benchmark pricing.

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2026		2025		Change		2026		2025		Change
Oil sales
Light oil and condensate	$	162,266	$	99,188	$	63,078	$	398,126	$	282,532	$	115,594
Heavy oil	426,675		329,005		97,670		1,248,844		981,970		266,874
NGL	10,690		7,250		3,440		30,210		21,371		8,839
Total oil sales	599,631		435,443		164,188		1,677,180		1,285,873		391,307
Natural gas sales	6,228		2,462		3,766		21,576		17,219		4,357
Total petroleum and natural gas sales	605,859		437,905		167,954		1,698,756		1,303,092		395,664
Blending and other expense	(54,380)		(49,750)		(4,630)		(205,369)		(184,951)		(20,418)
Total sales, net of blending and other expense (1) - continuing operations	$	551,479	$	388,155	$	163,324	$	1,493,387	$	1,118,141	$	375,246
Total sales - discontinued operations	—		489,743		(489,743)		—		1,510,265		(1,510,265)
Total sales, net of blending and other expense (1)	$	551,479	$	877,898	$	(326,419)	$	1,493,387	$	2,628,406	$	(1,135,019)

(1)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 MD&A for further information.

Total sales, net of blending and other expense for continuing operations was $551.5 million for Q3/2026 and $1,493.4 million for YTD 2026 compared to $388.2 million for Q3/2025 and $1,118.1 million for YTD 2025. The increase in total sales, net of blending and other expense reflects higher realized pricing and higher production in both Q3/2026 and YTD 2026. The increase in our realized pricing for Q3/2026 relative to Q3/2025 resulted in a $143.8 million increase in total sales, net of blending and other expense, and higher production contributed a $19.5 million increase in total sales, net of blending and other expense. Higher realized pricing resulted in a $274.4 million increase in total sales, net of blending and other expense, in YTD 2026 relative to YTD 2025 while higher production contributed an $100.8 million increase in total sales, net of blending and other expense, in YTD 2026 relative to YTD 2025.

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.

The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for % and per boe)	2026			2025			Change			2026			2025			Change
Royalties - continuing operations	$	94,469		$	53,645		$	40,824		$	236,436		$	160,701		$	75,735
Royalties - discontinued operations	—			127,585			(127,585)			—			405,856			(405,856)
Total royalties	$	94,469		$	181,230		$	(86,761)		$	236,436		$	566,557		$	(330,121)

Average royalty rate (1) - continuing operations	17.1		%	13.8		%	3.3		%	15.8		%	14.4		%	1.4		%
Average royalty rate (1) - discontinued operations	—		%	26.1		%	(26.1)		%	—		%	26.9		%	(26.9)		%
Total average royalty rate (1)	17.1		%	20.6		%	(3.5)		%	15.8		%	21.6		%	(5.8)		%

Royalties per boe (2) - continuing operations	$	14.34		$	8.55		$	5.79		$	12.24		$	9.07		$	3.17
Royalties per boe (2) - discontinued operations	$	—		$	16.76		$	(16.76)		$	—		$	17.95		$	(17.95)
Total royalties per boe (2)	$	14.34		$	13.05		$	1.29		$	12.24		$	14.04		$	(1.80)

(2)Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

Royalties for continuing operations were $94.5 million or 17.1% of total sales, net of blending and other expense for Q3/2026 compared to $53.6 million or 13.8% for Q3/2025. Royalties for continuing operations were $236.4 million or 15.8% of total sales, net of blending and other expense for YTD 2026 compared to $160.7 million or 14.4% for YTD 2025. Our average royalty rate was higher for Q3/2026 and YTD 2026 as a result of higher benchmark prices.

Our average royalty rate of 15.8% for YTD 2026 is consistent with our revised annual guidance of approximately 16% for 2026.

OPERATING EXPENSE


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2026		2025		Change		2026		2025		Change
Operating expense - continuing operations	$	84,377	$	84,994	$	(617)	$	255,464	$	248,609	$	6,855
Operating expense - discontinued operations	—		75,290		(75,290)		—		220,398		(220,398)
Total operating expense	$	84,377	$	160,284	$	(75,907)	$	255,464	$	469,007	$	(213,543)

Operating expense per boe (1) - continuing operations	$	12.81	$	13.55	$	(0.74)	$	13.22	$	14.02	$	(0.80)
Operating expense per boe (1) - discontinued operations	$	—	$	9.89	$	(9.89)	$	—	$	9.75	$	(9.75)
Total operating expense per boe (1)	$	12.81	$	11.54	$	1.27	$	13.22	$	11.63	$	1.59

(1)Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

Operating expense for continuing operations was $84.4 million ($12.81/boe) for Q3/2026 and $255.5 million ($13.22/boe) for YTD 2026 compared to $85.0 million ($13.55/boe) for Q3/2025 and $248.6 million ($14.02/boe) for YTD 2025. Operating expense for continuing operations for Q3/2026 and YTD 2026 was relatively consistent with both Q3/2025 and YTD 2025 while per unit operating expense decreased as higher production volumes enabled costs to be absorbed over a larger production base.

Operating expense of $13.22/boe for YTD 2026 is consistent with our revised annual guidance of $13.30/boe for 2026.

TRANSPORTATION EXPENSE

Transportation expense includes the costs incurred to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize sales prices and transportation rates. The following table compares our transportation expense for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2026		2025		Change		2026		2025		Change
Transportation expense - continuing operations	$	23,078	$	23,060	$	18	$	72,144	$	62,383	$	9,761
Transportation expense - discontinued operations	—		12,235		(12,235)		—		36,331		(36,331)
Total transportation expense	$	23,078	$	35,295	$	(12,217)	$	72,144	$	98,714	$	(26,570)

Transportation expense per boe (1) - continuing operations	$	3.50	$	3.68	$	(0.18)	$	3.73	$	3.52	$	0.21
Transportation expense per boe (1) - discontinued operations	$	—	$	1.61	$	(1.61)	$	—	$	1.61	$	(1.61)
Total transportation expense per boe (1)	$	3.50	$	2.54	$	0.96	$	3.73	$	2.45	$	1.28

(1)Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

Transportation expense for continuing operations was $23.1 million ($3.50/boe) for Q3/2026 and $72.1 million ($3.73/boe) for YTD 2026 compared to $23.1 million ($3.68/boe) for Q3/2025 and $62.4 million ($3.52/boe) for YTD 2025. Transportation expense for continuing operations for Q3/2026 was consistent with Q3/2025 while YTD 2026 increased as a result of higher heavy oil production and an increase in trucking rates relative to 2025.

Transportation expense of $3.73/boe for YTD 2026 is consistent with our revised annual guidance of $3.75/boe for 2026.

BLENDING AND OTHER EXPENSE

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

Blending and other expense was $54.4 million for Q3/2026 and $205.4 million for YTD 2026 compared to $49.8 million for Q3/2025 and $185.0 million for YTD 2025. Higher blending and other expense for both periods in 2026 is a result of the increase in the cost of condensate purchased for blending as well as higher heavy oil production in YTD 2026 compared to YTD 2025.

FINANCIAL DERIVATIVES

As part of our normal operations, our business is exposed to fluctuations in commodity prices. In an effort to manage this exposure, we may utilize various financial derivative contracts which are intended to reduce the volatility in our cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and new contracts are entered into.

The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2026		2025		Change		2026		2025		Change
Realized financial derivatives gain (loss)
Crude oil	$	4,990	$	(9,203)	$	14,193	$	(109,725)	$	(22,484)	$	(87,241)
Natural gas	818		623		195		2,098		1,836		262

Total	$	5,808	$	(8,580)	$	14,388	$	(107,627)	$	(20,648)	$	(86,979)
Unrealized financial derivatives gain (loss)
Crude oil	$	6,908	$	(4,401)	$	11,309	$	(8,585)	$	(20,016)	$	11,431
Natural gas	(1,836)		7,942		(9,778)		(2,221)		4,669		(6,890)


Total	$	5,072	$	3,541	$	1,531	$	(10,806)	$	(15,347)	$	4,541
Total financial derivatives gain (loss)
Crude oil	$	11,898	$	(13,604)	$	25,502	$	(118,310)	$	(42,500)	$	(75,810)
Natural gas	(1,018)		8,565		(9,583)		(123)		6,505		(6,628)


Total	$	10,880	$	(5,039)	$	15,919	$	(118,433)	$	(35,995)	$	(82,438)

We recorded a total financial derivatives gain of $10.9 million for Q3/2026 and a loss of $118.4 million for YTD 2026 compared to losses of $5.0 million for Q3/2025 and $36.0 million for YTD 2025. The realized financial derivatives loss of $107.6 million for YTD 2026 was primarily a result of the increase in benchmark oil prices in March 2026 resulting in market prices for crude oil settling at levels above those set in our derivative contracts which were entered into prior to the sale of our U.S. operations. The unrealized financial derivatives loss of $10.8 million for YTD 2026 reflects both the reclassification of unrealized losses to realized losses upon settlement of contracts during 2026 and the increase in forecasted crude oil pricing used to revalue outstanding volumes on crude oil contracts in place at September 30, 2026, relative to December 31, 2025. The fair value of our financial derivative contracts resulted in a net asset of $15.7 million at September 30, 2026 compared to a net asset of $26.5 million at December 31, 2025.

Refer to Note 18 of the consolidated financial statements for a complete listing of our outstanding contracts at November 5, 2026.

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30							Nine Months Ended September 30
($ per boe except for volume)	2026		2025		Change			2026		2025		Change
Daily production (boe/d) - continuing operations	71,606		68,185		5		%	70,784		64,932		9		%
Daily production (boe/d) - discontinued operations	—		82,765		(100)		%	—		82,839		(100)		%
Total production (boe/d)	71,606		150,950		(53)		%	70,784		147,771		(52)		%

Operating netback:
Total sales, net of blending and other expense (1)	$	83.71	$	61.88	$	21.83		$	77.28	$	63.08	$	14.20
Less:
Royalties (2)	(14.34)		(8.55)		(5.79)			(12.24)		(9.07)		(3.17)
Operating expense (2)	(12.81)		(13.55)		0.74			(13.22)		(14.02)		0.80
Transportation expense (2)	(3.50)		(3.68)		0.18			(3.73)		(3.52)		(0.21)
Operating netback (1) - continuing operations	$	53.06	$	36.10	$	16.96		$	48.09	$	36.47	$	11.62
Operating netback (1) - discontinued operations	—		36.06		(36.06)			—		37.47		(37.47)
Operating netback (1)	$	53.06	$	36.09	$	16.97		$	48.09	$	37.03	$	11.06
Realized financial derivatives gain (loss) (3)	0.88		(0.62)		1.50			(5.57)		(0.51)		(5.06)
Operating netback after financial derivatives (1)	$	53.94	$	35.47	$	18.47		$	42.52	$	36.52	$	6.00

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

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

Our operating netback for continuing operations of $53.06/boe for Q3/2026 and $48.09/boe for YTD 2026 was higher than $36.10/boe for Q3/2025 and $36.47/boe for YTD 2025 due to the increase in our realized price which resulted in higher per unit sales net of royalties. Our operating netback after financial derivatives of $53.94/boe for Q3/2026 and $42.52/boe for YTD 2026 was higher than $35.47/boe for Q3/2025 and $36.52/boe for YTD 2025 due to higher realized pricing.

GENERAL AND ADMINISTRATIVE EXPENSE

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

The following table summarizes our G&A expense for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2026		2025 (1)		Change		2026		2025 (1)		Change
Gross G&A expense - continuing operations	$	14,616	$	17,533	$	(2,917)	$	56,723	$	56,336	$	387
Overhead recoveries - continuing operations	(2,171)		(1,709)		(462)		(5,499)		(5,351)		(148)
G&A expense - continuing operations	$	12,445	$	15,824	$	(3,379)	$	51,224	$	50,985	$	239
G&A expense - discontinued operations (2)	—		4,912		(4,912)		—		17,577		(17,577)
Total G&A expense	$	12,445	$	20,736	$	(8,291)	$	51,224	$	68,562	$	(17,338)

G&A expense per boe (3) - continuing operations	$	1.89	$	2.52	$	(0.63)	$	2.65	$	2.88	$	(0.23)
G&A expense per boe (3) - discontinued operations	$	—	$	0.65	$	(0.65)	$	—	$	0.78	$	(0.78)
Total G&A expense per boe (3)	$	1.89	$	1.49	$	0.40	$	2.65	$	1.70	$	0.95

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.

(2)General and administrative expense for discontinued operations is net of recoveries.

(3)General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

G&A expense for continuing operations was $12.4 million ($1.89/boe) for Q3/2026 and $51.2 million ($2.65/boe) for YTD 2026 compared to $15.8 million ($2.52/boe) for Q3/2025 and $51.0 million ($2.88/boe) for YTD 2025. G&A expense for continuing operations for YTD 2026 was consistent with YTD 2025 while Q3/2026 decreased compared to Q3/2025 due to savings realized in professional fees and insurance costs, as well as reduced personnel costs. G&A expense for continuing operations for YTD 2026 includes severance and other non-recurring costs related to staff reductions in Canada which resulted in higher G&A expense per boe for YTD 2026 compared to Q3/2026.

NET FINANCING AND INTEREST EXPENSE

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

The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2026		2025 (1)		Change		2026		2025 (1)		Change
Interest on credit facilities	$	827	$	2,951	$	(2,124)	$	2,556	$	9,790	$	(7,234)
Interest on long-term notes	1,676		36,718		(35,042)		5,031		114,680		(109,649)
Interest on lease obligations	1,423		323		1,100		3,961		985		2,976
Interest income	(4,466)		(86)		(4,380)		(15,544)		(478)		(15,066)
Net cash interest (income) expense	$	(540)	$	39,906	$	(40,446)	$	(3,996)	$	124,977	$	(128,973)
Amortization of debt issue costs	63		2,217		(2,154)		642		8,121		(7,479)
Accretion of asset retirement obligations	5,146		4,939		207		15,339		14,155		1,184

Early redemption expense (gain)	—		—		—		297		(2,755)		3,052
Net financing and interest expense - continuing operations	$	4,669	$	47,062	$	(42,393)	$	12,282	$	144,498	$	(132,216)
Net financing and interest expense - discontinued operations	—		5,374		(5,374)		—		14,897		(14,897)
Total net financing and interest expense	$	4,669	$	52,436	$	(47,767)	$	12,282	$	159,395	$	(147,113)



Net financing and interest expense per boe (2) - continuing operations	$	0.71	$	7.50	$	(6.79)	$	0.64	$	8.15	$	(7.51)

Net financing and interest expense per boe (2) - discontinued operations	$	—	$	0.71	$	(0.71)	$	—	$	0.66	$	(0.66)

Total net financing and interest expense per boe (2)	$	0.71	$	3.78	$	(3.07)	$	0.64	$	3.95	$	(3.31)

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.

(2)Calculated as net financing and interest expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

Net financing and interest expense for continuing operations was $4.7 million ($0.71/boe) for Q3/2026 and $12.3 million ($0.64/boe) for YTD 2026 compared to $47.1 million ($7.50/boe) for Q3/2025 and $144.5 million ($8.15/boe) for YTD 2025. Lower net financing and interest expense for Q3/2026 and YTD 2026 reflects the repayment of nearly all of our outstanding debt following the Eagle Ford disposition in Q4/2025.

We recorded net cash interest income for continuing operations of $0.5 million for Q3/2026 and $4.0 million for YTD 2026 compared to interest expense of $39.9 million for Q3/2025 and $125.0 million for YTD 2025. In Q4/2025, we repaid the majority of our outstanding credit facilities, redeemed the 8.5% Senior Notes and partially redeemed the 7.375% Senior Notes which resulted in lower interest on our credit facilities and long-term notes in Q3/2026 and YTD 2026. Interest on our credit facilities for Q3/2026 and YTD 2026 reflects the standby fees rate of 0.5% compared to the weighted average interest rate of 6.7% for Q3/2025 and YTD 2025. Interest income for Q3/2026 and YTD 2026 reflects interest earned on cash deposits held in high-interest savings accounts during the period.

Accretion of asset retirement obligations for continuing operations of $5.1 million for Q3/2026 and $15.3 million for YTD 2026 was consistent with $4.9 million for Q3/2025 and $14.2 million for YTD 2025. Amortization of debt issue costs for continuing operations of $0.1 million for Q3/2026 and $0.6 million for YTD 2026 was lower than $2.2 million for Q3/2025 and $8.1 million for YTD 2025 due to the de-recognition of debt issue costs associated with the credit facilities and the long-term notes in Q4/2025.

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense from continuing operations was $0.1 million for Q3/2026 and $1.5 million for YTD 2026 compared to $0.1 million for Q3/2025 and $0.7 million for YTD 2025.

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and nine months ended September 30, 2026 and 2025.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2026		2025 (1)		Change		2026		2025 (1)		Change


Depletion and depreciation - continuing operations	$	131,138	$	126,218	$	4,920	$	383,773	$	360,965	$	22,808
Depletion and depreciation - discontinued operations	—		202,875		(202,875)		—		610,210		(610,210)
Total depletion and depreciation	$	131,138	$	329,093	$	(197,955)	$	383,773	$	971,175	$	(587,402)

Depletion and depreciation per boe (2) - continuing operations	$	19.91	$	20.12	$	(0.21)	$	19.86	$	20.36	$	(0.50)
Depletion and depreciation per boe (2) - discontinued operations	$	—	$	26.64	$	(26.64)	$	—	$	26.98	$	(26.98)
Total depletion and depreciation per boe (2)	$	19.91	$	23.70	$	(3.79)	$	19.86	$	24.07	$	(4.21)

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.

(2)Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.

Depletion and depreciation expense for continuing operations was $131.1 million ($19.91/boe) for Q3/2026 and $383.8 million ($19.86/boe) for YTD 2026 compared to $126.2 million ($20.12/boe) for Q3/2025 and $361.0 million ($20.36/boe) for YTD 2025. Depletion and depreciation expense for continuing operations was higher in Q3/2026 and YTD 2026 relative to Q3/2025 and YTD 2025 due to higher production.

IMPAIRMENT

We concluded there were no indicators of impairment or impairment reversal on all of our oil and gas properties and exploration and evaluation assets at September 30, 2026.

SHARE-BASED COMPENSATION EXPENSE

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

We recorded SBC expense of $9.2 million for Q3/2026 and $36.4 million for YTD 2026 for our continuing operations compared to $8.4 million for Q3/2025 and $9.7 million for YTD 2025. The increase for Q3/2026 and YTD 2026 primarily reflects changes in the Company's share price, which increased the value of the awards resulting in higher SBC expense relative to the same periods in 2025. The total expense YTD 2026 for continuing operations is comprised of $31.5 million of cash expense and $4.9 million of non-cash expense for awards designated as equity-settled.

FOREIGN EXCHANGE

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


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for exchange rates)	2026		2025		Change		2026		2025		Change
Unrealized foreign exchange (gain) loss	$	(132)	$	36,840	$	(36,972)	$	3,191	$	(67,427)	$	70,618
Realized foreign exchange loss (gain)	500		81		419		(1,205)		(116)		(1,089)
Foreign exchange loss (gain) - continuing operations	$	368	$	36,921	$	(36,553)	$	1,986	$	(67,543)	$	69,529


CAD/USD exchange rates:
At beginning of period	1.4206		1.3622				1.3715		1.4405
At end of period	1.4191		1.3906				1.4191		1.3906

We recorded a foreign exchange loss for continuing operations of $0.4 million for Q3/2026 and $2.0 million for YTD 2026 compared to a loss of $36.9 million for Q3/2025 and a gain of $67.5 million for YTD 2025.

The unrealized foreign exchange gain for continuing operations of $0.1 million for Q3/2026 and the loss of $3.2 million for YTD 2026 is related to changes in the reported amount of our U.S. dollar denominated long-term notes due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2026 compared to June 30, 2026 and December 31, 2025. The unrealized foreign exchange loss of $36.8 million for Q3/2025 and gain of $67.4 million for YTD 2025 is related to changes in the reported amount of our long-term notes and credit facilities due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2025 compared to June 30, 2025 and December 31, 2024.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss for continuing operations of $0.5 million for Q3/2026 and a gain of $1.2 million for YTD 2026 compared to a loss of $0.1 million for Q3/2025 and a gain of $0.1 million for YTD 2025.

INCOME TAXES


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2026		2025 (1)		Change		2026		2025 (1)		Change
Current income tax expense	$	25	$	1,076	$	(1,051)	$	25	$	8,061	$	(8,036)
Deferred income tax expense	48,329		15,089		33,240		79,105		41,095		38,010
Income tax expense - continuing operations	$	48,354	$	16,165	$	32,189	$	79,130	$	49,156	$	29,974
Income tax (recovery) expense - discontinued operations	$	—	$	(1,125)	$	1,125	$	—	$	9,105	$	(9,105)

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.

We recorded current income tax expense for continuing operations of $25 thousand in Q3/2026 and YTD 2026 compared to an expense of $1.1 million for Q3/2025 and $8.1 million for YTD 2025. Current income tax expense for Q3/2025 and YTD 2025 relates to the financing structure previously utilized in connection with our Eagle Ford operations.

We recorded a deferred income tax expense for continuing operations of $48.3 million for Q3/2026 and $79.1 million for YTD 2026 compared to expense of $15.1 million for Q3/2025 and $41.1 million for YTD 2025. The deferred tax expense for Q3/2026 and YTD 2026 reflects an effective tax rate of 23.2% and 24.1% which is similar to our statutory rate of 24.0%.

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

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During 2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent statement of account issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $244.2 million and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments

allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the Losses. In September 2025, the Department of Justice, legal counsel for the Crown, abandoned the position that the trusts were resettled. The issue of whether the general anti-avoidance rule applies remains in dispute. If, after exhausting available appeals, the deduction of the Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three and nine months ended September 30, 2026 and 2025 are set forth in the following table.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2026		2025 (1)		Change		2026		2025 (1)		Change
Petroleum and natural gas sales	$	605,859	$	437,905	$	167,954	$	1,698,756	$	1,303,092	$	395,664
Royalties	(94,469)		(53,645)		(40,824)		(236,436)		(160,701)		(75,735)
Revenue, net of royalties	511,390		384,260		127,130		1,462,320		1,142,391		319,929

Expenses
Operating	(84,377)		(84,994)		617		(255,464)		(248,609)		(6,855)
Transportation	(23,078)		(23,060)		(18)		(72,144)		(62,383)		(9,761)
Blending and other	(54,380)		(49,750)		(4,630)		(205,369)		(184,951)		(20,418)
Operating netback (2) from continuing operations	$	349,555	$	226,456	$	123,099	$	929,343	$	646,448	$	282,895
General and administrative	(12,445)		(15,824)		3,379		(51,224)		(50,985)		(239)
Net cash interest income (expense)	540		(39,906)		40,446		3,996		(124,977)		128,973
Realized financial derivatives gain (loss)	5,808		(8,580)		14,388		(107,627)		(20,648)		(86,979)
Realized foreign exchange (loss) gain	(500)		(81)		(419)		1,205		116		1,089
Cash other expense	(1,883)		(702)		(1,181)		(5,644)		(5,801)		157
Current income tax expense	(25)		(1,076)		1,051		(25)		(8,061)		8,036
Cash share-based compensation	(9,166)		(8,440)		(726)		(31,496)		(9,716)		(21,780)
Adjusted funds flow (3) from continuing operations	$	331,884	$	151,847	$	180,037	$	738,528	$	426,376	$	312,152

Exploration and evaluation	(50)		(127)		77		(1,525)		(691)		(834)
Depletion and depreciation	(131,138)		(126,218)		(4,920)		(383,773)		(360,965)		(22,808)
Non-cash share-based compensation	—		—		—		(4,857)		—		(4,857)
Non-cash financing and interest	(5,209)		(7,156)		1,947		(16,278)		(19,521)		3,243

Unrealized financial derivatives gain (loss)	5,072		3,541		1,531		(10,806)		(15,347)		4,541
Unrealized foreign exchange gain (loss)	132		(36,840)		36,972		(3,191)		67,427		(70,618)
Gain on dispositions	7,906		1,591		6,315		10,184		1,028		9,156

Deferred income tax expense	(48,329)		(15,089)		(33,240)		(79,105)		(41,095)		(38,010)
Net income (loss) from continuing operations	$	160,268	$	(28,451)	$	188,719	$	249,177	$	57,212	$	191,965
Net income from discontinued operations	—		60,419		(60,419)		18,634		195,896		(177,262)
Net income	$	160,268	$	31,968	$	128,300	$	267,811	$	253,108	$	14,703

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.

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

We generated adjusted funds flow(1) from continuing operations of $331.9 million for Q3/2026 and $738.5 million for YTD 2026 compared to $151.8 million for Q3/2025 and $426.4 million for YTD 2025. The increase in adjusted funds flow for both periods of 2026 is a result of an increase in operating netback, which is primarily due to higher benchmark pricing and an increase in production, and lower cash interest expense due to the repayment of nearly all outstanding debt in Q4/2025. The increase in YTD 2026 operating netback was partially offset by higher realized losses on financial derivatives.

We reported net income from continuing operations of $160.3 million for Q3/2026 and $249.2 million for YTD 2026 compared to a net loss of $28.5 million for Q3/2025 and net income of $57.2 million for YTD 2025. The increase in net income for both periods of 2026 relative to 2025 is primarily due to an increase in adjusted funds flow.

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

CAPITAL EXPENDITURES

Capital expenditures for the three and nine months ended September 30, 2026 and 2025 are summarized as follows.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2026		2025		Change		2026		2025		Change
Drilling, completion and equipping	$	164,875	$	109,383	$	55,492	$	385,001	$	398,810	$	(13,809)
Facilities and other	21,554		14,196		7,358		68,682		56,822		11,860
Exploration and development expenditures - continuing operations	$	186,429	$	123,579	$	62,850	$	453,683	$	455,632	$	(1,949)
Exploration and development expenditures - discontinued operations	—		146,785		(146,785)		—		576,361		(576,361)
Total exploration and development expenditures	$	186,429	$	270,364	$	(83,935)	$	453,683	$	1,031,993	$	(578,310)

Property acquisitions - continuing operations	$	18,804	$	23,560	$	(4,756)	$	27,157	$	24,934	$	2,223
Proceeds from dispositions - continuing operations	$	(6,977)	$	(8,254)	$	1,277	$	(6,775)	$	(11,794)	$	5,019
Property acquisitions - discontinued operations	$	—	$	464	$	(464)	$	—	$	1,540	$	(1,540)
Proceeds from dispositions - discontinued operations	$	—	$	—	$	—	$	(19,434)	$	549	$	(19,983)

Exploration and development expenditures for continuing operations were $186.4 million in Q3/2026 and $453.7 million for YTD 2026 compared to $123.6 million in Q3/2025 and $455.6 million in YTD 2025. Exploration and development expenditures were higher in Q3/2026 compared to Q3/2025 due to increased activity in our Duvernay development program. Exploration and development expenditures for continuing operations for YTD 2026 included costs associated with drilling 158 (131.1 net) wells along with 148 (125.5 net) wells that were brought on production compared to drilling 175 (164.8 net) wells along with 177 (169.7 net) wells brought on production during YTD 2025. Total YTD spend is relatively consistent between the periods, but the focus has shifted in 2026 to Duvernay properties. Exploration and development expenditures for YTD 2026 in Duvernay were $197 million, while Viking and heavy oil properties had spend of $61 million and $196 million, respectively, compared to YTD 2025 which had expenditures in Duvernay of $141 million, and spend related to Viking and heavy oil properties of $85 million and $230 million, respectively. We also invested $68.7 million on facilities and other expenditures during YTD 2026.

Exploration and development expenditures of $453.7 million for YTD 2026 were consistent with expectations and our revised annual guidance for 2026 of approximately $665 million.

CAPITAL RESOURCES AND LIQUIDITY

Our capital management objective is to maintain a strong financial position that provides flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio. Baytex assesses its capital structure in response to operational requirements and changes in economic conditions. At September 30, 2026, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, inventory, trade payables, share-based compensation liability, dividends payable, cash and the credit facilities.

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

At September 30, 2026 we had net cash(1) of $522.4 million compared to $765.8 million at December 31, 2025. The decrease in net cash from December 31, 2025 primarily reflects shareholder returns of $507.5 million during YTD 2026, which includes share buybacks and quarterly dividends, partially offset by $268.3 million of free cash flow(2) earned during YTD 2026.

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

Credit Facilities

At September 30, 2026, Baytex had $750 million of revolving credit facilities (the "Credit Facilities") that mature on June 27, 2030. The Credit Facilities are secured and are comprised of a $50 million operating loan and a $700 million syndicated revolving loan. The Credit Facilities were undrawn at September 30, 2026.

The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances under the Baytex Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, Canadian Overnight Repo Rate Average rates or Secured Overnight Financing Rates, plus applicable margins.

At September 30, 2026, Baytex had $4.4 million of outstanding letters of credit (December 31, 2025 - $4.4 million outstanding) under the Credit Facilities.

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

Financial Covenants

The financial covenants applicable to the Credit Facilities and calculated in accordance with the credit facility agreement are Senior Secured Debt to Bank EBITDA, Interest coverage, and Total Debt to Bank EBITDA. Senior Secured Debt to Bank EBITDA measures senior secured leverage based on the principal amount of the Credit Facilities and other secured obligations relative to Bank EBITDA, which is calculated on a twelve-month trailing basis and reflects net income or loss adjusted for various items specified in the credit facility agreement and has a maximum ratio of 3.5:1. Interest Coverage measures the Company’s ability to cover financing and interest expense based on Bank EBITDA relative to financing and interest expense and has a minimum ratio of 3.5:1. Total Debt to Bank EBITDA measures overall leverage based on the Company’s obligations, liabilities and indebtedness, excluding certain specified liabilities, relative to Bank EBITDA and has a maximum ratio of 4.0:1. Baytex is in compliance with all covenants contained in the credit facility agreement.

Long-Term Notes

During YTD 2026, Baytex repurchased and cancelled US$5.8 million principal amount of the 7.375% Senior Notes at 103.613% of par value and recorded an early redemption expense of $0.3 million. The 7.375% Senior Notes were issued on April 1, 2024 and US$64.1 million remains outstanding as at September 30, 2026. The 7.375% Senior Notes mature on March 15, 2032 and are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2026, we issued 0.1 million common shares pursuant to our share-based compensation program. As at September 30, 2026, we had 684.8 million common shares issued and outstanding and no preferred shares issued and outstanding. As at November 5, 2026, there were 675.2 million common shares issued and outstanding and no preferred shares issued and outstanding.

During the nine months ended September 30, 2026, we repurchased 80.9 million common shares under our normal course issuer bid ("NCIB") at an average price of $5.68 per share for total consideration of $459.2 million. In June 2026, the Toronto Stock Exchange ("TSX") accepted the renewal of our NCIB under which we are permitted to purchase for cancellation up to 70.9 million common shares over the 12-month period commencing July 2, 2026, which represents 10% of the Company's public float, as defined by the TSX, as at June 19, 2026. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase common shares through the New York Stock Exchange and other U.S. based trading systems.

During the nine months ended September 30, 2026, we recorded a $9.1 million charge to shareholders’ capital related to the federal tax on equity repurchases (December 31, 2025 - $0.5 million).

On January 2, April 1, July 2, and October 1, 2026, we paid quarterly cash dividends of $0.0225 per share to shareholders of record. On November 5, 2026, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 4, 2027 to shareholders of record on December 15, 2026. These dividends are designated as “eligible dividends” for Canadian income tax purposes. These dividends are considered “qualified dividends” for U.S income tax purposes.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2026 and the expected timing for funding these obligations are noted in the table below.


($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years

Long-term notes - principal	$	91,011	$	—	$	—	$	—	$	91,011
Interest on long-term notes	36,649		6,712		13,424		13,424		3,089
Lease obligations - principal	94,327		15,723		23,473		16,912		38,219
Processing agreements	4,252		460		543		521		2,728
Transportation agreements	60,766		36,516		18,766		3,276		2,208
Total	$	287,005	$	59,411	$	56,206	$	34,133	$	137,255

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

The Company is, from time-to-time, subject to various claims, demands, audits and other proceedings covering matters that arise in the ordinary course of business activities. Such claims and other proceedings often relate to labour, tax, personal injury, environmental, title or commercial matters. Baytex retains liability for matters related to our prior ownership of assets located in the U.S.. Resolution of these matters may have an unfavorable financial or operating impact on the Company. Certain conditions may exist as at September 30, 2026 which may result in a loss to the Company. However, the Company believes that none of these matters are expected to have a material effect on the results of operations or financial position of the Company.

The Company establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Company also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Company.

QUARTERLY FINANCIAL INFORMATION


	2026			2025				2024
($ thousands, except per common share amounts)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Petroleum and natural gas sales	605,859	639,943	452,954	759,815	927,648	886,579	999,130	1,017,017
Net income (loss) - continuing operations (1)	160,268	168,588	(79,679)	(334,057)	(28,451)	103,018	(17,355)	(124,903)
Per common share - basic	0.23	0.23	(0.11)	(0.43)	(0.04)	0.13	(0.02)	(0.16)
Per common share - diluted	0.23	0.23	(0.11)	(0.43)	(0.04)	0.13	(0.02)	(0.16)
Net income (loss)	160,268	174,869	(67,326)	(856,887)	31,968	151,549	69,591	(38,477)
Per common share - basic	0.23	0.24	(0.09)	(1.12)	0.04	0.20	0.09	(0.05)
Per common share - diluted	0.23	0.24	(0.09)	(1.12)	0.04	0.20	0.09	(0.05)
Adjusted funds flow (2)	331,884	254,433	151,125	261,531	422,232	366,919	463,870	461,886
Per common share - basic	0.48	0.35	0.20	0.34	0.55	0.48	0.60	0.59
Per common share - diluted	0.47	0.35	0.20	0.34	0.55	0.48	0.60	0.59
Free cash flow (3)	138,506	128,045	1,705	76,486	142,688	3,188	52,529	254,838
Per common share - basic	0.20	0.18	—	0.10	0.19	—	0.07	0.33
Per common share - diluted	0.20	0.18	—	0.10	0.18	—	0.07	0.33
Cash flows from operating activities	283,034	230,852	122,203	227,657	472,676	354,312	431,317	468,865
Per common share - basic	0.41	0.32	0.16	0.30	0.62	0.46	0.56	0.60
Per common share - diluted	0.40	0.32	0.16	0.30	0.61	0.46	0.56	0.60
Dividends declared	15,578	16,144	16,606	17,268	17,326	17,304	17,289	17,598
Per common share	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225
Exploration and development	186,429	122,242	145,012	174,078	270,364	356,532	405,097	198,177
Canada	186,429	122,242	145,012	92,720	123,579	147,734	184,319	108,971
U.S. (4)	—	—	—	81,358	146,785	208,798	220,778	89,206
Property acquisitions	18,804	226	8,127	5,544	24,024	1,193	1,257	12,621
Proceeds from dispositions	(6,977)	(6,119)	(13,113)	(3,012,058)	(8,254)	(725)	(2,266)	(42,339)
Net (cash) debt (2)	(522,367)	(566,286)	(591,151)	(765,785)	2,244,358	2,293,940	2,390,250	2,417,172
Total assets	3,206,395	3,169,943	3,252,692	3,345,414	7,601,389	7,552,013	7,824,576	7,759,745
Common shares outstanding	684,800	708,888	730,561	765,568	768,317	768,317	770,039	773,590

Daily production
Total production (boe/d)	71,606	71,243	69,478	137,087	150,950	148,095	144,194	152,894
Canada (boe/d)	71,606	71,243	69,478	67,295	68,185	64,167	62,380	65,332
U.S. (boe/d) (4)	—	—	—	69,792	82,765	83,928	81,814	87,562

Benchmark prices
WTI oil (US$/bbl)	85.79	92.79	71.93	59.14	64.93	63.74	71.42	70.27
WCS heavy oil ($/bbl)	100.59	108.16	79.28	66.88	75.14	74.10	84.33	80.77
Edmonton par oil ($/bbl)	119.21	132.26	93.50	76.49	86.20	84.15	95.27	94.98
AECO 7A natural gas ($/mcf)	1.54	1.51	2.49	2.34	1.00	2.07	2.02	1.46
CAD/USD avg exchange rate	1.3988	1.3836	1.3716	1.3949	1.3774	1.3840	1.4350	1.3992


Total sales, net of blending and other expense ($/boe) (3)	83.71	87.13	60.30	56.28	63.22	61.16	71.38	66.60
Royalties ($/boe) (5)	(14.34)	(13.94)	(8.25)	(11.54)	(13.05)	(13.16)	(16.02)	(14.69)
Operating expense ($/boe) (5)	(12.81)	(13.86)	(12.99)	(12.51)	(11.54)	(11.95)	(11.38)	(10.36)
Transportation expense ($/boe) (5)	(3.50)	(4.00)	(3.70)	(2.43)	(2.54)	(2.44)	(2.35)	(2.35)
Operating netback ($/boe) (3)	53.06	55.33	35.36	29.80	36.09	33.61	41.63	39.20
Financial derivatives (loss) gain ($/boe) (5)	0.88	(12.98)	(4.68)	0.08	(0.62)	(0.88)	(0.01)	(0.15)
Operating netback after financial derivatives ($/boe) (3)	53.94	42.35	30.68	29.88	35.47	32.73	41.62	39.05

(1)Previously disclosed amounts have been revised to conform with current period presentation.

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

(3)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 MD&A for further information.

(4)The Company's U.S. operations were disposed in December 2025.

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

Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have fluctuated, along with acquisition and disposition activity. Production of 71,606 boe/d in Q3/2026 reflects our Canadian operations following the Eagle Ford disposition in Q4/2025. Our successful light and heavy oil development programs in Canada for YTD 2026 resulted in production growth to 71,606 boe/d from 65,332 boe/d in Q4/2024 despite the disposition of certain thermal assets in Q4/2024.

Benchmark prices for crude oil declined from Q4/2024 through Q4/2025 due to increasing supply from OPEC+ and North American production growth along with concerns over slowing global economic activity. Prices sharply increased in March 2026 and remained volatile through Q3/2026 due to supply disruptions related to the conflict in Iran and resulted in realized pricing of $83.71/boe for Q3/2026 and operating netback after financial derivatives of $53.94/boe. Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow(1) of $331.9 million and cash flows from operating activities of $283.0 million for Q3/2026 reflect strong operating performance from our light and heavy oil assets.

In Q4/2025, we completed the disposition of the Eagle Ford assets which resulted in net cash(1) of $522.4 million at Q3/2026 compared to a net debt position of $2.4 billion at Q4/2024. The change in net (cash) debt also reflects free cash flow(2) of $543.1 million generated in the period since Q4/2024, along with $605.5 million of shareholder returns including share buybacks and quarterly dividends.

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

ENVIRONMENTAL REGULATIONS

As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2025 for a full description of the risks associated with these regulations and how they may impact our business in the future.

Reporting Regulations

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

OFF BALANCE SHEET TRANSACTIONS

We do not have any material financial arrangements that are excluded from the consolidated financial statements as at September 30, 2026, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the nine months ended September 30, 2026. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2025.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2026, Baytex adopted amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures which were issued by the IASB in May 2024. The amendments further clarify the date of recognition and derecognition of financial assets and liabilities. These amendments have not had a material impact on our consolidated financial statements. The amendments have been applied retrospectively with no restatement of comparative information, in accordance

with transition requirements on initial application of IFRS 9. The adjustment to the cash balance is reflected as a $1.8 million increase to the opening balance of cash in the consolidated statements of cash flows.

Future Accounting Pronouncements

IFRS 18 Presentation and Disclosure in Financial Statements was issued in April 2024 and replaces IAS 1 Presentation of Financial Statements. The standard does not alter the recognition and measurement of items included in the statements of income or loss and comprehensive income or loss; however, it does change how items are presented. The statements of income or loss and comprehensive income or loss will include three new categories: operating, investing and financing. Items such as interest expense will be included in the financing section and items such as interest income on cash and cash equivalents will be included in the investing section. IFRS 18 establishes increased disclosure in the financial statements around management-defined performance measures, such as operating netback. The standard is required to be adopted retrospectively and is effective for fiscal years beginning on or after January 1, 2027, with early adoption permitted.

In addition, consequential amendments have been made to IAS 7 Statement of Cash Flows, which include changing the starting point for determining cash flows from operations under the indirect method, from ‘net income or loss’ to a new subtotal referred to as ‘operating income or loss’ and removing the optionality around classification of cash flows from interest.

The Company is completing the evaluation of the impact that this standard will have on the consolidated financial statements.

SPECIFIED FINANCIAL MEASURES

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

Non-GAAP Financial Measures

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

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

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2026		2025		2026		2025
Petroleum and natural gas sales	$	605,859	$	437,905	$	1,698,756	$	1,303,092
Light oil and condensate (1)	(162,266)		(99,188)		(398,126)		(282,532)
NGL (1)	(10,690)		(7,250)		(30,210)		(21,371)
Natural gas (1)	(6,228)		(2,462)		(21,576)		(17,219)
Heavy oil	$	426,675	$	329,005	$	1,248,844	$	981,970
Blending and other expense (2)	(54,380)		(49,750)		(205,369)		(184,951)
Heavy oil, net of blending and other expense	$	372,295	$	279,255	$	1,043,475	$	797,019

(1)Component of petroleum and natural gas sales. See Note 14 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and nine months ended September 30, 2026 for further information.

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

Operating netback

Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation expense. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to reduce price uncertainty on a portion of our production.

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2026		2025		2026		2025
Petroleum and natural gas sales	$	605,859	$	437,905	$	1,698,756	$	1,303,092
Blending and other expense	(54,380)		(49,750)		(205,369)		(184,951)
Total sales, net of blending and other expense	551,479		388,155		1,493,387		1,118,141
Royalties	(94,469)		(53,645)		(236,436)		(160,701)
Operating expense	(84,377)		(84,994)		(255,464)		(248,609)
Transportation expense	(23,078)		(23,060)		(72,144)		(62,383)
Operating netback - continuing operations	$	349,555	$	226,456	$	929,343	$	646,448
Realized financial derivatives gain (loss) (1)	5,808		(8,580)		(107,627)		(20,648)
Operating netback after realized financial derivatives - continuing operations	$	355,363	$	217,876	$	821,716	$	625,800

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 18 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2026 for further information.

Free cash flow

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

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2026		2025		2026		2025
Cash flows from operating activities	$	283,034	$	472,676	$	636,089	$	1,258,305
Change in non-cash working capital	44,330		(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)		(270,364)		(450,839)		(1,031,063)
Payments on lease obligations	(2,429)		(3,663)		(6,431)		(10,022)

Free cash flow	$	138,506	$	142,688	$	268,256	$	198,405

Non-GAAP Financial Ratios

Heavy oil, net of blending and other expense per bbl

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

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 continuing or total operations.

Average royalty rate

Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties divided by total sales, net of blending and other expense (a non-GAAP financial measure) for continuing or total operations. Average royalty rate for discontinued operations is calculated as royalties divided by total petroleum and natural gas sales. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.

Operating netback per boe

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

Capital Management Measures

Net cash

We use net cash to monitor our current financial position and to evaluate existing sources of liquidity. We also use net cash projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net cash 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, cash, trade receivables, prepaids and other assets, and inventory.

The following table summarizes our calculation of net cash.


	As at
($ thousands)	September 30, 2026		December 31, 2025
Credit facilities	$	—	$	1,138
Unamortized debt issuance costs - Credit facilities (1)	—		262
Long-term notes	89,201		93,834
Unamortized debt issuance costs - Long-term notes (1)	1,810		2,113
Trade payables	289,861		236,373
Share-based compensation liability	37,907		34,802
Dividends payable	15,578		17,268

Cash	(652,602)		(953,113)
Trade receivables	(244,000)		(135,230)
Prepaids and other assets	(58,498)		(63,232)
Inventory	(1,624)		—
Net cash	$	(522,367)	$	(765,785)

(1)Unamortized debt issuance costs were obtained from Note 8 - Credit Facilities and Note 9 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2026. These amounts represent the remaining balance of costs that were paid by Baytex at the inception of the contract.

Adjusted funds flow

Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital and asset retirements 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 September 30				Nine Months Ended September 30
($ thousands)	2026		2025		2026		2025
Cash flow from operating activities	$	283,034	$	472,676	$	636,089	$	1,258,305
Change in non-cash working capital	44,330		(55,961)		92,281		(17,885)
Asset retirement obligations settled	4,520		5,517		9,072		12,601

Adjusted funds flow	$	331,884	$	422,232	$	737,442	$	1,253,021

INTERNAL CONTROL OVER FINANCIAL REPORTING

We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any material weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no material weaknesses or such changes were identified in our internal controls over financial reporting during the three and nine months ended September 30, 2026.

FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to but not limited to: our 2026 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, lease expenditures and asset retirement obligations settled; the we may seek to reduce cash flow volatility by using financial derivates; the expected time to resolve the reassessment of our tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions and dispositions; that we may issue or repurchase debt or equity securities from time to time and sell adjust or adjust capital spending; our intent to fund a significant portion of our financial obligations with adjusted funds flow and the expected timing of those financial obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

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 productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 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.

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

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 acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future.

Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend is subject to the discretion of the Board of Directors of Baytex.