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Baytex Energy Corp.

Management’s Discussion and Analysis

For the three months ended March 31, 2026 and 2025

Dated May 7, 2026

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2026. This information is provided as of May 7, 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 months ended March 31, 2026 ("Q1/2026") have been compared with the results for the three months ended March 31, 2025 ("Q1/2025"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 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. 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 Viking and Duvernay light oil assets along with heavy oil assets in Peace River and Lloydminster.

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 our operations and its results have been classified as discontinued operations. The financial results for the three months ended March 31, 2026 and March 31, 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 March 31
	2026						2025
	Continuing		Discontinued		Total		Continuing		Discontinued		Total

Revenue, net of royalties
Petroleum and natural gas sales	$	452,954	$	—	$	452,954	$	454,151	$	544,979	$	999,130
Royalties	(51,589)		—		(51,589)		(59,256)		(148,681)		(207,937)
	401,365		—		401,365		394,895		396,298		791,193

Expenses
Operating	81,244		—		81,244		75,580		72,123		147,703
Transportation	23,134		—		23,134		18,779		11,733		30,512
Blending and other	75,921		—		75,921		72,820		—		72,820
General and administrative	22,299		—		22,299		18,566		7,040		25,606

Exploration and evaluation	665		—		665		107		—		107
Depletion and depreciation	123,690		—		123,690		116,743		203,180		319,923

Share-based compensation	22,870		—		22,870		413		350		763
Net financing and interest expense	3,097		—		3,097		50,567		4,679		55,246
Financial derivatives loss	150,756		—		150,756		49,619		—		49,619
Foreign exchange loss (gain)	1,934		—		1,934		(3,878)		—		(3,878)
(Gain) loss on dispositions	(2,017)		(13,439)		(15,456)		1,229		—		1,229
Other expense (income)	1,704		—		1,704		2,396		(1,207)		1,189
	505,297		(13,439)		491,858		402,941		297,898		700,839
Net (loss) income before income taxes	(103,932)		13,439		(90,493)		(8,046)		98,400		90,354

Income taxes
Current income tax expense	—		1,086		1,086		947		1,205		2,152
Deferred income tax (recovery) expense	(24,253)		—		(24,253)		8,362		10,249		18,611
	(24,253)		1,086		(23,167)		9,309		11,454		20,763
Net (loss) income	$	(79,679)	$	12,353	$	(67,326)	$	(17,355)	$	86,946	$	69,591

FIRST QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q1/2026. Production of 69,478 boe/d exceeded the high end of our guidance range of 67,000 - 69,000 boe/d driven by outperformance from our heavy oil assets. Exploration and development expenditures of $145.0 million for Q1/2026 were consistent with our full-year plan and were focused on our heavy oil and Duvernay development programs. We remain committed to shareholder returns and completed $174.3 million of share repurchases during Q1/2026.

We invested $145.0 million and generated production of 69,478 boe/d in Q1/2026 compared to exploration and development expenditures of $184.3 million and production of 62,380 boe/d in Q1/2025. Production for Q1/2026 was 11% higher compared to Q1/2025 which reflects strong well performance and the efficiency of our Duvernay and heavy oil development programs. Exploration and development expenditures of $145.0 million reflect our active heavy oil development program with 25.7 net wells brought on production during the quarter. Exploration and development expenditures for Q1/2026 also includes drilling of the first four wells of our 2026 Duvernay development program with completion operations now underway.

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$91.00/bbl in March which resulted in an average of US$71.93/bbl for Q1/2026 compared to US$71.42/bbl for Q1/2025. Our financial results for Q1/2026 reflect our strong operating performance and volatile benchmark oil prices which resulted in adjusted funds flow(1) of $152.2 million and cash flows from operating activities of $122.2 million from continuing operations compared to Q1/2025 when we generated adjusted funds flow of $162.0 million and cash flows from operating activities of $155.1 million from continuing operations.

Net cash(1) was $591.2 million at March 31, 2026 compared to $765.8 million at December 31, 2025 which reflects $190.9 million of shareholder returns including share buybacks and the quarterly dividend.

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

GUIDANCE

Based on strong operating performance to-date and planned activity for the remainder of the year we have revised our 2026 production guidance to 69,000 - 71,000 boe/d. Additional heavy oil and Duvernay development in the second half of 2026 will result in exploration and development expenditures of approximately $625 million which is at the high end of our annual guidance range.

The following table compares our 2026 revised annual guidance to our previously announced guidance and Q1/2026 results.


	2026 Annual Guidance (1)	Revised Annual Guidance	Q1/2026 Results
Exploration and development expenditures	$550 - $625 million	~ $625 million	$145.0 million
Production (boe/d)	67,000 - 69,000	69,000 - 71,000	69,478

Expenses:
Average royalty rate (2)	15%	No change	13.7	%
Operating (3)	$13.75 - $14.25/boe	No change	$12.99/boe
Transportation (3)	$3.40 - $3.60/boe	No change	$3.70/boe




Leasing expenditures	$7 million	No change	$1.8 million
Asset retirement obligations settled	$20 million	No change	$2.6 million

(1)As announced on December 22, 2025.

(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.

(3)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 March 31
	2026		2025		Change
Daily Production
Liquids (bbl/d)
Light oil and condensate	11,835		11,775		1%
Heavy oil	44,908		40,192		12%
Natural Gas Liquids (NGL)	4,368		3,123		40%
Total liquids (bbl/d)	61,111		55,090		11%
Natural gas (mcf/d)	50,205		43,743		15%
Daily production (boe/d) - continuing operations	69,478		62,380		11%
Daily production (boe/d) - discontinued operations	—		81,814		(100)%
Total production (boe/d)	69,478		144,194		(52)%

Production Mix - continuing operations
Light oil and condensate	17	%	19	%	(2)	%
Heavy oil	65	%	64	%	1	%
NGL	6	%	5	%	1	%
Natural gas	12	%	12	%	—	%

Production from continuing operations of 69,478 boe/d for Q1/2026 increased 11% compared to 62,380 boe/d for Q1/2025 with strong performance from both our heavy oil and Duvernay development programs over the last year. Production of 69,478 boe/d for Q1/2026 is consistent with our revised annual guidance range of 69,000 - 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 March 31
	2026	2025	Change

WTI oil (US$/bbl) (1)	71.93	71.42	0.51
Edmonton par oil ($/bbl) (2)	93.50	95.27	(1.77)
Edmonton par oil differential to WTI (US$/bbl)	(3.76)	(5.03)	1.27
WCS heavy oil ($/bbl) (3)	79.28	84.33	(5.05)
WCS heavy oil differential to WTI (US$/bbl)	(14.13)	(12.65)	(1.48)
AECO 7A natural gas price ($/mcf) (4)	2.49	2.02	0.47
AECO 5A natural gas price ($/mcf) (5)	2.01	2.19	(0.18)
CAD/USD average exchange rate	1.3716	1.4350	(0.0634)

(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

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 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 $93.50/bbl during Q1/2026 compared to $95.27/bbl during Q1/2025. Increased demand for light oil from Canada resulted in Edmonton par trading at a discount to WTI of US$3.76/bbl for Q1/2026 which was narrower compared to US$5.03/bbl for Q1/2025.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q1/2026 averaged $79.28/bbl compared to $84.33/bbl for Q1/2025. The WCS heavy oil differential to WTI was US$14.13/bbl in Q1/2026 which was wider compared to US$12.65/bbl for Q1/2025 due to higher heavy oil production in Western Canada.

Natural Gas

We compare our natural gas pricing to the AECO 7A benchmark which averaged $2.49/mcf during Q1/2026 compared to $2.02/mcf for Q1/2025. 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 March 31
	2026		2025		Change

Light oil and condensate ($/bbl) (1)	$	83.55	$	93.86	$	(10.31)
Heavy oil, net of blending and other expense ($/bbl) (2)	67.01		73.51		(6.50)
NGL ($/bbl) (1)	21.77		28.07		(6.30)
Natural gas ($/mcf) (1)	1.92		2.05		(0.13)
Total sales, net of blending and other expense ($/boe) (2) - continuing operations	$	60.30	$	67.92	$	(7.62)
Total sales ($/boe) - discontinued operations	—		74.01		(74.01)
Total sales, net of blending and other expense ($/boe) (2)	$	60.30	$	71.38	$	(11.08)

(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 $60.30/boe for Q1/2026 compared to $67.92/boe for Q1/2025. The decrease primarily reflects lower realized prices for our oil and NGL relative to Q1/2025. Although benchmark prices strengthened in March 2026, the quarter as a whole was affected by lower realized pricing earlier in the period and the timing of sales relative to the March price increase.

Our realized light oil and condensate price for continuing operations represents a discount to the Edmonton par price of $9.95/bbl for Q1/2026 compared to a discount of $1.41/bbl in Q1/2025. The wider discount in Q1/2026 reflects the timing of production during the period along with a sharp increase in benchmark oil prices during March 2026.

Our realized heavy oil price, net of blending and other expense for continuing operations was lower in Q1/2026 compared to the same period of 2025 which reflects the decrease in WCS benchmark pricing. Our realized pricing for Q1/2026 represents a discount to the WCS benchmark of $12.27/bbl compared to $10.82/bbl for the same period of 2025.

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 22% of WTI in Q1/2026 compared to 27% of WTI in Q1/2025, reflecting higher sales volumes of propane during Q1/2026 relative to Q1/2025.

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 $1.92/mcf for Q1/2026 was lower than $2.05/mcf for Q1/2025.

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended March 31
($ thousands)	2026		2025		Change
Oil sales
Light oil and condensate	$	88,993	$	99,469	$	(10,476)
Heavy oil	346,737		338,711		8,026
NGL	8,560		7,888		672
Total oil sales	444,290		446,068		(1,778)
Natural gas sales	8,664		8,083		581
Total petroleum and natural gas sales	452,954		454,151		(1,197)
Blending and other expense	(75,921)		(72,820)		(3,101)
Total sales, net of blending and other expense (1) - continuing operations	$	377,033	$	381,331	$	(4,298)
Total sales - discontinued operations	—		544,979		(544,979)
Total sales, net of blending and other expense (1)	$	377,033	$	926,310	$	(549,277)

(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 $377.0 million for Q1/2026 compared to $381.3 million for Q1/2025. The decrease in total sales, net of blending and other expense reflects lower realized pricing partially offset by higher production in Q1/2026. The decrease in our realized pricing for Q1/2026 relative to Q1/2025 resulted in a $47.7 million decrease in total sales, net of blending and other expense, partially offset by higher production which contributed to a $43.4 million increase in total sales, net of blending and other expense.

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 months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands except for % and per boe)	2026			2025			Change
Royalties - continuing operations	$	51,589		$	59,256		$	(7,667)
Royalties - discontinued operations	—			148,681			(148,681)
Total royalties	$	51,589		$	207,937		$	(156,348)

Average royalty rate (1) - continuing operations	13.7		%	15.5		%	(1.8)		%
Average royalty rate (1) - discontinued operations	—		%	27.3		%	(27.3)		%
Total average royalty rate (1)	13.7		%	22.4		%	(8.7)		%

Royalties per boe (3) - continuing operations	$	8.25		$	10.55		$	(2.30)
Royalties per boe (3) - discontinued operations	$	—		$	20.19		$	(20.19)
Total royalties per boe (3)	$	8.25		$	16.02		$	(7.77)

(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 $51.6 million or 13.7% of total sales, net of blending and other expense for Q1/2026 compared to $59.3 million or 15.5% for Q1/2025. Total royalty expense was lower for Q1/2026 due to lower total sales, net of blending and other expense, relative to Q1/2025. Our average royalty rate of 13.7% for Q1/2026 is slightly below our annual guidance of approximately 15% for 2026.

OPERATING EXPENSE


	Three Months Ended March 31
($ thousands except for per boe)	2026		2025		Change
Operating expense - continuing operations	$	81,244	$	75,580	$	5,664
Operating expense - discontinued operations	—		72,123		(72,123)
Total operating expense	$	81,244	$	147,703	$	(66,459)

Operating expense per boe (1) - continuing operations	$	12.99	$	13.46	$	(0.47)
Operating expense per boe (1) - discontinued operations	$	—	$	9.79	$	(9.79)
Total operating expense per boe (1)	$	12.99	$	11.38	$	1.61

(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 $81.2 million ($12.99/boe) for Q1/2026 compared to $75.6 million ($13.46/boe) for Q1/2025. Operating expense for continuing operations for Q1/2026 increased compared to Q1/2025 due to increased production over the same period while per unit operating expense decreased due to lower carbon tax compliance costs in Q1/2026.

Operating expense of $12.99/boe for Q1/2026 is slightly below our annual guidance range of $13.75 - $14.25/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 months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands except for per boe)	2026		2025		Change
Transportation expense - continuing operations	$	23,134	$	18,779	$	4,355
Transportation expense - discontinued operations	—		11,733		(11,733)
Total transportation expense	$	23,134	$	30,512	$	(7,378)

Transportation expense per boe (1) - continuing operations	$	3.70	$	3.34	$	0.36
Transportation expense per boe (1) - discontinued operations	$	—	$	1.59	$	(1.59)
Total transportation expense per boe (1)	$	3.70	$	2.35	$	1.35

(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 ($3.70/boe) for Q1/2026 compared to $18.8 million ($3.34/boe) for Q1/2025. The increase in transportation expense for Q1/2026 reflects higher heavy oil production relative to Q1/2025. Transportation expense of $3.70/boe for Q1/2026 is consistent with expectations and slightly above our annual guidance range of $3.40 - $3.60/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 $75.9 million for Q1/2026 compared to $72.8 million for Q1/2025. Blending and other expense for Q1/2026 was higher than Q1/2025 as heavy oil production was higher over the same period.

FINANCIAL DERIVATIVES

As part of our normal operations, our business is exposed to fluctuations in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we 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 as new contracts are entered into.

The following table summarizes the results of our financial derivative contracts for the three months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands)	2026		2025		Change
Realized financial derivatives gain (loss)
Crude oil	$	(29,891)	$	(834)	$	(29,057)
Natural gas	602		640		(38)

Total	$	(29,289)	$	(194)	$	(29,095)
Unrealized financial derivatives gain (loss)
Crude oil	$	(122,070)	$	(34,041)	$	(88,029)
Natural gas	603		(15,384)		15,987


Total	$	(121,467)	$	(49,425)	$	(72,042)
Total financial derivatives gain (loss)
Crude oil	$	(151,961)	$	(34,875)	$	(117,086)
Natural gas	1,205		(14,744)		15,949


Total	$	(150,756)	$	(49,619)	$	(101,137)

We recorded total financial derivatives losses of $150.8 million for Q1/2026 compared to $49.6 million for Q1/2025. The realized financial derivatives loss of $29.3 million for Q1/2026 was primarily a result of the market prices for crude oil settling at levels above those set in our derivative contracts following the increase in benchmark oil prices in March 2026. The unrealized financial derivatives loss of $121.5 million for Q1/2026 is primarily due to the increase in forecasted crude oil pricing used to revalue outstanding volumes on crude oil contracts in place at March 31, 2026, which were entered into prior to the sale of our U.S. operations, relative to December 31, 2025. The fair value of our financial derivative contracts resulted in a net liability of $95.0 million at March 31, 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 May 7, 2026.

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for the three months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ per boe except for volume)	2026		2025		Change
Daily production (boe/d) - continuing operations	69,478		62,380		11		%
Daily production (boe/d) - discontinued operations	—		81,814		(100)		%
Total production (boe/d)	69,478		144,194		(52)		%

Operating netback:
Total sales, net of blending and other expense (1)	$	60.30	$	67.92	$	(7.62)
Less:
Royalties (2)	(8.25)		(10.55)		2.30
Operating expense (2)	(12.99)		(13.46)		0.47
Transportation expense (2)	(3.70)		(3.34)		(0.36)
Operating netback (1) - continuing operations	$	35.36	$	40.57	$	(5.21)
Operating netback (1) - discontinued operations	—		42.44		(42.44)
Operating netback (1)	$	35.36	$	41.63	$	(6.27)
Realized financial derivatives loss (3)	(4.68)		(0.01)		(4.67)
Operating netback after financial derivatives (1)	$	30.68	$	41.62	$	(10.94)

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

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

Our operating netback for continuing operations of $35.36/boe for Q1/2026 was lower than $40.57/boe for Q1/2025 due to the decrease in our realized price which resulted in lower per unit sales net of royalties. Combined operating and transportation expense for Q1/2026 was consistent with the same period of 2025. Our operating netback after financial derivatives of $30.68/boe for Q1/2026 was lower than $41.62/boe for Q1/2025 due to lower realized pricing along with a higher realized financial derivatives loss in Q1/2026 compared to Q1/2025.

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 months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands except for per boe)	2026		2025 (1)		Change
Gross G&A expense - continuing operations	$	24,231	$	20,624	$	3,607
Overhead recoveries - continuing operations	(1,932)		(2,058)		126
G&A expense - continuing operations	$	22,299	$	18,566	$	3,733
G&A expense - discontinued operations (2)	—		7,040		(7,040)
Total G&A expense	$	22,299	$	25,606	$	(3,307)

G&A expense per boe (3) - continuing operations	$	3.57	$	3.31	$	0.26
G&A expense per boe (3) - discontinued operations	$	—	$	0.96	$	(0.96)
Total G&A expense per boe (3)	$	3.57	$	1.97	$	1.60

(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 $22.3 million ($3.57/boe) for Q1/2026 compared to $18.6 million ($3.31/boe) for Q1/2025. G&A expense for continuing operations includes severance and other non-recurring costs related to staff reductions in Canada of approximately $5.5 million which resulted in higher G&A expense for Q1/2026 compared to Q1/2025.

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 months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands except for per boe)	2026		2025 (1)		Change
Interest on credit facilities	$	887	$	3,337	$	(2,450)
Interest on long-term notes	1,719		40,279		(38,560)
Interest on lease obligations	1,095		325		770
Interest income	(6,455)		(350)		(6,105)
Net cash interest (income) expense	$	(2,754)	$	43,591	$	(46,345)
Amortization of debt issue costs	516		2,378		(1,862)
Accretion of asset retirement obligations	5,038		4,598		440

Early redemption expense	297		—		297
Net financing and interest expense - continuing operations	$	3,097	$	50,567	$	(47,470)
Net financing and interest expense - discontinued operations	—		4,679		(4,679)
Total net financing and interest expense	$	3,097	$	55,246	$	(52,149)



Net financing and interest expense per boe (2) - continuing operations	$	0.50	$	9.01	$	(8.51)

Net financing and interest expense per boe (2) - discontinued operations	$	—	$	0.64	$	(0.64)

Total net financing and interest expense per boe (2)	$	0.50	$	4.26	$	(3.76)

(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 $3.1 million ($0.50/boe) for Q1/2026 compared to $50.6 million ($9.01/boe) for Q1/2025. Lower net financing and interest expense for Q1/2026 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 $2.8 million for Q1/2026 compared to expense of $43.6 million for Q1/2025. 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 Q1/2026. Interest on our credit facilities for Q1/2026 reflects the standby fees rate of 0.5% compared to the weighted average interest rate of 6.9% for Q1/2025. Interest income for Q1/2026 reflects interest earned on cash deposits held in high-interest savings accounts during the period.

Accretion of asset retirement obligations of $5.0 million for Q1/2026 was consistent with $4.6 million for Q1/2025. Amortization of debt issue costs of $0.5 million for Q1/2026 was lower than $2.4 million for Q1/2025 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 $0.7 million for Q1/2026 compared to $0.1 million for Q1/2025.

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 months ended March 31, 2026 and 2025.


	Three Months Ended March 31
($ thousands except for per boe)	2026		2025 (1)		Change


Depletion and depreciation - continuing operations	$	123,690	$	116,743	$	6,947
Depletion and depreciation - discontinued operations	—		203,180		(203,180)
Total depletion and depreciation	$	123,690	$	319,923	$	(196,233)

Depletion and depreciation per boe (2) - continuing operations	$	19.78	$	20.79	$	(1.01)
Depletion and depreciation per boe (2) - discontinued operations	$	—	$	27.59	$	(27.59)
Total depletion and depreciation per boe (2)	$	19.78	$	24.65	$	(4.87)

(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 $123.7 million ($19.78/boe) for Q1/2026 compared to $116.7 million ($20.79/boe) for Q1/2025. Depletion and depreciation expense for continuing operations was higher in Q1/2026 relative to Q1/2025 due to higher production which was partially offset by a reduction to the depletion rate of our oil and gas properties at Q1/2026.

IMPAIRMENT

We assessed our oil and gas properties and exploration and evaluation assets for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of our cash generating units at March 31, 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 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 $22.9 million for Q1/2026 for our continuing operations compared to $0.4 million for Q1/2025. The increase for Q1/2026 primarily reflects the Company's share price, which increased the value of the awards resulting in higher SBC expense relative to Q1/2025. The total expense for Q1/2026 for continuing operations is comprised of $18.0 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 March 31
($ thousands except for exchange rates)	2026		2025		Change
Unrealized foreign exchange loss (gain)	$	1,630	$	(3,475)	$	5,105
Realized foreign exchange loss (gain)	304		(403)		707
Foreign exchange loss (gain) - continuing operations	$	1,934	$	(3,878)	$	5,812


CAD/USD exchange rates:
At beginning of period	1.3715		1.4405
At end of period	1.3956		1.4379

We recorded a foreign exchange loss for continuing operations of $1.9 million for Q1/2026 compared to a gain of $3.9 million for Q1/2025.

The unrealized foreign exchange loss for continuing operations of $1.6 million for Q1/2026 is related to changes in the reported amount of our U.S. dollar denominated long-term notes due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2026 compared to December 31, 2025. The unrealized foreign exchange gain of $3.5 million for Q1/2025 is related to changes in the reported amount of our long-term notes and credit facilities due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2025 compared to 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 $0.3 million for Q1/2026 compared to a gain of $0.4 million for Q1/2025.

INCOME TAXES


	Three Months Ended March 31
($ thousands)	2026		2025 (1)		Change
Current income tax expense	$	—	$	947	$	(947)
Deferred income tax (recovery) expense	(24,253)		8,362		(32,615)
Income tax (recovery) expense - continuing operations	$	(24,253)	$	9,309	$	(33,562)
Income tax expense - discontinued operations	$	—	$	11,454	$	(11,454)

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

We did not record current income tax for continuing operations in Q1/2026 and recorded an expense of $0.9 million for Q1/2025.

We recorded a deferred income tax recovery for continuing operations of $24.3 million for Q1/2026 compared to expense of $8.4 million for Q1/2025. The deferred tax recovery for Q1/2026 reflects a net loss from continuing operations.

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

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During 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 (LOSS) AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three months ended March 31, 2026 and 2025 are set forth in the following table.


	Three Months Ended March 31
($ thousands)	2026		2025 (1)		Change
Petroleum and natural gas sales	$	452,954	$	454,151	$	(1,197)
Royalties	(51,589)		(59,256)		7,667
Revenue, net of royalties	401,365		394,895		6,470

Expenses
Operating	(81,244)		(75,580)		(5,664)
Transportation	(23,134)		(18,779)		(4,355)
Blending and other	(75,921)		(72,820)		(3,101)
Operating netback (2)	$	221,066	$	227,716	$	(6,650)
General and administrative	(22,299)		(18,566)		(3,733)
Net cash interest income (expense)	2,754		(43,591)		46,345
Realized financial derivatives loss	(29,289)		(194)		(29,095)
Realized foreign exchange (loss) gain	(304)		403		(707)
Cash other expense	(1,704)		(2,396)		692
Current income tax expense	—		(947)		947
Cash share-based compensation	(18,013)		(413)		(17,600)
Adjusted funds flow (3)	$	152,211	$	162,012	$	(9,801)

Exploration and evaluation	(665)		(107)		(558)
Depletion and depreciation	(123,690)		(116,743)		(6,947)
Non-cash share-based compensation	(4,857)		—		(4,857)
Non-cash financing and interest	(5,851)		(6,976)		1,125

Unrealized financial derivatives loss	(121,467)		(49,425)		(72,042)
Unrealized foreign exchange (loss) gain	(1,630)		3,475		(5,105)
Gain (loss) on dispositions	2,017		(1,229)		3,246

Deferred income tax recovery (expense)	24,253		(8,362)		32,615
Net loss from continuing operations	$	(79,679)	$	(17,355)	$	(62,324)
Net income from discontinued operations	12,353		86,946		(74,593)
Net (loss) income	$	(67,326)	$	69,591	$	(136,917)

(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 of $152.2 million for Q1/2026 compared to $162.0 million for Q1/2025. Adjusted funds flow for Q1/2026 includes realized financial derivatives losses of $29.3 million due to benchmark oil prices above our contracted prices and cash share-based compensation expense of $18.0 million due to an increase in our share price. We recorded net cash interest income in Q1/2026, reflecting interest earned on cash deposits held in high-interest savings accounts and lower interest expense from the repayment of the majority of our debt following the U.S. disposition in Q4/2025.

We reported a net loss from continuing operations of $79.7 million for Q1/2026 compared to $17.4 million for Q1/2025. The increase in net loss for Q1/2026 relative to Q1/2025 is primarily a result of an unrealized financial derivatives loss of $121.5 million driven by the sharp increase in near-term oil prices in March 2026.

CAPITAL EXPENDITURES

Capital expenditures for the three months ended March 31, 2026 and 2025 are summarized as follows.


	Three Months Ended March 31
($ thousands)	2026		2025	Change

Drilling, completion and equipping	$	121,580			$	167,478	$	(45,898)
Facilities and other	23,432				16,841		6,591
Exploration and development expenditures - continuing operations	$	145,012			$	184,319	$	(39,307)
Exploration and development expenditures - discontinued operations	—				220,778		(220,778)
Total exploration and development expenditures	$	145,012			$	405,097	$	(260,085)

Property acquisitions - continuing operations	$	8,127			$	469	$	7,658
Proceeds from dispositions - continuing operations	$	40			$	(2,677)	$	2,717
Property acquisitions - discontinued operations	$	—			$	788	$	(788)
Proceeds from dispositions - discontinued operations	$	(13,153)			$	411	$	(13,564)

Exploration and development expenditures for continuing operations were $145.0 million in Q1/2026 which is $39.3 million lower compared to $184.3 million in Q1/2025. Exploration and development expenditures for Q1/2026 included costs associated with drilling 58 (52.5 net) wells along with 54 (52.7 net) wells that were brought on production compared to drilling 90 (85.5 net) wells along with 77 (75.0 net) wells brought on production during Q1/2025. We also invested $23.4 million on facilities and other expenditures during Q1/2026.

Exploration and development expenditures of $145.0 million for Q1/2026 were consistent with expectations and our annual guidance for 2026 of approximately $625 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 through strategic acquisitions. Baytex assesses its capital structure in response to operational requirements and changes in economic conditions. At March 31, 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 debt levels. There is no certainty that any of these additional sources of capital would be available if required.

At March 31, 2026 we had net cash(1) of $591.2 million compared to $765.8 million at December 31, 2025. The decrease in net cash from December 31, 2025 reflects shareholder returns of $190.9 million during Q1/2026 which includes share buybacks and quarterly dividends.

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

Credit Facilities

At March 31, 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 March 31, 2026.

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

At March 31, 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 following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2026.


Covenant Description	Position as at March 31, 2026	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0:0:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	5.5:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	0.1:1.0	4.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at March 31, 2026, the Company's Senior Secured Debt totaled $4.4 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expense, income taxes, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 2026 was $661.0 million.

(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expense, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Financing and interest expense for the twelve months ended March 31, 2026 was $119.4 million.

(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, lease obligations, deferred income tax liability, and financial derivative liabilities. As at March 31, 2026, the Company's Total Debt totaled $93.9 million of principal amounts outstanding.

Long-Term Notes

During Q1/2026, 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 March 31, 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 three months ended March 31, 2026, we issued 0.1 million common shares pursuant to our share-based compensation program. As at March 31, 2026, we had 730.6 million common shares issued and outstanding and no preferred shares issued and outstanding. As at May 7, 2026, there were 723.4 million common shares issued and outstanding and no preferred shares issued and outstanding.

During the three months ended March 31, 2026, we repurchased 35.1 million common shares under our normal course issuer bid ("NCIB") at an average price of $4.96 per share for total consideration of $174.3 million. At March 31, 2026, we had 28.4 million shares remaining on our NCIB which expires on July 2, 2026. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase its common shares through the NYSE and other U.S. based trading systems.

During the three months ended March 31, 2026, we recorded a $3.4 million charge to shareholders’ capital related to the federal tax on equity repurchases (December 31, 2025 - $0.5 million).

On January 2 and April 1, 2026, we paid a quarterly cash dividend of $0.0225 per share to shareholders of record. On May 7, 2026, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on July 2, 2026 to shareholders of record on June 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 March 31, 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
Credit facilities - principal (1)	$	—	$	—	$	—	$	—	$	—
Long-term notes - principal	89,507		—		—		—		89,507
Interest on long-term notes	39,353		6,601		13,202		13,202		6,348
Lease obligations - principal	95,646		14,792		22,290		17,823		40,741
Processing agreements	4,733		799		543		529		2,862
Transportation agreements	74,851		36,035		32,439		3,355		3,022
Total	$	304,090	$	58,227	$	68,474	$	34,909	$	142,480

(1) The Credit Facilities were undrawn at March 31, 2026.

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 March 31, 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)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Petroleum and natural gas sales	452,954	759,815	927,648	886,579	999,130	1,017,017	1,074,623	1,133,123
Net (loss) income - continuing operations (1)	(79,679)	(334,057)	(28,451)	103,018	(17,355)	(124,903)	96,204	13,751
Per common share - basic	(0.11)	(0.43)	(0.04)	0.13	(0.02)	(0.16)	0.12	0.02
Per common share - diluted	(0.11)	(0.43)	(0.04)	0.13	(0.02)	(0.16)	0.12	0.02
Net (loss) income	(67,326)	(856,887)	31,968	151,549	69,591	(38,477)	185,219	103,898
Per common share - basic	(0.09)	(1.12)	0.04	0.20	0.09	(0.05)	0.23	0.13
Per common share - diluted	(0.09)	(1.12)	0.04	0.20	0.09	(0.05)	0.23	0.13
Adjusted funds flow (2)	151,125	261,531	422,232	366,919	463,870	461,886	537,947	532,839
Per common share - basic	0.20	0.34	0.55	0.48	0.60	0.59	0.68	0.65
Per common share - diluted	0.20	0.34	0.55	0.48	0.60	0.59	0.67	0.65
Free cash flow (3)	1,705	76,486	142,688	3,188	52,529	254,838	220,159	180,673
Per common share - basic	—	0.10	0.19	—	0.07	0.33	0.28	0.22
Per common share - diluted	—	0.10	0.18	—	0.07	0.33	0.28	0.22
Cash flows from operating activities	122,203	227,657	472,676	354,312	431,317	468,865	550,042	505,584
Per common share - basic	0.16	0.30	0.62	0.46	0.56	0.60	0.69	0.62
Per common share - diluted	0.16	0.30	0.61	0.46	0.56	0.60	0.69	0.62
Dividends declared	16,606	17,268	17,326	17,304	17,289	17,598	17,732	18,161
Per common share	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225
Exploration and development	145,012	174,078	270,364	356,532	405,097	198,177	306,332	339,573
Canada	145,012	92,720	123,579	147,734	184,319	108,971	120,473	101,916
U.S. (4)	—	81,358	146,785	208,798	220,778	89,206	185,859	237,657
Property acquisitions	8,127	5,544	24,024	1,193	1,257	12,621	1,042	3,349
Proceeds from dispositions	(13,113)	(3,012,058)	(8,254)	(725)	(2,266)	(42,339)	(1,436)	(2,695)
Net (cash) debt (2)	(591,151)	(765,785)	2,244,358	2,293,940	2,390,250	2,417,172	2,493,269	2,639,014
Total assets	3,252,692	3,345,414	7,601,389	7,552,013	7,824,576	7,759,745	7,614,157	7,770,926
Common shares outstanding	730,561	765,568	768,317	768,317	770,039	773,590	787,328	804,977

Daily production
Total production (boe/d)	69,478	137,087	150,950	148,095	144,194	152,894	154,468	154,194
Canada (boe/d)	69,478	67,295	68,185	64,167	62,380	65,332	64,668	63,688
U.S. (boe/d) (4)	—	69,792	82,765	83,928	81,814	87,562	89,800	90,506

Benchmark prices
WTI oil (US$/bbl)	71.93	59.14	64.93	63.74	71.42	70.27	75.10	80.57
WCS heavy oil ($/bbl)	79.28	66.88	75.14	74.10	84.33	80.77	83.98	91.72
Edmonton par oil ($/bbl)	93.50	76.49	86.20	84.15	95.27	94.98	97.91	105.30
AECO 7A natural gas ($/mcf)	2.49	2.34	1.00	2.07	2.02	1.46	0.81	1.44
CAD/USD avg exchange rate	1.3716	1.3949	1.3774	1.3840	1.4350	1.3992	1.3636	1.3684


Total sales, net of blending and other expense ($/boe) (3)	60.30	56.28	63.22	61.16	71.38	66.60	71.97	75.93
Royalties ($/boe) (5)	(8.25)	(11.54)	(13.05)	(13.16)	(16.02)	(14.69)	(15.75)	(17.14)
Operating expense ($/boe) (5)	(12.99)	(12.51)	(11.54)	(11.95)	(11.38)	(10.36)	(11.76)	(11.95)
Transportation expense ($/boe) (5)	(3.70)	(2.43)	(2.54)	(2.44)	(2.35)	(2.35)	(2.60)	(2.37)
Operating netback ($/boe) (3)	35.36	29.80	36.09	33.61	41.63	39.20	41.86	44.47
Financial derivatives (loss) gain ($/boe) (5)	(4.68)	0.08	(0.62)	(0.88)	(0.01)	(0.15)	0.02	(0.16)
Operating netback after financial derivatives ($/boe) (3)	30.68	29.88	35.47	32.73	41.62	39.05	41.88	44.31

(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 69,478 boe/d in Q1/2026 reflects our Canadian operations following the Eagle Ford disposition in Q4/2025. Our successful light and heavy oil development programs in Canada for Q1/2026 resulted in production growth to 69,478 boe/d from 63,688 boe/d in Q2/2024 despite the disposition of certain thermal assets in Q4/2024.

Benchmark prices for crude oil declined from Q2/2024 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 due to supply disruptions related to the conflict in Iran and resulted in realized pricing of $60.30/boe for Q1/2026 and operating netback after financial derivatives of $30.68/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 $151.1 million and cash flows from operating activities of $122.2 million for Q1/2026 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 $591.2 million at Q1/2026 compared to a net debt position of $2.6 billion at Q2/2024. The change in net (cash) debt also reflects free cash flow(2) of $932.3 million generated in the period since Q2/2024, along with $557.3 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 March 31, 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 three months ended March 31, 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.

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 March 31
($ thousands)	2026		2025
Petroleum and natural gas sales	$	452,954	$	454,151
Light oil and condensate (1)	(88,993)		(99,469)
NGL (1)	(8,560)		(7,888)
Natural gas (1)	(8,664)		(8,083)
Heavy oil	$	346,737	$	338,711
Blending and other expense (2)	(75,921)		(72,820)
Heavy oil, net of blending and other expense - continuing operations	$	270,816	$	265,891

(1)Component of petroleum and natural gas sales. See Note 14 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three months ended March 31, 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 provide price certainty on a portion of our production.

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


	Three Months Ended March 31
($ thousands)	2026		2025
Petroleum and natural gas sales	$	452,954	$	454,151
Blending and other expense	(75,921)		(72,820)
Total sales, net of blending and other expense	377,033		381,331
Royalties	(51,589)		(59,256)
Operating expense	(81,244)		(75,580)
Transportation expense	(23,134)		(18,779)
Operating netback - continuing operations	$	221,066	$	227,716
Realized financial derivatives loss (1)	(29,289)		(194)
Operating netback after realized financial derivatives - continuing operations	$	191,777	$	227,522

(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 months ended March 31, 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 March 31
($ thousands)	2026		2025
Cash flows from operating activities	$	122,203	$	431,317
Change in non-cash working capital	26,303		29,034
Additions to exploration and evaluation assets	(1,737)		—
Additions to oil and gas properties	(143,275)		(405,097)
Payments on lease obligations	(1,789)		(2,725)

Free cash flow	$	1,705	$	52,529

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 provide price certainty 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)	March 31, 2026		December 31, 2025
Credit facilities	$	—	$	1,138
Unamortized debt issuance costs - Credit facilities (1)	—		262
Long-term notes	87,598		93,834
Unamortized debt issuance costs - Long-term notes (1)	1,909		2,113
Trade payables	303,107		236,373
Share-based compensation liability	25,748		34,802
Dividends payable	16,606		17,268

Cash	(757,869)		(953,113)
Trade receivables	(194,985)		(135,230)
Prepaids and other assets	(59,091)		(63,232)
Inventory	(14,174)		—
Net cash	$	(591,151)	$	(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 months ended March 31, 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 March 31
($ thousands)	2026		2025
Cash flow from operating activities	$	122,203	$	431,317
Change in non-cash working capital	26,303		29,034
Asset retirement obligations settled	2,619		3,519

Adjusted funds flow	$	151,125	$	463,870

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 months ended March 31, 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 intend 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.