Document

Baytex Energy Corp.

Q2 2025 MD&A 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2025 and 2024

Dated July 31, 2025

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2025. This information is provided as of July 31, 2025. 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 six months ended June 30, 2025 ("Q2/2025" and "YTD 2025") have been compared with the results for the three and six months ended June 30, 2024 ("Q2/2024" and "YTD 2024"). 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 six months ended June 30, 2025, its audited comparative consolidated financial statements for the years ended December 31, 2024 and 2023, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2024. 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 debt" 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 North American focused oil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operated assets in Texas.

SECOND QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q2/2025. Production of 148,095 boe/d and exploration and development expenditures of $356.5 million for Q2/2025 were consistent with our full-year plan and reflect our successful development programs in the U.S. and Canada. In the U.S., we successfully completed two refracs on our operated Eagle Ford properties that extend inventory duration and improve capital efficiencies. In Canada, we achieved record well performance in our Duvernay light oil operations and delivered a 7% increase in production from our heavy oil properties.

We spent $356.5 million on exploration and development expenditures in Q2/2025, compared to $339.6 million in Q2/2024 and consistent with our full year plans to spend approximately $1.2 billion. In the U.S., we invested $208.8 million and production averaged 83,928 boe/d during Q2/2025 compared to exploration and development expenditures of $237.7 million and production of 90,506 boe/d for Q2/2024. In Canada, we invested $147.7 million and generated production of 64,167 boe/d in Q2/2025 compared to exploration and development expenditures of $101.9 million and production of 63,688 boe/d in Q2/2024.

Oil prices were volatile during Q2/2025 due to geopolitical events along with concerns over global economic conditions. The WTI benchmark price for Q2/2025 was US$63.74/bbl which was lower than Q2/2024 when WTI averaged US$80.57/bbl. Adjusted funds flow(1) of $366.9 million and cash flows from operating activities of $354.3 million for Q2/2025 were primarily a result of lower realized pricing compared to Q2/2024 when we generated adjusted funds flow of $532.8 million and cash flows from operating activities of $505.6 million.

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

Baytex Energy Corp.

Q2 2025 MD&A 2

Net debt(1) of $2.3 billion at June 30, 2025 was $123.2 million lower than at December 31, 2024. Free cash flow(2) of $55.7 million generated in YTD 2025 was allocated to debt repayment along with $51.4 million of shareholder returns including share buybacks and quarterly dividends. We expect net debt to decline over the remainder of 2025 as we continue to allocate free cash flow to the balance sheet after funding our dividend.

(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.

2025 GUIDANCE

We continue to execute our 2025 plan and anticipate full year production of approximately 148,000 boe/d and exploration and development expenditures of approximately $1.2 billion, consistent with our previous guidance. We have fine-tuned several of our cost assumptions to reflect lower production and lower commodity prices. The following table compares our 2025 annual guidance to our YTD 2025 results.

2025 Annual Guidance (1)

Revised Annual Guidance

YTD 2025 Results

Exploration and development expenditures

$1.2 - $1.3 billion

~ $1.2 billion

$761.6 million

Production (boe/d)

148,000 - 152,000 (2)

~148,000

146,156

Expenses:

Average royalty rate (3)

~ 23%

~ 22%

22.0

Operating (4)

$11.75 - $12.50/boe

no change

$11.67/boe

Transportation (4)

$2.40 - $2.55/boe

no change

$2.40/boe

General and administrative (4)

$90 million ($1.67/boe) (5)

$95 million ($1.76/boe)

$47.8 million ($1.81/boe)

Cash interest (4)

$180 million ($3.33/boe) (5)

no change

$91.7 million ($3.46/boe)

Current income tax

~ 1% of EBITDA (6)

no change

0.7% of EBITDA (6)

Leasing expenditures

$10 million

$15 million

$6.4 million

Asset retirement obligations

$25 million

$20 million

$7.1 million

(1)As announced on December 3, 2024.

(2)As announced December 20, 2024 in conjunction with the Kerrobert Thermal asset sale.

(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)Refer to Operating Expense, Transportation Expense, General and Administrative Expense and Financing and Interest Expense sections of this MD&A for a description of the composition of these measures.

(5)Per boe amounts for general and administrative and cash interest have been updated to reflect the low end of the production guidance range.

(6)EBITDA is calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

Baytex Energy Corp.

Q2 2025 MD&A 3

RESULTS OF OPERATIONS

The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our operated and non-operated Eagle Ford assets in Texas.

Production


	Three Months Ended June 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	11,167		50,941		62,108		11,076		55,955		67,031
Heavy oil	42,959		—		42,959		43,703		—		43,703
Natural Gas Liquids (NGL)	2,986		16,962		19,948		2,309		17,858		20,167
Total liquids (bbl/d)	57,112		67,903		125,015		57,088		73,813		130,901
Natural gas (mcf/d)	42,331		96,151		138,482		39,599		100,165		139,764
Total production (boe/d)	64,167		83,928		148,095		63,688		90,506		154,194

Production Mix
Segment as a percent of total	43	%	57	%	100	%	41	%	59	%	100	%

Light oil and condensate	17	%	61	%	42	%	17	%	62	%	44	%
Heavy oil	67	%	—	%	29	%	69	%	—	%	28	%
NGL	5	%	20	%	13	%	4	%	20	%	13	%
Natural gas	11	%	19	%	16	%	10	%	18	%	15	%

	Six Months Ended June 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	11,469		50,752		62,221		11,285		55,249		66,534
Heavy oil	41,583		—		41,583		42,131		—		42,131
Natural Gas Liquids (NGL)	3,054		16,445		19,499		2,470		17,263		19,733
Total liquids (bbl/d)	56,106		67,197		123,303		55,886		72,512		128,398
Natural gas (mcf/d)	43,033		94,081		137,114		41,990		102,069		144,059
Total production (boe/d)	63,279		82,877		146,156		62,884		89,523		152,407

Production Mix
Segment as a percent of total	43	%	57	%	100	%	41	%	59	%	100	%

Light oil and condensate	18	%	61	%	43	%	18	%	62	%	44	%
Heavy oil	66	%	—	%	28	%	67	%	—	%	28	%
NGL	5	%	20	%	13	%	4	%	19	%	13	%
Natural gas	11	%	19	%	16	%	11	%	19	%	15	%

Production was 148,095 boe/d for Q2/2025 and 146,156 boe/d for YTD 2025 compared to 154,194 boe/d for Q2/2024 and 152,407 boe/d for YTD 2024 which reflects lower development on our non-operated Eagle Ford assets and the disposition of non-core heavy oil assets in Q4/2024.

Baytex Energy Corp.

Q2 2025 MD&A 4

In Canada, production was 64,167 boe/d for Q2/2025 and 63,279 boe/d for YTD 2025 compared to 63,688 boe/d for Q2/2024 and 62,884 boe/d for YTD 2024. Our successful light and heavy oil development programs resulted in production that was 479 boe/d higher for Q2/2025 and 395 boe/d higher for YTD 2025 relative to the same periods of 2024 despite the disposition of 2,000 boe/d of heavy oil production from the Kerrobert thermal assets in Q4/2024.

In the U.S., production was 83,928 boe/d for Q2/2025 and 82,877 for YTD 2025 compared to 90,506 boe/d for Q2/2024 and 89,523 boe/d for YTD 2024. Lower production for both periods of 2025 reflects reduced non-operated Eagle Ford activity in late 2024 and early 2025. We initiated production from 19 (14.9 net) wells during Q2/2025 and 46 (30.6 net) wells during YTD 2025 compared to 30 (14.8 net) wells during Q2/2024 and 67 (37.2 net) wells during YTD 2024.

Total production of 146,156 boe/d for YTD 2025 is consistent with expectations. We are expecting production of approximately 148,000 boe/d for 2025 which reflects average production of approximately 150,000 boe/d over the second half of 2025.

COMMODITY PRICES

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

Crude Oil

During Q2/2025 and YTD 2025, global benchmark prices for crude oil were lower compared to the same periods of 2024 as a result of increasing supply, geopolitical events and concerns over slowing global economic activity. The WTI benchmark price averaged US$63.74/bbl for Q2/2025 and US$67.58/bbl for YTD 2025 compared to US$80.57/bbl for Q2/2024 and US$78.77/bbl for YTD 2024.

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf Coast. The MEH benchmark averaged US$65.56/bbl during Q2/2025 and US$69.47/bbl during YTD 2025 compared to US$83.10/bbl for Q2/2024 and US$81.03/bbl for YTD 2024, and typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$1.82/bbl for Q2/2025 and US$1.89/bbl for YTD 2025 compared to premiums of US$2.53/bbl for Q2/2024 and US$2.26/bbl for YTD 2024.

Prices for Canadian oil trade at a discount to WTI due to a lack of 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. Canadian oil differentials were narrower in Q2/2025 and YTD 2025 relative to both periods of 2024 after exports commenced from the TMX pipeline expansion in May 2024.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $84.15/bbl during Q2/2025 and $89.71/bbl during YTD 2025 compared to $105.30/bbl during Q2/2024 and $98.73/bbl during YTD 2024. Edmonton par traded at a discount to WTI of US$2.94/bbl for Q2/2025 and $3.93/bbl for YTD 2025 compared to a discount of US$3.62/bbl for Q2/2024 and $6.10/bbl for YTD 2024.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q2/2025 averaged $74.10/bbl and $79.15/bbl for YTD 2025 compared to $91.72/bbl for Q2/2024 and $84.68/bbl for YTD 2024. The WCS heavy oil differential to WTI was US$10.20/bbl in Q2/2025 and US$11.43/bbl in YTD 2025 compared to US$13.55/bbl for Q2/2024 and US$16.44/bbl for YTD 2024.

Natural Gas

Natural gas prices in Canada and the U.S. were higher in both periods of 2025 compared to 2024 and reflect incremental demand from cold winter weather and lower inventory levels.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$3.44/mmbtu for Q2/2025 and US$3.55/mmbtu for YTD 2025 compared to US$1.89/mmbtu for Q2/2024 and US$2.07/mmbtu for YTD 2024.

In Canada, we receive natural gas pricing based on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $2.07/mcf during Q2/2025 and $2.05/mcf for YTD 2025 which is higher than $1.44/mcf for Q2/2024 and $1.74/mcf for YTD 2024.

Baytex Energy Corp.

Q2 2025 MD&A 5

The following tables compare select benchmark prices and our average realized selling prices for the three and six months ended June 30, 2025 and 2024.


	Three Months Ended June 30			Six Months Ended June 30
	2025	2024	Change	2025	2024	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	63.74	80.57	(16.83)	67.58	78.77	(11.19)
MEH oil (US$/bbl) (2)	65.56	83.10	(17.54)	69.47	81.03	(11.56)
MEH oil differential to WTI (US$/bbl)	1.82	2.53	(0.71)	1.89	2.26	(0.37)
Edmonton par oil ($/bbl) (3)	84.15	105.30	(21.15)	89.71	98.73	(9.02)
Edmonton par oil differential to WTI (US$/bbl)	(2.94)	(3.62)	0.68	(3.93)	(6.10)	2.17
WCS heavy oil ($/bbl) (4)	74.10	91.72	(17.62)	79.15	84.68	(5.53)
WCS heavy oil differential to WTI (US$/bbl)	(10.20)	(13.55)	3.35	(11.43)	(16.44)	5.01
AECO natural gas ($/mcf) (5)	2.07	1.44	0.63	2.05	1.74	0.31
NYMEX natural gas (US$/mmbtu) (6)	3.44	1.89	1.55	3.55	2.07	1.48
CAD/USD average exchange rate	1.3840	1.3684	0.0156	1.4095	1.3586	0.0509

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

(2)MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.

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

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

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

(6)NYMEX refers to the NYMEX last day average index price as published by the CGPR.


	Three Months Ended June 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	82.54	$	86.73	$	85.98	$	103.21	$	109.71	$	108.64
Heavy oil, net of blending and other expense ($/bbl) (2)	64.43		—		64.43		82.29		—		82.29
NGL ($/bbl) (1)	22.93		26.17		25.68		24.48		27.30		26.98
Natural gas ($/mcf) (1)	1.73		3.78		3.16		1.23		2.37		2.04
Total sales, net of blending and other expense ($/boe) (2)	$	59.71	$	62.26	$	61.16	$	76.07	$	75.83	$	75.93

	Six Months Ended June 30
	2025						2024
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	88.32	$	93.68	$	92.69	$	97.02	$	105.87	$	104.37
Heavy oil, net of blending and other expense ($/bbl) (2)	68.79		—		68.79		74.07		—		74.07
NGL ($/bbl) (1)	25.54		28.95		28.42		25.61		26.71		26.57
Natural gas ($/mcf) (1)	1.89		4.33		3.57		1.86		2.37		2.22
Total sales, net of blending and other expense ($/boe) (2)	$	63.74	$	68.03	$	66.17	$	69.29	$	73.19	$	71.58

(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.

Baytex Energy Corp.

Q2 2025 MD&A 6

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $61.16/boe for Q2/2025 and $66.17/boe for YTD 2025 compared to $75.93/boe for Q2/2024 and $71.58/boe for YTD 2024. Our average realized sales price decreased due to lower WTI pricing partially offset by narrower Canadian oil differentials, higher natural gas prices and improved NGL realizations.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) represents a discount to the Edmonton par price of $1.61/bbl for Q2/2025 and $1.39/bbl for YTD 2025 which is consistent with discounts of $2.09/bbl in Q2/2024 and $1.71/bbl in YTD 2024.

The price received for our U.S. light oil and condensate production is based on the MEH benchmark. Expressed in U.S. dollars, our realized light oil and condensate price(2) represents a discount to MEH of US$2.89/bbl for Q2/2025 and $3.01/bbl for YTD 2025 consistent with a discount of US$2.93/bbl for Q2/2024 and $3.10/bbl for YTD 2024.

Our realized heavy oil price, net of blending and other expense(1) was lower in Q2/2025 and YTD 2025 compared to the same periods of 2024 which reflects the decrease in WCS benchmark pricing. Our realized pricing for Q2/2025 and YTD 2025 represents a discount to the WCS benchmark of $9.67/bbl and $10.36/bbl compared to $9.43/bbl and $10.61/bbl for the same periods of 2024.

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(2) was 29% of WTI in Q2/2025 and 30% of WTI in YTD 2025, which reflects strong ethane pricing compared to 24% of WTI in Q2/2024 and 25% of WTI for YTD 2024.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. The increase in AECO and NYMEX benchmark prices for Q2/2025 and YTD 2025 resulted in higher realized natural gas pricing in Canada and the U.S. relative to both periods of 2024.

(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.

(2)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.

Baytex Energy Corp.

Q2 2025 MD&A 7

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended June 30
	2025						2024
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	83,876	$	402,046	$	485,922	$	104,030	$	558,620	$	662,650
Heavy oil	314,254		—		314,254		394,960		—		394,960
NGL	6,232		40,390		46,622		5,144		44,366		49,510
Total oil sales	404,362		442,436		846,798		504,134		602,986		1,107,120
Natural gas sales	6,674		33,107		39,781		4,426		21,577		26,003
Total petroleum and natural gas sales	411,036		475,543		886,579		508,560		624,563		1,133,123
Blending and other expense	(62,381)		—		(62,381)		(67,685)		—		(67,685)
Total sales, net of blending and other expense (1)	$	348,655	$	475,543	$	824,198	$	440,875	$	624,563	$	1,065,438

	Six Months Ended June 30
	2025						2024
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	183,344	$	860,540	$	1,043,884	$	199,251	$	1,064,514	$	1,263,765
Heavy oil	652,965		—		652,965		699,884		—		699,884
NGL	14,121		86,178		100,299		11,513		83,928		95,441
Total oil sales	850,430		946,718		1,797,148		910,648		1,148,442		2,059,090
Natural gas sales	14,757		73,804		88,561		14,225		44,000		58,225
Total petroleum and natural gas sales	865,187		1,020,522		1,885,709		924,873		1,192,442		2,117,315
Blending and other expense	(135,201)		—		(135,201)		(131,893)		—		(131,893)
Total sales, net of blending and other expense (1)	$	729,986	$	1,020,522	$	1,750,508	$	792,980	$	1,192,442	$	1,985,422

Total sales, net of blending and other expense, was $824.2 million for Q2/2025 and $1.8 billion for YTD 2025 compared to $1.1 billion for Q2/2024 and $2.0 billion for YTD 2024. The decrease in total sales, net of blending and other expense reflects lower realized pricing and lower production in both periods of 2025 compared to 2024.

In Canada, total sales, net of blending and other expense, of $348.7 million for Q2/2025 and $730.0 million for YTD 2025 decreased from $440.9 million reported for Q2/2024 and $793.0 million for YTD 2024. The decrease in benchmark prices in Q2/2025 and YTD 2025 relative to Q2/2024 and YTD 2024 was the primary factor that resulted in lower total sales, net of blending and other expense over the same periods.

In the U.S., total petroleum and natural gas sales of $475.5 million for Q2/2025 and $1.0 billion for YTD 2025 decreased from $624.6 million reported for Q2/2024 and $1.2 billion for YTD 2024. Lower realized pricing resulted in a $103.6 million decrease in total sales in Q2/2025 relative to Q2/2024 while lower production contributed to a $45.4 million decrease in total sales relative to Q2/2024. Lower realized pricing resulted in a $77.3 million decrease in total sales in YTD 2025 relative to YTD 2024 while lower production contributed to a $94.6 million decrease in total sales relative to YTD 2024.

Baytex Energy Corp.

Q2 2025 MD&A 8

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 six months ended June 30, 2025 and 2024.


	Three Months Ended June 30
	2025									2024
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	47,800		$	129,590		$	177,390		$	72,894		$	167,546		$	240,440
Average royalty rate (1)(2)	13.7		%	27.3		%	21.5		%	16.5		%	26.8		%	22.6		%
Royalties per boe (3)	$	8.19		$	16.97		$	13.16		$	12.58		$	20.34		$	17.14

	Six Months Ended June 30
	2025									2024
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	107,056		$	278,271		$	385,327		$	129,458		$	320,153		$	449,611
Average royalty rate (1)(2)	14.7		%	27.3		%	22.0		%	16.3		%	26.8		%	22.6		%
Royalties per boe (3)	$	9.35		$	18.55		$	14.57		$	11.31		$	19.65		$	16.21

(1)Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.

(3)Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period.

Royalties for Q2/2025 were $177.4 million or 21.5% of total sales, net of blending and other expense, compared to $240.4 million or 22.6% for Q2/2024. Total royalties for YTD 2025 were $385.3 million or 22.0% of total sales, net of blending and other expense, compared to $449.6 million or 22.6% for YTD 2024. Total royalty expense was lower for Q2/2025 and YTD 2025 due to lower total

sales, net of blending and other expense, relative to the same periods of 2024.

Our average royalty rate in Canada of 13.7% for Q2/2025 and 14.7% for YTD 2025 was lower than 16.5% for Q2/2024 and 16.3% for YTD 2024 due to lower benchmark commodity prices. In the U.S., our average royalty rate was 27.3% for both periods of 2025 which was relatively consistent with 26.8% for both periods of 2024.

Our average royalty rate of 22.0% for YTD 2025 is consistent with expectations and we have updated our annual guidance to approximately 22% for 2025.

Baytex Energy Corp.

Q2 2025 MD&A 9

OPERATING EXPENSE


	Three Months Ended June 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	88,035	$	72,985	$	161,020	$	84,415	$	83,290	$	167,705
Operating expense per boe (1)	$	15.08	$	9.56	$	11.95	$	14.57	$	10.11	$	11.95

	Six Months Ended June 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	163,615	$	145,108	$	308,723	$	169,818	$	171,322	$	341,140
Operating expense per boe (1)	$	14.29	$	9.67	$	11.67	$	14.84	$	10.51	$	12.30

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

Total operating expense was $161.0 million ($11.95/boe) for Q2/2025 and $308.7 million ($11.67/boe) for YTD 2025 compared to $167.7 million ($11.95/boe) for Q2/2024 and $341.1 million ($12.30/boe) for YTD 2024. Total operating expense for both periods of 2025 decreased relative to 2024 due to lower production while per unit operating costs were relatively consistent over the same periods.

In Canada, total operating expense was $88.0 million ($15.08/boe) for Q2/2025 and $163.6 million ($14.29/boe) for YTD 2025 compared to $84.4 million ($14.57/boe) for Q2/2024 and $169.8 million ($14.84/boe) for YTD 2024. Operating expense in Canada for Q2/2025 has increased with higher production relative to Q2/2024 while per unit operating expense of $15.08/boe for Q2/2025 and $14.29/boe for YTD 2025 was relatively consistent with $14.57/boe for Q2/2024 and $14.84/boe for YTD 2024.

In the U.S., operating expense was $73.0 million ($9.56/boe) for Q2/2025 and $145.1 million ($9.67/boe) for YTD 2025 which was lower than $83.3 million ($10.11/boe) for Q2/2024 and $171.3 million ($10.51/boe) for YTD 2024. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$6.91/boe for Q2/2025 and US$6.86/boe for YTD 2025 which was lower than US$7.39/boe for Q2/2024 and US$7.74/boe for YTD 2024. The decrease in total and per unit operating expense reflects our cost savings initiatives and lower production in both periods of 2025 compared to 2024.

Operating expense of $11.67/boe for YTD 2025 is consistent with expectations and slightly below our annual guidance range of $11.75 - $12.50/boe for 2025.

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 six months ended June 30, 2025 and 2024.


	Three Months Ended June 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	20,544	$	12,363	$	32,907	$	19,569	$	13,745	$	33,314
Transportation expense per boe (1)	$	3.52	$	1.62	$	2.44	$	3.38	$	1.67	$	2.37

	Six Months Ended June 30
	2025						2024
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	39,323	$	24,096	$	63,419	$	37,779	$	25,370	$	63,149
Transportation expense per boe (1)	$	3.43	$	1.61	$	2.40	$	3.30	$	1.56	$	2.28

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

Transportation expense was $32.9 million ($2.44/boe) for Q2/2025 and $63.4 million ($2.40/boe) for YTD 2025 consistent with $33.3 million ($2.37/boe) for Q2/2024 and $63.1 million ($2.28/boe) for YTD 2024.

Baytex Energy Corp.

Q2 2025 MD&A 10

Per unit transportation expense of $2.40/boe for YTD 2025 is consistent with expectations and our annual guidance range of $2.40 - $2.55/boe for 2025.

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 $62.4 million for Q2/2025 and $135.2 million for YTD 2025 compared to $67.7 million for Q2/2024 and $131.9 million for YTD 2024. Blending and other expense for Q2/2025 was comparable to Q2/2024 and YTD 2024 as heavy oil production was relatively consistent over the same periods.

FINANCIAL DERIVATIVES

Our business is exposed to fluctuations in commodity prices, foreign exchange rates, interest rates and changes in our share price. We utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow caused by these exposures. 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 executed. The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2025 and 2024.


	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2025		2024		Change		2025		2024		Change
Realized financial derivatives gain (loss)
Crude oil	$	(12,448)	$	(4,847)	$	(7,601)	$	(13,281)	$	(3,900)	$	(9,381)
Natural gas	574		2,590		(2,016)		1,213		7,131		(5,918)

Total	$	(11,874)	$	(2,257)	$	(9,617)	$	(12,068)	$	3,231	$	(15,299)
Unrealized financial derivatives gain (loss)
Crude oil	$	18,426	$	13,476	$	4,950	$	(15,615)	$	(17,989)	$	2,374
Natural gas	12,111		(2,686)		14,797		(3,273)		(3,571)		298


Total	$	30,537	$	10,790	$	19,747	$	(18,888)	$	(21,560)	$	2,672
Total financial derivatives gain (loss)
Crude oil	$	5,978	$	8,629	$	(2,651)	$	(28,896)	$	(21,889)	$	(7,007)
Natural gas	12,685		(96)		12,781		(2,060)		3,560		(5,620)


Total	$	18,663	$	8,533	$	10,130	$	(30,956)	$	(18,329)	$	(12,627)

We recorded a total financial derivatives gain of $18.7 million for Q2/2025 and a loss of $31.0 million for YTD 2025 compared to a gain of $8.5 million for Q2/2024 and a loss of $18.3 million for YTD 2024. The realized financial derivatives loss of $12.1 million for YTD 2025 resulted from losses of $13.3 million on crude oil contracts and gains of $1.2 million on natural gas contracts. The unrealized financial derivatives loss of $18.9 million for YTD 2025 resulted from a $15.6 million loss on crude oil contracts and a $3.3 million loss on natural gas contracts. The fair value of our financial derivative contracts resulted in a net asset of $5.0 million at June 30, 2025 compared to a net asset of $23.9 million at December 31, 2024.

Refer to Note 16 of the consolidated financial statements for a complete listing of our outstanding contracts at July 31, 2025.

Baytex Energy Corp.

Q2 2025 MD&A 11

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and six months ended June 30, 2025 and 2024.


	Three Months Ended June 30
	2025						2024
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	64,167		83,928		148,095		63,688		90,506		154,194
Operating netback:
Total sales, net of blending and other expense (1)	$	59.71	$	62.26	$	61.16	$	76.07	$	75.83	$	75.93
Less:
Royalties (2)	(8.19)		(16.97)		(13.16)		(12.58)		(20.34)		(17.14)
Operating expense (2)	(15.08)		(9.56)		(11.95)		(14.57)		(10.11)		(11.95)
Transportation expense (2)	(3.52)		(1.62)		(2.44)		(3.38)		(1.67)		(2.37)
Operating netback (1)	$	32.92	$	34.11	$	33.61	$	45.54	$	43.71	$	44.47
Realized financial derivatives loss (3)	—		—		(0.88)		—		—		(0.16)
Operating netback after financial derivatives (1)	$	32.92	$	34.11	$	32.73	$	45.54	$	43.71	$	44.31

	Six Months Ended June 30
	2025						2024
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	63,279		82,877		146,156		62,884		89,523		152,407
Operating netback:
Total sales, net of blending and other expense (1)	$	63.74	$	68.03	$	66.17	$	69.29	$	73.19	$	71.58
Less:
Royalties (2)	(9.35)		(18.55)		(14.57)		(11.31)		(19.65)		(16.21)
Operating expense (2)	(14.29)		(9.67)		(11.67)		(14.84)		(10.51)		(12.30)
Transportation expense (2)	(3.43)		(1.61)		(2.40)		(3.30)		(1.56)		(2.28)
Operating netback (1)	$	36.67	$	38.20	$	37.53	$	39.84	$	41.47	$	40.79
Realized financial derivatives (loss) gain (3)	—		—		(0.46)		—		—		0.12
Operating netback after financial derivatives (1)	$	36.67	$	38.20	$	37.07	$	39.84	$	41.47	$	40.91

(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 of $33.61/boe for Q2/2025 and $37.53/boe for YTD 2025 was lower than $44.47/boe for Q2/2024 and $40.79/boe for YTD 2024 due to the decrease in our realized price which resulted in lower per unit sales net of royalties. Total operating and transportation expense for Q2/2025 and YTD 2025 was consistent with the same periods of 2024. Our operating netback net of realized gains and losses on financial derivatives was $32.73/boe for Q2/2025 and $37.07/boe for YTD 2025 was lower than $44.31/boe for Q2/2024 and $40.91/boe for YTD 2024 due to the decrease in realized prices.

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. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.

Baytex Energy Corp.

Q2 2025 MD&A 12

The following table summarizes our G&A expense for the three and six months ended June 30, 2025 and 2024.


	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2025		2024		Change		2025		2024		Change
Gross general and administrative expense	$	28,859	$	27,064	$	1,795	$	61,522	$	55,827	$	5,695
Overhead recoveries	(6,639)		(6,058)		(581)		(13,696)		(12,409)		(1,287)
General and administrative expense	$	22,220	$	21,006	$	1,214	$	47,826	$	43,418	$	4,408
General and administrative expense per boe (1)	$	1.65	$	1.50	$	0.15	$	1.81	$	1.57	$	0.24

(1)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.

G&A expense was $22.2 million ($1.65/boe) for Q2/2025 and $47.8 million ($1.81/boe) for YTD 2025 compared to $21.0 million ($1.50/boe) for Q2/2024 and $43.4 million ($1.57/boe) for YTD 2024. G&A expense of $47.8 million ($1.81/boe) for YTD 2025 is consistent with expectations and our revised 2025 annual guidance of approximately $95.0 million ($1.76/boe) which reflects the timing of certain costs and our expectations for production over the remainder of 2025.

FINANCING AND INTEREST EXPENSE

Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, 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 six months ended June 30, 2025 and 2024.


	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2025		2024		Change		2025		2024		Change
Interest on credit facilities	$	6,855	$	15,639	$	(8,784)	$	13,038	$	33,928	$	(20,890)
Interest on long-term notes	37,683		37,656		27		77,962		72,334		5,628
Interest on lease obligations	337		651		(314)		662		964		(302)
Cash interest	$	44,875	$	53,946	$	(9,071)	$	91,662	$	107,226	$	(15,564)
Accretion of debt issue costs	3,926		7,862		(3,936)		6,736		10,922		(4,186)
Accretion of asset retirement obligations	5,667		5,459		208		11,316		10,386		930
Gain on repurchase and cancellation of long-term notes	(2,755)		—		(2,755)		(2,755)		—		(2,755)
Early redemption expense	—		24,350		(24,350)		—		24,350		(24,350)
Financing and interest expense	$	51,713	$	91,617	$	(39,904)	$	106,959	$	152,884	$	(45,925)
Cash interest per boe (1)	$	3.33	$	3.84	$	(0.51)	$	3.46	$	3.87	$	(0.41)
Financing and interest expense per boe (1)	$	3.84	$	6.53	$	(2.69)	$	4.04	$	5.51	$	(1.47)

(1)Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period.

Financing and interest expense was $51.7 million ($3.84/boe) for Q2/2025 and $107.0 million ($4.04/boe) for YTD 2025 compared to $91.6 million ($6.53/boe) for Q2/2024 and $152.9 million ($5.51/boe) for YTD 2024. The decrease for both periods of 2025 is due to lower outstanding debt balances for YTD 2025 and early redemption expense recognized in Q2/2024 related to the redemption of the 8.75% senior notes.

Cash interest of $44.9 million ($3.33/boe) for Q2/2025 and $91.7 million ($3.46/boe) for YTD 2025 was lower than $53.9 million ($3.84/boe) for Q2/2024 and $107.2 million ($3.87/boe) for YTD 2024. Lower interest on our credit facilities reflects lower debt balances outstanding in both periods of 2025, while higher interest on long-term notes is a result of additional principal amounts outstanding after the issuance of the 7.375% Senior Notes in Q2/2024. The weighted average interest rate applicable on our credit facilities was 6.5% for Q2/2025 and 6.6% for YTD 2025 compared to 7.9% for Q2/2024 and 8.0% for YTD 2024.

Accretion of asset retirement obligations of $5.7 million for Q2/2025 and $11.3 million for YTD 2025 was consistent with $5.5 million for Q2/2024 and $10.4 million for YTD 2024. Accretion of debt issue costs of $3.9 million for Q2/2025 and $6.7 million for YTD 2025 was lower than $7.9 million for Q2/2024 and $10.9 million for YTD 2024. In Q2/2024, we recorded $24.4 million of early redemption expense related to the redemption of the 8.75% senior notes.

Baytex Energy Corp.

Q2 2025 MD&A 13

Cash interest expense of $91.7 million ($3.46/boe) for YTD 2025 is consistent with our expectations and our 2025 annual guidance of $180 million ($3.33/boe) as we expect to reduce debt over the remainder of 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 was $0.5 million for Q2/2025 and $0.6 million for YTD 2025 compared to $0.6 million for Q2/2024 and $0.7 million for YTD 2024.

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 six months ended June 30, 2025 and 2024.


	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2025		2024		Change		2025		2024		Change
Depletion	$	318,187	$	349,718	$	(31,531)	$	634,030	$	691,153	$	(57,123)
Depreciation	3,972		3,383		589		8,052		6,085		1,967
Depletion and depreciation	$	322,159	$	353,101	$	(30,942)	$	642,082	$	697,238	$	(55,156)
Depletion and depreciation per boe (1)	$	23.90	$	25.16	$	(1.26)	$	24.27	$	25.14	$	(0.87)

(1)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.

Depletion and depreciation expense was $322.2 million ($23.90/boe) for Q2/2025 and $642.1 million ($24.27/boe) for YTD 2025 compared to $353.1 million ($25.16/boe) for Q2/2024 and $697.2 million ($25.14/boe) for YTD 2024. Total depletion and depreciation expense and depletion and depreciation per boe were lower in Q2/2025 and YTD 2025 relative to Q2/2024 and YTD 2024 due to lower production and a decrease in future development costs for proved plus probable reserves which resulted in a lower depletable base for our oil and gas properties during 2025.

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 June 30, 2025 and December 31, 2024.

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 $1.6 million for Q2/2025 and $2.3 million for YTD 2025 compared to $5.6 million for Q2/2024 and $15.1 million for YTD 2024. SBC expense for Q2/2025 and YTD 2025 reflects a decrease in the Company's share price which resulted in lower SBC expense relative to the same periods of 2024.

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.

Baytex Energy Corp.

Q2 2025 MD&A 14


	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for exchange rates)	2025		2024		Change		2025		2024		Change
Unrealized foreign exchange (gain) loss	$	(100,792)	$	19,189	$	(119,981)	$	(104,267)	$	57,907	$	(162,174)
Realized foreign exchange loss (gain)	206		866		(660)		(197)		2,085		(2,282)
Foreign exchange (gain) loss	$	(100,586)	$	20,055	$	(120,641)	$	(104,464)	$	59,992	$	(164,456)
CAD/USD exchange rates:
At beginning of period	1.4379		1.3533				1.4405		1.3205
At end of period	1.3622		1.3687				1.3622		1.3687

We recorded a foreign exchange gain of $100.6 million for Q2/2025 and $104.5 million for YTD 2025 compared to losses of $20.1 million for Q2/2024 and $60.0 million for YTD 2024.

The unrealized foreign exchange gain of $100.8 million for Q2/2025 and $104.3 million for YTD 2025 is related to changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities due to the strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2025 compared to March 31, 2025 and December 31, 2024. The unrealized foreign exchange loss of $19.2 million for Q2/2024 and $57.9 million for YTD 2024 is related to changes in the reported amount of our long-term notes and credit facilities due to a weakening of the Canadian dollar relative to the U.S. dollar at June 30, 2024 compared to March 31, 2024 and December 31, 2023.

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 functional currency entities. We recorded a realized foreign exchange loss of $0.2 million for Q2/2025 and a gain of $0.2 million for YTD 2025 compared to losses of $0.9 million for Q2/2024 and $2.1 million for YTD 2024.

INCOME TAXES


	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2025		2024		Change		2025		2024		Change
Current income tax expense	$	4,547	$	6,475	$	(1,928)	$	6,699	$	8,155	$	(1,456)
Deferred income tax expense	17,911		22,810		(4,899)		36,522		38,611		(2,089)
Total income tax expense	$	22,458	$	29,285	$	(6,827)	$	43,221	$	46,766	$	(3,545)

We recorded current income tax expense of $4.5 million for Q2/2025 and $6.7 million for YTD 2025 compared to $6.5 million for Q2/2024 and $8.2 million for YTD 2024. The current income tax expense for both periods of 2025 and 2024 primarily relates to repatriation and related taxes.

We recorded deferred income tax expense of $17.9 million for Q2/2025 and $36.5 million for YTD 2025 compared to $22.8 million for Q2/2024 and $38.6 million for YTD 2024. The deferred tax expense for Q2/2025 decreased compared to Q2/2024 as a result of unrecognized future capital gains on foreign exchange relative to the increase in income generated for the period.

On July 4, 2025, the U.S. enacted a budget reconciliation package known as the One Big Beautiful Bill Act of 2025 ("OBBBA") which includes both tax and non-tax provisions. The changes resulting from the tax provisions in OBBBA are not expected to have a material impact on the Company’s financial results.

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 Q4/2023, 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 reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $232.9 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

Baytex Energy Corp.

Q2 2025 MD&A 15

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 June 2025, the Department of Justice, legal counsel for the Crown, notified Baytex that they intend to abandon 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 for the three and six months ended June 30, 2025 and 2024 are set forth in the following table.


	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2025		2024		Change		2025		2024		Change
Petroleum and natural gas sales	$	886,579	$	1,133,123	$	(246,544)	$	1,885,709	$	2,117,315	$	(231,606)
Royalties	(177,390)		(240,440)		63,050		(385,327)		(449,611)		64,284
Revenue, net of royalties	709,189		892,683		(183,494)		1,500,382		1,667,704		(167,322)

Expenses
Operating	(161,020)		(167,705)		6,685		(308,723)		(341,140)		32,417
Transportation	(32,907)		(33,314)		407		(63,419)		(63,149)		(270)
Blending and other	(62,381)		(67,685)		5,304		(135,201)		(131,893)		(3,308)
Operating netback (1)	$	452,881	$	623,979	$	(171,098)	$	993,039	$	1,131,522	$	(138,483)
General and administrative	(22,220)		(21,006)		(1,214)		(47,826)		(43,418)		(4,408)
Cash interest	(44,875)		(53,946)		9,071		(91,662)		(107,226)		15,564
Realized financial derivatives (loss) gain	(11,874)		(2,257)		(9,617)		(12,068)		3,231		(15,299)
Realized foreign exchange gain (loss)	(206)		(866)		660		197		(2,085)		2,282
Cash other expense	(685)		(1,025)		340		(1,874)		(2,096)		222
Current income tax expense	(4,547)		(6,475)		1,928		(6,699)		(8,155)		1,456
Cash share-based compensation	(1,555)		(5,565)		4,010		(2,318)		(15,088)		12,770
Adjusted funds flow (2)	$	366,919	$	532,839	$	(165,920)	$	830,789	$	956,685	$	(125,896)
Transaction costs	—		—		—		—		(1,539)		1,539
Exploration and evaluation	(457)		(649)		192		(564)		(667)		103
Depletion and depreciation	(322,159)		(353,101)		30,942		(642,082)		(697,238)		55,156

Non-cash financing and interest	(6,838)		(37,671)		30,833		(15,297)		(45,658)		30,361

Unrealized financial derivatives gain (loss)	30,537		10,790		19,747		(18,888)		(21,560)		2,672
Unrealized foreign exchange gain (loss)	100,792		(19,189)		119,981		104,267		(57,907)		162,174
Gain (loss) on dispositions	666		(6,311)		6,977		(563)		(3,650)		3,087

Deferred income tax expense	(17,911)		(22,810)		4,899		(36,522)		(38,611)		2,089
Net income	$	151,549	$	103,898	$	47,651	$	221,140	$	89,855	$	131,285

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

We generated adjusted funds flow of $366.9 million for Q2/2025 and $830.8 million for YTD 2025 compared $532.8 million for Q2/2024 and $956.7 million for YTD 2024. The decrease in adjusted funds flow was primarily due to realized pricing that resulted in decreased revenues net of royalties partially offset by lower operating expense.

Baytex Energy Corp.

Q2 2025 MD&A 16

We reported net income of $151.5 million for Q2/2025 and $221.1 million for YTD 2025 compared to a net income of $103.9 million for Q2/2024 and $89.9 million for YTD 2024. The increase in net income for Q2/2025 and YTD 2025 is the result of lower depletion expense, non-cash financing and interest expense along with an unrealized foreign exchange gain.

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation loss of $247.4 million for Q2/2025 and $255.9 million for YTD 2025 relates to the change in value of our U.S. net assets and is due to a strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2025 compared to March 31, 2025 and December 31, 2024. The CAD/USD exchange rate was 1.3622 CAD/USD as at June 30, 2025 compared to 1.4379 CAD/USD at March 31, 2025 and 1.4405 CAD/USD at December 31, 2024.

CAPITAL EXPENDITURES

Capital expenditures for the three and six months ended June 30, 2025 and 2024 are summarized as follows.


	Three Months Ended June 30
	2025						2024
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	121,950	$	208,592	$	330,542	$	80,349	$	208,662	$	289,011
Facilities and other	25,784		206		25,990		21,567		28,995		50,562
Exploration and development expenditures	$	147,734	$	208,798	$	356,532	$	101,916	$	237,657	$	339,573
Property acquisitions	$	905	$	288	$	1,193	$	1,802	$	1,547	$	3,349
Proceeds from dispositions	$	(863)	$	138	$	(725)	$	157	$	(2,852)	$	(2,695)

	Six Months Ended June 30
	2025						2024
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	289,428	$	393,798	$	683,226	$	206,357	$	428,601	$	634,958
Facilities and other	42,625		35,778		78,403		53,685		63,481		117,166
Exploration and development expenditures	$	332,053	$	429,576	$	761,629	$	260,042	$	492,082	$	752,124
Property acquisitions	$	1,374	$	1,076	$	2,450	$	36,077	$	2,675	$	38,752
Proceeds from dispositions	$	(3,540)	$	549	$	(2,991)	$	132	$	(2,852)	$	(2,720)

Exploration and development expenditures were $356.5 million for Q2/2025 and $761.6 million for YTD 2025 compared to $339.6 million for Q2/2024 and $752.1 million for YTD 2024. Exploration and development expenditures in Q2/2025 and YTD 2025 reflect our active heavy and light oil development program in Canada along with lower non-operated Eagle Ford development in the U.S.

In Canada, exploration and development expenditures were $147.7 million in Q2/2025 and $332.1 million for YTD 2025 compared to $101.9 million in Q2/2024 and $260.0 million for YTD 2024. Drilling and completion spending of $122.0 million in Q2/2025 and $289.4 million for YTD 2025 was higher than the comparative periods of 2024 which reflects increased development activity on our light and heavy oil properties.

Total U.S. exploration and development expenditures were $208.8 million for Q2/2025 and $429.6 million for YTD 2025 compared to $237.7 million in Q2/2024 and $492.1 million for YTD 2024. The decrease in exploration and development expenditures for both periods of 2025 compared to the same periods of 2024 reflects lower development activity primarily on our non-operated Eagle Ford properties coupled with realized improvements in operated drilling and completion costs per completed lateral foot.

Exploration and development expenditures of $761.6 million for YTD 2025 were consistent with expectations. We expect exploration and development expenditures for 2025 to be approximately $1.2 billion.

Baytex Energy Corp.

Q2 2025 MD&A 17

CAPITAL RESOURCES AND LIQUIDITY

Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions and dispositions. We strive to actively manage our capital structure in response to changes in economic conditions. At June 30, 2025, our capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.

In order to manage our capital structure and liquidity, we 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.

Management of debt levels is a priority for Baytex in order to sustain operations and support our business strategy. Net debt(1) of $2.3 billion at June 30, 2025 was $123.2 million lower than $2.4 billion at December 31, 2024 which was primarily due to a strengthening Canadian dollar relative to the U.S. dollar and also reflects our allocation of free cash flow to debt repayment. At current commodity prices we have adjusted our shareholder returns to allocate free cash flow to debt repayment after funding our quarterly dividend.

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

Credit Facilities

At June 30, 2025, we had $333.5 million of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (the "Credit Facilities"). The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.

On June 27, 2025, we extended the maturity of the Credit Facilities from May 9, 2028 to June 27, 2029. There were no changes to the loan balances or financial covenants as a result of the amendment.

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 ("SOFR"), plus applicable margins. Advances under the Baytex Energy USA, Inc. Credit Facilities can be drawn in U.S. funds and bear interest at the bank's prime lending rate or SOFR, plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.5% for Q2/2025 and 6.6% for YTD 2025 compared to 7.9% for Q2/2024 and 8.0% for YTD 2024. The interest rate on our Credit Facilities has decreased with lower government benchmark rates.

At June 30, 2025, we had $5.1 million of outstanding letters of credit (December 31, 2024 - $5.8 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 June 30, 2025.


Covenant Description	Position as at June 30, 2025	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.2:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	10.8:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.1:1.0	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 June 30, 2025, the Company's Senior Secured Debt totaled $337.9 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 expenses, income tax, 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 acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended June 30, 2025 was $2.0 billion.

(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 acquisitions as if they had occurred at the beginning of the twelve month period. Financing and interest expense for the twelve months ended June 30, 2025 was $189.2 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, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at June 30, 2025, the Company's Total Debt totaled $2.2 billion of principal amounts outstanding.

Long-Term Notes

At June 30, 2025 we have two issuances of long-term notes outstanding with a total principal amount of $1.8 billion. The long-term notes do not contain any financial maintenance covenants.

On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be redeemable at par from April 30, 2028 to maturity.

On April 1, 2024, we issued US$575 million aggregate principal amount of senior unsecured notes due March 15, 2032 bearing interest at a rate of 7.375% per annum payable semi-annually ("7.375% Senior Notes"). The 7.375% Senior Notes 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.

During Q2/2025, Baytex repurchased and cancelled US$40.6 million principal of the 8.50% Senior Notes for US$38.8 million ($53.7 million) and recorded a gain of $2.8 million.

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 six months ended June 30, 2025, we issued 0.1 million common shares pursuant to our share-based compensation program. As at June 30, 2025, we had 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding. As at July 31, 2025, there were 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding.

Our shareholder returns framework includes common share repurchases and a quarterly dividend. During the six months ended June 30, 2025, we repurchased 5.4 million common shares under our normal course issuer bid ("NCIB") at an average price of $3.12 per share for total consideration of $16.8 million. In June 2025, we renewed our NCIB under which we are permitted to purchase for cancellation up to 66.2 million common shares over the 12-month period commencing July 2, 2025, which represents 10% of Baytex's public float, as defined by the Toronto Stock Exchange, as at June 18, 2025. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase its common shares through the New York Stock Exchange and other U.S.-based trading systems.

During the six months ended June 30, 2025, we recorded a $0.4 million liability related to the 2% federal tax on equity repurchases (December 31, 2024 - $4.3 million), which is charged to shareholders’ equity.

On January 2, April 1 and July 2, 2025 we paid a quarterly cash dividend of $0.0225 per share to shareholders of record. On July 31, 2025, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2025 to shareholders of record on September 15, 2025. 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 June 30, 2025 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	$	333,516	$	—	$	—	$	333,516	$	—
Long-term notes - principal	1,817,707		—		—		1,034,471		783,236
Interest on long-term notes (1)	812,924		145,694		291,387		276,933		98,910
Lease obligations - principal	35,766		15,204		12,893		6,853		816
Processing agreements	5,445		948		902		540		3,055
Transportation agreements	210,633		71,206		77,500		24,784		37,143
Total	$	3,215,991	$	233,052	$	382,682	$	1,677,097	$	923,160

(1)Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.

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.

Baytex Energy Corp.

Q2 2025 MD&A 18

QUARTERLY FINANCIAL INFORMATION


	2025		2024				2023
($ thousands, except per common share amounts)	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Petroleum and natural gas sales	886,579	999,130	1,017,017	1,074,623	1,133,123	984,192	1,065,515	1,163,010
Net income (loss)	151,549	69,591	(38,477)	185,219	103,898	(14,043)	(625,830)	127,430
Per common share - basic	0.20	0.09	(0.05)	0.23	0.13	(0.02)	(0.75)	0.15
Per common share - diluted	0.20	0.09	(0.05)	0.23	0.13	(0.02)	(0.75)	0.15
Adjusted funds flow (1)	366,919	463,870	461,886	537,947	532,839	423,846	502,148	581,623
Per common share - basic	0.48	0.60	0.59	0.68	0.65	0.52	0.60	0.68
Per common share - diluted	0.48	0.60	0.59	0.67	0.65	0.52	0.60	0.68
Free cash flow (2)	3,188	52,529	254,838	220,159	180,673	(88)	290,785	158,440
Per common share - basic	—	0.07	0.33	0.28	0.22	—	0.35	0.19
Per common share - diluted	—	0.07	0.33	0.28	0.22	—	0.35	0.18
Cash flows from operating activities	354,312	431,317	468,865	550,042	505,584	383,773	474,452	444,033
Per common share - basic	0.46	0.56	0.60	0.69	0.62	0.47	0.57	0.52
Per common share - diluted	0.46	0.56	0.60	0.69	0.62	0.47	0.57	0.52
Dividends declared	17,304	17,334	17,598	17,732	18,161	18,494	18,381	19,138
Per common share	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225	0.0225
Exploration and development	356,532	405,097	198,177	306,332	339,573	412,551	199,214	409,191
Canada	147,734	184,319	108,971	120,473	101,916	158,126	75,137	107,053
U.S.	208,798	220,778	89,206	185,859	237,657	254,425	124,077	302,138
Property acquisitions	1,193	1,257	12,621	1,042	3,349	35,403	33,923	4,277
Proceeds from dispositions	(725)	(2,266)	(42,339)	(1,436)	(2,695)	(25)	(159,745)	(226)
Net debt (1)	2,293,940	2,390,250	2,417,172	2,493,269	2,639,014	2,639,841	2,534,287	2,824,348
Total assets	7,552,013	7,824,576	7,759,745	7,614,157	7,770,926	7,717,495	7,460,931	8,946,181
Common shares outstanding	768,317	770,039	773,590	787,328	804,977	821,322	821,681	845,360

Daily production
Total production (boe/d)	148,095	144,194	152,894	154,468	154,194	150,620	160,373	150,600
Canada (boe/d)	64,167	62,380	65,332	64,668	63,688	62,081	64,744	63,289
U.S. (boe/d)	83,928	81,814	87,562	89,800	90,506	88,540	95,629	87,311

Benchmark prices
WTI oil (US$/bbl)	63.74	71.42	70.27	75.10	80.57	76.96	78.32	82.26
WCS heavy oil ($/bbl)	74.10	84.33	80.77	83.98	91.72	77.73	76.86	93.02
Edmonton par oil ($/bbl)	84.15	95.27	94.98	97.91	105.30	92.16	99.72	107.93
CAD/USD avg exchange rate	1.3840	1.4350	1.3992	1.3636	1.3684	1.3488	1.3619	1.3410
AECO natural gas ($/mcf)	2.07	2.02	1.46	0.81	1.44	2.05	2.66	2.39
NYMEX natural gas (US$/mmbtu)	3.44	3.65	2.79	2.16	1.89	2.24	2.88	2.55

Total sales, net of blending and other expense ($/boe) (2)	61.16	71.38	66.60	71.97	75.93	67.12	68.00	80.34
Royalties ($/boe) (3)	(13.16)	(16.02)	(14.69)	(15.75)	(17.14)	(15.26)	(15.49)	(17.33)
Operating expense ($/boe) (3)	(11.95)	(11.38)	(10.36)	(11.76)	(11.95)	(12.65)	(11.17)	(12.57)
Transportation expense ($/boe) (3)	(2.44)	(2.35)	(2.35)	(2.60)	(2.37)	(2.18)	(2.02)	(2.02)
Operating netback ($/boe) (2)	33.61	41.63	39.20	41.86	44.47	37.03	39.32	48.42
Financial derivatives (loss) gain ($/boe) (3)	(0.88)	(0.01)	(0.15)	0.02	(0.16)	0.40	0.84	0.15
Operating netback after financial derivatives ($/boe) (2)	32.73	41.62	39.05	41.88	44.31	37.43	40.16	48.57

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

(3)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.

Baytex Energy Corp.

Q2 2025 MD&A 19

Over the previous eight quarters, benchmark prices for crude oil have declined following increasing supply from OPEC+ and North American production growth along with concerns over slowing global economic activity. Our realized sales price of $80.34/boe for Q3/2023 was our strongest realized pricing in the most recent eight quarters and we reported a realized price of $61.16/boe for Q2/2025.

Production has increased from 150,600 boe/d in Q3/2023 and reached a high of 160,373 boe/d in Q4/2023 which reflects active development on our properties in the U.S. and Canada. We have completed several non-core dispositions in Canada and the pace of non-operated activity in the U.S. has moderated which has resulted in production of 148,095 boe/d in Q2/2025 due to our successful development programs in Canada and the U.S. 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 $366.9 million and cash flows from operating activities of $354.3 million for Q2/2025 reflect strong production results from our development plans in the U.S. and Canada.

Net debt can fluctuate on a quarterly basis depending on changes in our free cash flow, shareholder returns and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt(1) decreased to $2.3 billion at Q2/2025 from $2.8 billion at Q3/2023 which reflects free cash flow(2) of $1.0 billion generated in the period since Q3/2023, along with $492.3 million allocated to shareholder returns in addition to a stronger Canadian dollar at Q2/2025, which decreases the reported amount of our U.S. dollar denominated debt.

(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, 2024 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 June 30, 2025, 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 six months ended June 30, 2025. 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, 2024.

SPECIFIED FINANCIAL MEASURES

In this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of blending and other expense, heavy oil sales, net of blending and other expense, 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 debt" 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.

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Q2 2025 MD&A 20

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 in the following table.


	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2025		2024		2025		2024
Petroleum and natural gas sales	$	886,579	$	1,133,123	$	1,885,709	$	2,117,315
Light oil and condensate (1)	(485,922)		(662,650)		(1,043,884)		(1,263,765)
NGL (1)	(46,622)		(49,510)		(100,299)		(95,441)
Natural gas (1)	(39,781)		(26,003)		(88,561)		(58,225)
Heavy oil	$	314,254	$	394,960	$	652,965	$	699,884
Blending and other expense (2)	(62,381)		(67,685)		(135,201)		(131,893)
Heavy oil, net of blending and other expense	$	251,873	$	327,275	$	517,764	$	567,991

(1)Component of petroleum and natural gas sales. See Note 12 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and six months ended June 30, 2025 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.


	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2025		2024		2025		2024
Petroleum and natural gas sales	$	886,579	$	1,133,123	$	1,885,709	$	2,117,315
Blending and other expense	(62,381)		(67,685)		(135,201)		(131,893)
Total sales, net of blending and other expense	824,198		1,065,438		1,750,508		1,985,422
Royalties	(177,390)		(240,440)		(385,327)		(449,611)
Operating expense	(161,020)		(167,705)		(308,723)		(341,140)
Transportation expense	(32,907)		(33,314)		(63,419)		(63,149)
Operating netback	$	452,881	$	623,979	$	993,039	$	1,131,522
Realized financial derivatives (loss) gain (1)	(11,874)		(2,257)		(12,068)		3,231
Operating netback after realized financial derivatives	$	441,007	$	621,722	$	980,971	$	1,134,753

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 16 - Financial Instruments and Risk Management in the consolidated financial statements for the three and six months ended June 30, 2025 for further information.

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Q2 2025 MD&A 21

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 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 June 30				Six Months Ended June 30
($ thousands)	2025		2024		2025		2024
Cash flows from operating activities	$	354,312	$	505,584	$	785,629	$	889,357
Change in non-cash working capital	9,042		20,140		38,076		52,163
Additions to exploration and evaluation assets	(930)		—		(930)		—
Additions to oil and gas properties	(355,602)		(339,573)		(760,699)		(752,124)
Payments on lease obligations	(3,634)		(5,478)		(6,359)		(10,350)
Transaction costs	—		—		—		1,539

Free cash flow	$	3,188	$	180,673	$	55,717	$	180,585

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 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.

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.

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). 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 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 debt

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

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The following table summarizes our calculation of net debt.


	As at
($ thousands)	June 30, 2025		December 31, 2024
Credit facilities	$	317,310	$	324,346
Unamortized debt issuance costs - Credit facilities (1)	16,206		16,861
Long-term notes	1,776,647		1,932,890
Unamortized debt issuance costs - Long-term notes (1)	41,060		47,729
Trade payables	538,330		512,473
Share-based compensation liability	13,851		24,732
Dividends payable	17,304		17,598
Other long-term liabilities	19,751		20,887
Cash	(7,156)		(16,610)
Trade receivables	(363,507)		(387,266)
Prepaids and other assets	(75,856)		(76,468)
Net debt	$	2,293,940	$	2,417,172

(1)Unamortized debt issuance costs were obtained from Note 6 - Credit Facilities and Note 7 - Long-term Notes from the consolidated financial statements for the three and six months ended June 30, 2025. 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, asset retirements obligations settled during the applicable period, and transaction costs.

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


	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2025		2024		2025		2024
Cash flow from operating activities	$	354,312	$	505,584	$	785,629	$	889,357
Change in non-cash working capital	9,042		20,140		38,076		52,163
Asset retirement obligations settled	3,565		7,115		7,084		13,626
Transaction costs	—		—		—		1,539

Adjusted funds flow	$	366,919	$	532,839	$	830,789	$	956,685

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 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 such weaknesses were identified in, or that changes were made to, internal controls over financial reporting during the three months ended June 30, 2025.

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: we expect net debt to decline over the remainder of 2025; our 2025 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; 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

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Q2 2025 MD&A 23

time to time; our intent to fund certain 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; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; that we will have sufficient financial resources in the future to provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices (including as a result of tariffs); risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party operating our Eagle Ford properties; 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, 2024, 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.

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.