Document

EX-99.2 3 a992-q32024mda.htm EX-99.2 Document

Baytex Energy Corp.

Q3 2024 MD&A 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2024 and 2023

Dated October 31, 2024

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2024. This information is provided as of October 31, 2024. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and nine months ended September 30, 2024 ("Q3/2024" and "YTD 2024") have been compared with the results for the three and nine months ended September 30, 2023 ("Q3/2023" and "YTD 2023"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2024, its audited comparative consolidated financial statements for the years ended December 31, 2023 and 2022, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2023. 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.

On June 20, 2023, Baytex and Ranger Oil Corporation ("Ranger") completed a merger of the two companies (the "Merger") whereby Baytex acquired all of the issued and outstanding common shares of Ranger. The Merger increased our Eagle Ford scale and provided an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford. Production from the Ranger assets is approximately 80% weighted towards high netback light oil and liquids and is primarily operated which increased our ability to effectively allocate capital.

We issued 311.4 million common shares, paid $732.8 million in cash and assumed $1.1 billion of Ranger's net debt(1). The cash portion of the transaction was funded with an expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility ("Term Loan") (which was fully repaid and cancelled in August 2023) and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030.

THIRD QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q3/2024. Production of 154,468 boe/d for Q3/2024 reflects our successful development programs in the U.S. and Canada. We invested $306.3 million on exploration and development expenditures and generated free cash flow(2) of $220.2 million.

(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.

Baytex Energy Corp.

Q3 2024 MD&A 2

Exploration and development expenditures totaled $306.3 million in Q3/2024. In the U.S. we invested $185.9 million and production averaged 89,800 boe/d during Q3/2024 compared to exploration and development expenditures of $302.1 million and production of 87,311 boe/d for Q3/2023. In Canada, we invested $120.5 million and generated production of 64,668 boe/d in Q3/2024 compared to exploration and development expenditures of $107.1 million and production of 63,289 boe/d in Q3/2023.

Oil prices declined during Q3/2024 as a result of weaker demand, higher supply and global economic concerns. The WTI benchmark price for Q3/2024 was US$75.10/bbl which was lower than Q3/2023 when WTI averaged US$82.26/bbl. Despite higher production, lower realized pricing resulted in adjusted funds flow(1) of $537.9 million and cash flows from operating activities of $550.0 million for Q3/2024 compared to Q3/2023 when we generated adjusted funds flow of $581.6 million and cash flows from operating activities of $444.0 million.

Net debt(1) of $2.5 billion at September 30, 2024 was 2% lower than at December 31, 2023 which reflects our allocation of free cash flow to debt repayment in YTD 2024. Free cash flow(2) of $400.7 million generated in YTD 2024 was allocated to debt repayment along with $219.6 million of shareholder returns including share buybacks and quarterly dividends. The change in net debt also reflects the impact of a weaker Canadian dollar at September 30, 2024 on our U.S. dollar denominated debt along with $39.8 million of property acquisitions and $49.7 million of debt issuance costs incurred during YTD 2024. We expect net debt to decline over the remainder of 2024 as we continue to allocate 50% of free cash flow to the balance sheet.

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

2024 GUIDANCE

We continue to execute our 2024 plan and anticipate full year 2024 production of approximately 153,000 boe/d and exploration and development expenditures of approximately $1.25 billion, consistent with our previous guidance range.

The following table updates our 2024 guidance reflecting year-to-date results and our expectation for the fourth quarter.


	Annual Guidance (1)	2024 Revised Guidance
Exploration and development expenditures	$1.2 - $1.3 billion	~ $1.25 billion
Production (boe/d)	152,000 - 154,000	~ 153,000

Expenses:
Average royalty rate (2)	~ 23.0%	~ 22.5%
Operating (3)	$11.25 - $12.00/boe	~ $12.00/boe
Transportation (3)	$2.35 - $2.55/boe	~ $2.45/boe
General and administrative (3)	$92 million ($1.65/boe)	$85 million ($1.52/boe)
Cash interest (3)	$200 million ($3.58/boe)	no change
Current income tax (4)	$40 million ($0.72/boe)	$25 million ($0.45/boe)

Leasing expenditures	$12 million	$15 million
Asset retirement obligations	$30 million	no change

(1)As announced on July 25, 2024.

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

(4)Current income tax expense per boe is calculated as current income tax expense divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp.

Q3 2024 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 September 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	13,781		56,062		69,843		17,641		58,122		75,763
Heavy oil	42,759		—		42,759		35,204		—		35,204
Natural Gas Liquids (NGL)	2,533		17,303		19,836		2,102		15,902		18,004
Total liquids (bbl/d)	59,073		73,365		132,438		54,947		74,024		128,971
Natural gas (mcf/d)	33,566		98,609		132,175		50,058		79,722		129,780
Total production (boe/d)	64,668		89,800		154,468		63,289		87,311		150,600

Production Mix
Segment as a percent of total	42	%	58	%	100	%	42	%	58	%	100	%

Light oil and condensate	21	%	63	%	45	%	28	%	67	%	50	%
Heavy oil	66	%	—	%	28	%	56	%	—	%	23	%
NGL	4	%	19	%	13	%	3	%	18	%	12	%
Natural gas	9	%	18	%	14	%	13	%	15	%	15	%

	Nine Months Ended September 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	12,123		55,522		67,645		16,222		31,528		47,750
Heavy oil	42,342		—		42,342		34,076		—		34,076
Natural Gas Liquids (NGL)	2,491		17,276		19,767		1,804		9,514		11,318
Total liquids (bbl/d)	56,956		72,798		129,754		52,102		41,042		93,144
Natural gas (mcf/d)	39,162		100,907		140,069		47,077		49,710		96,787
Total production (boe/d)	63,483		89,616		153,099		59,948		49,327		109,275

Production Mix
Segment as a percent of total	41	%	59	%	100	%	55	%	45	%	100	%

Light oil and condensate	19	%	62	%	44	%	27	%	64	%	44	%
Heavy oil	67	%	—	%	28	%	57	%	—	%	31	%
NGL	4	%	19	%	13	%	3	%	19	%	10	%
Natural gas	10	%	19	%	15	%	13	%	17	%	15	%

Production was 154,468 boe/d for Q3/2024 and 153,099 boe/d for YTD 2024 compared to 150,600 boe/d for Q3/2023 and 109,275 boe/d for YTD 2023. Higher production in Q3/2024 relative to 2023 reflects our successful development programs in the U.S. and Canada. Production for YTD 2024 was higher than the same period of 2023 primarily due to production from the Eagle Ford properties acquired from Ranger in addition to our successful development programs in Canada.

Baytex Energy Corp.

Q3 2024 MD&A 4

In Canada, production was 64,668 boe/d for Q3/2024 and 63,483 boe/d for YTD 2024 compared to 63,289 boe/d for Q3/2023 and 59,948 boe/d for YTD 2023. Our successful light and heavy oil development programs resulted in a 1,379 boe/d increase in production for Q3/2024 and 3,535 boe/d for YTD 2024 relative to the same periods of 2023. Strong production results from our heavy oil development was partially offset by the disposition of4,000 boe/d of light oil Viking assets in December 2023.

In the U.S., production was 89,800 boe/d for Q3/2024 compared to 87,311 boe/d which reflects the results of our successful development programs. Production of 89,616 boe/d for YTD 2024 was higher than 49,327 boe/d for YTD 2023 due to production from the Merger with Ranger.

Total production of 153,099 boe/d for YTD 2024 is consistent with our revised annual guidance of approximately 153,000 boe/d.

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

Global benchmark pricing for crude oil declined during Q3/2024, influenced by weaker demand, higher supply and global economic concerns. The WTI benchmark price averaged US$75.10/bbl for Q3/2024 and US$77.54/bbl for YTD 2024 compared to US$82.26/bbl for Q3/2023 and US$77.39/bbl for YTD 2023.

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$77.50/bbl during Q3/2024 and US$79.85/bbl during YTD 2024 compared to US$84.10/bbl for Q3/2023 and US$78.84/bbl for YTD 2023 and typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$2.40/bbl and US$2.31/bbl for Q3/2024 and YTD 2024 compared to premiums of US$1.84/bbl and US$1.45/bbl for Q3/2023 and YTD 2023, respectively. The MEH benchmark traded at a higher premium to WTI in both periods of 2024 as a result of additional demand at the U.S. Gulf Coast.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets 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 continued to narrow during Q3/2024 after exports commenced from the TMX pipeline expansion in May 2024. Delays in the TMX expansion resulted in increased pipeline apportionment and additional light and heavy crude oil inventories in the Western Canadian Sedimentary Basin earlier in 2024, which caused wider differentials for YTD 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 $97.91/bbl during Q3/2024 and $98.46/bbl during YTD 2024 compared to $107.93/bbl during Q3/2023 and $100.70/bbl during YTD 2023. Edmonton par traded at a discount to WTI of US$3.30/bbl for Q3/2024 and US$5.16/bbl for YTD 2024 compared to a discount of US$1.78/bbl for Q3/2023 and US$2.54/bbl for YTD 2023.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q3/2024 and YTD 2024 averaged $83.98/bbl and $84.45/bbl respectively, compared to $93.02/bbl and $80.47/bbl for the same periods of 2023. The WCS heavy oil differential to WTI was US$13.51/bbl in Q3/2024 and US$15.46/bbl in YTD 2024 compared to US$12.89/bbl for Q3/2023 and US$17.57/bbl in YTD 2023.

Natural Gas

Natural gas prices in Canada and the U.S. were lower in 2024 relative to 2023 after mild winter weather across most of North America resulted in weak natural gas demand and elevated 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$2.16/mmbtu for Q3/2024 and US$2.10/mmbtu for YTD 2024 compared to US$2.55/mmbtu for Q3/2023 and US$2.69/mmbtu for YTD 2023.

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 $0.81/mcf during Q3/2024 and $1.43/mcf during YTD 2024, lower than $2.39/mcf for Q3/2023 and $3.03/mcf for YTD 2023.

Baytex Energy Corp.

Q3 2024 MD&A 5

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30			Nine Months Ended September 30
	2024	2023	Change	2024	2023	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	75.10	82.26	(7.16)	77.54	77.39	0.15
MEH oil (US$/bbl) (2)	77.50	84.10	(6.60)	79.85	78.84	1.01
MEH oil differential to WTI (US$/bbl)	2.40	1.84	0.56	2.31	1.45	0.86
Edmonton par oil ($/bbl) (3)	97.91	107.93	(10.02)	98.46	100.70	(2.24)
Edmonton par oil differential to WTI (US$/bbl)	(3.30)	(1.78)	(1.52)	(5.16)	(2.54)	(2.62)
WCS heavy oil ($/bbl) (4)	83.98	93.02	(9.04)	84.45	80.47	3.98
WCS heavy oil differential to WTI (US$/bbl)	(13.51)	(12.89)	(0.62)	(15.46)	(17.57)	2.11
AECO natural gas ($/mcf) (5)	0.81	2.39	(1.58)	1.43	3.03	(1.60)
NYMEX natural gas (US$/mmbtu) (6)	2.16	2.55	(0.39)	2.10	2.69	(0.59)
CAD/USD average exchange rate	1.3636	1.3410	0.0226	1.3603	1.3453	0.0150

(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 September 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	96.58	$	101.82	$	100.78	$	106.89	$	109.09	$	108.57
Heavy oil, net of blending and other expense ($/bbl) (2)	76.00		—		76.00		84.43		—		84.43
NGL ($/bbl) (1)	26.04		27.66		27.45		30.75		28.04		28.36
Natural gas ($/mcf) (1)	1.00		2.53		2.14		2.72		3.20		3.01
Total sales, net of blending and other expense ($/boe) (2)	$	72.37	$	71.68	$	71.97	$	79.93	$	80.64	$	80.34

	Nine Months Ended September 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	96.85	$	104.49	$	103.12	$	100.46	$	105.63	$	103.87
Heavy oil, net of blending and other expense ($/bbl) (2)	74.73		—		74.73		67.65		—		67.65
NGL ($/bbl) (1)	25.76		27.03		26.87		32.03		28.18		28.79
Natural gas ($/mcf) (1)	1.61		2.42		2.20		2.98		3.21		3.10
Total sales, net of blending and other expense ($/boe) (2)	$	70.34	$	72.68	$	71.71	$	68.96	$	76.19	$	72.22

(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.

Q3 2024 MD&A 6

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $71.97/boe for Q3/2024 and $71.71/boe for YTD 2024 compared to $80.34/boe for Q3/2023 and $72.22/boe for YTD 2023. In Canada, our realized price of $72.37/boe for Q3/2024 was $7.56/boe lower than $79.93/boe for Q3/2023. Our realized price in the U.S. was $71.68/boe in Q3/2024 which is $8.96/boe lower than $80.64/boe in Q3/2023. The decrease in North American benchmark prices was the primary factor that resulted in lower realized pricing for our operations in Canada and the U.S. in Q3/2024 and YTD 2024 relative to the same periods of 2023.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price represents a discount to the Edmonton par price of $1.33/bbl for Q3/2024 and $1.61/bbl for YTD 2024 compared to a discount of $1.04/bbl in Q3/2023 and $0.24/bbl for YTD 2023.

We compare the price received for our U.S. light oil and condensate production to the MEH benchmark. Our realized light oil and condensate price averaged $101.82/bbl for Q3/2024 and $104.49/bbl for YTD 2024 compared to $109.09/bbl for Q3/2023 and $105.63/bbl for YTD 2023. Expressed in U.S. dollars, our realized light oil and condensate price of US$74.67/bbl for Q3/2024 and US$76.81/bbl for YTD 2024 represent discounts to MEH of US$2.83/bbl and US$3.04/bbl for Q3/2024 and YTD 2024 respectively, compared to discounts of US$2.75/bbl for Q3/2023 and US$0.32/bbl for YTD 2023. The realized discounts to MEH for 2024 are consistent with expectations and the comparative periods of 2023 which reflect the realized pricing and additional Eagle Ford production acquired from Ranger.

Our realized heavy oil price, net of blending and other expense(1) decreased $8.43/bbl which is consistent with a $9.04/bbl decrease in the WCS benchmark price for the same period. Our realized heavy oil price, net of blending and other expense for YTD 2024 increased by $7.08/bbl from YTD 2023, compared to $3.98/bbl increase in the WCS benchmark price over the same period. Our realized price increased more than the benchmark price as the cost of condensate purchased for blending was lower relative to the price received for sales of the blended product based on the WCS benchmark in YTD 2024 compared to YTD 2023.

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. Our realized NGL price(2) was $27.45/bbl in Q3/2024 or 27% of WTI (expressed in Canadian dollars) and $26.87/bbl in YTD 2024 or 25% of WTI (expressed in Canadian dollars), compared to $28.36/bbl or 26% of WTI (expressed in Canadian dollars) in Q3/2023 and $28.79/bbl or 28% of WTI (expressed in Canadian dollars) in YTD 2023. Our realized NGL price as a percentage of WTI in both periods of 2024 was consistent with the same periods of 2023.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. The change in our realized natural gas prices in Canada and the U.S. for Q3/2024 and YTD 2024 is consistent with the change in the AECO and NYMEX benchmark prices relative to Q3/2023 and YTD 2023.

(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.

Q3 2024 MD&A 7

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended September 30
	2024						2023
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	122,452	$	525,135	$	647,587	$	173,475	$	583,304	$	756,779
Heavy oil	350,859		—		350,859		323,272		—		323,272
NGL	6,067		44,034		50,101		5,945		41,027		46,972
Total oil sales	479,378		569,169		1,048,547		502,692		624,331		1,127,023
Natural gas sales	3,089		22,987		26,076		12,526		23,461		35,987
Total petroleum and natural gas sales	482,467		592,156		1,074,623		515,218		647,792		1,163,010
Blending and other expense	(51,902)		—		(51,902)		(49,830)		—		(49,830)
Total sales, net of blending and other expense (1)	$	430,565	$	592,156	$	1,022,721	$	465,388	$	647,792	$	1,113,180

	Nine Months Ended September 30
	2024						2023
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	321,704	$	1,589,648	$	1,911,352	$	444,894	$	909,159	$	1,354,053
Heavy oil	1,050,743		—		1,050,743		791,806		—		791,806
NGL	17,579		127,963		145,542		15,777		73,192		88,969
Total oil sales	1,390,026		1,717,611		3,107,637		1,252,477		982,351		2,234,828
Natural gas sales	17,314		66,987		84,301		38,654		43,624		82,278
Total petroleum and natural gas sales	1,407,340		1,784,598		3,191,938		1,291,131		1,025,975		2,317,106
Blending and other expense	(183,795)		—		(183,795)		(162,506)		—		(162,506)
Total sales, net of blending and other expense (1)	$	1,223,545	$	1,784,598	$	3,008,143	$	1,128,625	$	1,025,975	$	2,154,600

Total sales, net of blending and other expense, was $1.0 billion for Q3/2024 which reflects lower realized pricing compared to Q3/2023 when total sales, net of blending and other expense, was $1.1 billion. Total sales, net of blending and other expense of $3.0 billion for YTD 2024 increased from $2.2 billion reported for YTD 2023 which reflects the additional production from the Merger with Ranger.

In Canada, total sales, net of blending and other expense, of $430.6 million for Q3/2024 decreased from $465.4 million reported for Q3/2023. The decrease in our realized pricing for Q3/2024 relative to Q3/2023 resulted in a $45.0 million decrease in total sales, net of blending and other expense while higher production contributed to a $10.1 million increase in total sales, net of blending and other expense, relative to Q3/2023. Total sales, net of blending and other expense, of $1.2 billion for YTD 2024 increased from $1.1 billion for YTD 2023. The increase in our realized pricing for YTD 2024 relative to YTD 2023 resulted in a $24.0 million increase in total sales, net of blending and other expense while higher production contributed to a $70.9 million increase in total sales, net of blending and other expense, relative to YTD 2023.

In the U.S., total petroleum and natural gas sales of $592.2 million for Q3/2024 decreased from $647.8 million reported for Q3/2023. Higher production contributed to a $18.5 million increase in total sales in Q3/2024 relative to Q3/2023 and lower realized pricing resulted in a $74.1 million decrease in total sales relative to Q3/2023. Total petroleum and natural gas sales of $1.8 billion for YTD 2024 increased from $1.0 billion for YTD 2023. Higher production in YTD 2024 resulted in a $844.8 million increase in total sales relative to YTD 2023 and lower realized pricing resulted in a $86.2 million decrease in total sales relative to YTD 2023.

Baytex Energy Corp.

Q3 2024 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 nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30
	2024									2023
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	71,351		$	152,449		$	223,800		$	64,238		$	175,811		$	240,049
Average royalty rate (1)(2)	16.6		%	25.7		%	21.9		%	13.8		%	27.1		%	21.6		%
Royalties per boe (3)	$	11.99		$	18.45		$	15.75		$	11.03		$	21.89		$	17.33

	Nine Months Ended September 30
	2024									2023
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	200,809		$	472,602		$	673,411		$	155,402		$	285,820		$	441,222
Average royalty rate (1)(2)	16.4		%	26.5		%	22.4		%	13.8		%	27.9		%	20.5		%
Royalties per boe (3)	$	11.54		$	19.25		$	16.05		$	9.50		$	21.22		$	14.79

(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 Q3/2024 were $223.8 million or 21.9% of total sales, net of blending and other expense, compared to $240.0 million or 21.6% for Q3/2023. Total royalties for YTD 2024 were $673.4 million or 22.4% of total sales, net of blending and other expense, compared to $441.2 million or 20.5% for YTD 2023.

Our average royalty rate in Canada of 16.6% for Q3/2024 and 16.4% for YTD 2024 was higher than 13.8% for the comparative periods of 2023 as a result of production growth from our heavy oil properties which have a higher royalty rate relative to our light oil properties.

In the U.S., our average royalty rate was 25.7% for Q3/2024 which was lower than 27.1% for Q3/2023 due to a non-recurring prior period adjustment received from the operator of our non-operated Eagle Ford properties. Our average royalty rate for YTD 2024 was 26.5% compared to 27.9% for YTD 2023 due to the prior period adjustment and production from the acquired Ranger properties which have a lower royalty rate relative to our legacy non-operated Eagle Ford properties.

Our average royalty rate of 22.4% for YTD 2024 is consistent with our revised annual guidance of 22.5% for 2024.

Baytex Energy Corp.

Q3 2024 MD&A 9

OPERATING EXPENSE


	Three Months Ended September 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	87,373	$	79,746	$	167,119	$	93,065	$	81,054	$	174,119
Operating expense per boe (1)	$	14.69	$	9.65	$	11.76	$	15.98	$	10.09	$	12.57

	Nine Months Ended September 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	257,191	$	251,068	$	508,259	$	275,599	$	130,366	$	405,965
Operating expense per boe (1)	$	14.79	$	10.22	$	12.12	$	16.84	$	9.68	$	13.61

(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 $167.1 million ($11.76/boe) for Q3/2024 which is lower than $174.1 million ($12.57/boe) for Q3/2023, and reflects production growth at Peavine along with the disposition of non-core Viking assets in Q4/2023. Total operating expense of $508.3 million ($12.12/boe) for YTD 2024 was higher than $406.0 million ($13.61/boe) for YTD 2023, due to the additional production from the properties acquired from Ranger which also resulted in lower total per unit operating costs in YTD 2024 relative to YTD 2023.

In Canada, total operating expense was $87.4 million ($14.69/boe) for Q3/2024 and $257.2 million ($14.79/boe) for YTD 2024 which was lower than $93.1 million ($15.98/boe) for Q3/2023 and $275.6 million ($16.84/boe) for YTD 2023. The decrease in total and per unit operating expense for both periods of 2024 relative to the same periods of 2023 reflects production growth at Peavine along with the disposition of non-core Viking assets in Q4/2023.

In the U.S., operating expense was $79.7 million ($9.65/boe) for Q3/2024 which is consistent with $81.1 million ($10.09/boe) for Q3/2023. Operating expense for YTD 2024 increased to $251.1 million ($10.22/boe) from $130.4 million ($9.68/boe) for YTD 2023, which reflects the additional production from the properties acquired from Ranger. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$7.08/boe for Q3/2024 and US$7.51/boe for YTD 2024 consistent with US$7.52/boe for Q3/2023 and US$7.20/boe for YTD 2023.

Operating expense of $12.12/boe for YTD 2024 is consistent with expectations and our annual guidance of approximately $12.00/boe for 2024.

TRANSPORTATION EXPENSE

Transportation expense includes the costs incurred to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize sales prices and transportation rates.

The following table compares our transportation expense for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	24,837	$	12,046	$	36,883	$	16,075	$	11,908	$	27,983
Transportation expense per boe (1)	$	4.17	$	1.46	$	2.60	$	2.76	$	1.48	$	2.02

	Nine Months Ended September 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	62,616	$	37,416	$	100,032	$	46,320	$	13,242	$	59,562
Transportation expense per boe (1)	$	3.60	$	1.52	$	2.38	$	2.83	$	0.98	$	2.00

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

Baytex Energy Corp.

Q3 2024 MD&A 10

Transportation expense was $36.9 million ($2.60/boe) for Q3/2024 and $100.0 million ($2.38/boe) for YTD 2024 compared to $28.0 million ($2.02/boe) for Q3/2023 and $59.6 million ($2.00/boe) for YTD 2023. In Canada, total transportation expense and per unit costs were higher in Q3/2024 and YTD 2024 as a result of additional heavy oil production relative to the same periods of 2023. In the U.S., total transportation expense and per unit costs for Q3/2024 were consistent with Q3/2023 while total transportation and per unit costs for YTD 2024 were higher than YTD 2023 due to trucking and pipeline costs on our operated Eagle Ford operations acquired from Ranger.

Per unit transportation expense of $2.38/boe for YTD 2024 is consistent with our revised annual guidance of approximately $2.45/boe for 2024.

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 $51.9 million for Q3/2024 and $183.8 million for YTD 2024 compared to $49.8 million for Q3/2023 and $162.5 million for YTD 2023. Higher blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in Q3/2024 and YTD 2024 relative to same periods in 2023.

FINANCIAL DERIVATIVES

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2024		2023		Change		2024		2023		Change
Realized financial derivatives gain (loss)
Crude oil	$	(2,190)	$	2,130	$	(4,320)	$	(6,091)	$	23,909	$	(30,000)
Natural gas	2,521		(75)		2,596		9,653		(74)		9,727

Total	$	331	$	2,055	$	(1,724)	$	3,562	$	23,835	$	(20,273)
Unrealized financial derivatives gain (loss)
Crude oil	$	21,239	$	(31,903)	$	53,142	$	3,251	$	(39,817)	$	43,068
Natural gas	1,357		1,207		150		(2,215)		(1,072)		(1,143)


Total	$	22,596	$	(30,696)	$	53,292	$	1,036	$	(40,889)	$	41,925
Total financial derivatives gain (loss)
Crude oil	$	19,049	$	(29,773)	$	48,822	$	(2,840)	$	(15,908)	$	13,068
Natural gas	3,878		1,132		2,746		7,438		(1,146)		8,584


Total	$	22,927	$	(28,641)	$	51,568	$	4,598	$	(17,054)	$	21,652

We recorded total financial derivatives gains of $22.9 million for Q3/2024 and $4.6 million for YTD 2024 compared to losses of $28.6 million for Q3/2023 and $17.1 million for YTD 2023. The realized financial derivatives gain of $3.6 million for YTD 2024 resulted from gains of $9.7 million on natural gas contracts and losses of $6.1 million on crude oil contracts. The unrealized financial derivatives gain of $1.0 million for YTD 2024 resulted from a $3.3 million gain on crude oil contracts partially offset by a $2.2 million loss on natural gas contracts. The YTD gain is primarily due to changes in forecasted crude oil and natural gas pricing used to revalue the volumes outstanding on our contracts in place at September 30, 2024 relative to December 31, 2023. The fair value of our financial derivative contracts resulted in a net asset of $24.3 million at September 30, 2024 compared to a net asset of $23.3 million at December 31, 2023.

Refer to Note 17 of the consolidated financial statements for a complete listing of our outstanding contracts at October 31, 2024.

Baytex Energy Corp.

Q3 2024 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 nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30
	2024						2023
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	64,668		89,800		154,468		63,289		87,311		150,600
Operating netback:
Total sales, net of blending and other expense (1)	$	72.37	$	71.68	$	71.97	$	79.93	$	80.64	$	80.34
Less:
Royalties (2)	(11.99)		(18.45)		(15.75)		(11.03)		(21.89)		(17.33)
Operating expense (2)	(14.69)		(9.65)		(11.76)		(15.98)		(10.09)		(12.57)
Transportation expense (2)	(4.17)		(1.46)		(2.60)		(2.76)		(1.48)		(2.02)
Operating netback (1)	$	41.52	$	42.12	$	41.86	$	50.16	$	47.18	$	48.42
Realized financial derivatives gain (loss) (3)	—		—		0.02		—		—		0.15
Operating netback after financial derivatives (1)	$	41.52	$	42.12	$	41.88	$	50.16	$	47.18	$	48.57

	Nine Months Ended September 30
	2024						2023
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	63,483		89,616		153,099		59,948		49,327		109,275
Operating netback:
Total sales, net of blending and other expense (1)	$	70.34	$	72.68	$	71.71	$	68.96	$	76.19	$	72.22
Less:
Royalties (2)	(11.54)		(19.25)		(16.05)		(9.50)		(21.22)		(14.79)
Operating expense (2)	(14.79)		(10.22)		(12.12)		(16.84)		(9.68)		(13.61)
Transportation expense (2)	(3.60)		(1.52)		(2.38)		(2.83)		(0.98)		(2.00)
Operating netback (1)	$	40.41	$	41.69	$	41.16	$	39.79	$	44.31	$	41.82
Realized financial derivatives gain (3)	—		—		0.08		—		—		0.80
Operating netback after financial derivatives (1)	$	40.41	$	41.69	$	41.24	$	39.79	$	44.31	$	42.62

(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 $41.86/boe for Q3/2024 and $41.16/boe for YTD 2024 was lower than $48.42/boe for Q3/2023 and $41.82/boe for YTD 2023 due to the decrease in our realized price which resulted in lower per unit sales net of royalties. In 2024, a higher proportion of our production was from our U.S. properties which have lower operating and transportation expense resulting in total operating and transportation expense of $14.36/boe for Q3/2024 and $14.50/boe for YTD 2024, which was lower than $14.59/boe for Q3/2023 and $15.61/boe for YTD 2023. Our operating netback net of realized gains and losses on financial derivatives was $41.88/boe for Q3/2024 and $41.24/boe for YTD 2024 compared to $48.57/boe for Q3/2023 and $42.62/boe for YTD 2023.

GENERAL AND ADMINISTRATIVE EXPENSE

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

Baytex Energy Corp.

Q3 2024 MD&A 12

The following table summarizes our G&A expense for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2024		2023		Change		2024		2023		Change
Gross general and administrative expense	$	24,255	$	25,970	$	(1,715)	$	80,082	$	56,863	$	23,219
Overhead recoveries	(6,360)		(5,434)		(926)		(18,769)		(9,353)		(9,416)
General and administrative expense	$	17,895	$	20,536	$	(2,641)	$	61,313	$	47,510	$	13,803
General and administrative expense per boe (1)	$	1.26	$	1.48	$	(0.22)	$	1.46	$	1.59	$	(0.13)

(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 $17.9 million ($1.26/boe) for Q3/2024 compared to $20.5 million ($1.48/boe) for Q3/2023 which included higher initial costs related to the Merger. G&A expense was $61.3 million ($1.46/boe) for YTD 2024 compared to $47.5 million ($1.59/boe) for YTD 2023. Higher G&A expense in YTD 2024 compared to YTD 2023 is primarily due to staffing costs associated with the personnel retained following the Merger with Ranger.

G&A expense of $1.46/boe for YTD 2024 is consistent with expectations and we expect G&A expense of approximately $1.52/boe for 2024.

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 nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2024		2023		Change		2024		2023		Change
Interest on credit facilities	$	12,343	$	21,671	$	(9,328)	$	46,271	$	35,422	$	10,849
Interest on long-term notes	37,426		34,664		2,762		109,760		67,323		42,437
Interest on lease obligations	340		160		180		1,304		380		924
Cash interest	$	50,109	$	56,495	$	(6,386)	$	157,335	$	103,125	$	54,210
Accretion of debt issue costs	3,067		6,539		(3,472)		13,989		8,910		5,079
Accretion of asset retirement obligations	5,524		5,031		493		15,910		14,252		1,658

Early redemption expense	—		—		—		24,350		—		24,350
Financing and interest expense	$	58,700	$	68,065	$	(9,365)	$	211,584	$	126,287	$	85,297
Cash interest per boe (1)	$	3.53	$	4.08	$	(0.55)	$	3.75	$	3.46	$	0.29
Financing and interest expense per boe (1)	$	4.13	$	4.91	$	(0.78)	$	5.04	$	4.23	$	0.81

(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 $58.7 million ($4.13/boe) for Q3/2024 and $211.6 million ($5.04/boe) for YTD 2024 compared to $68.1 million ($4.91/boe) for Q3/2023 and $126.3 million ($4.23/boe) for YTD 2023. The decrease in interest costs in Q3/2024 is due to lower outstanding debt balances compared to Q3/2023. Higher interest costs in YTD 2024 compared to YTD 2023 reflect the additional debt outstanding after the Merger with Ranger and also includes costs incurred related to the early redemption of the 8.75% senior notes on April 1, 2024.

Cash interest of $50.1 million ($3.53/boe) for Q3/2024 was lower than $56.5 million ($4.08/boe) for Q3/2023. Lower interest on our credit facilities reflects lower debt balances outstanding in Q3/2024, while higher interest on long-term notes is a result of the issuance of the 7.375% Senior Notes in Q2/2024. Cash interest of $157.3 million ($3.75/boe) for YTD 2024 was higher than $103.1 million ($3.46/boe) for YTD 2023 and is primarily the result of higher debt balances outstanding after the Merger which included the issuance of US$800.0 million aggregate principal amount of long-term notes. The weighted average interest rate applicable on our credit facilities was 7.5% for Q3/2024 and 7.9% for YTD 2024 compared to 7.8% for Q3/2023 and 7.3% for YTD 2023.

Baytex Energy Corp.

Q3 2024 MD&A 13

Accretion of asset retirement obligations of $5.5 million for Q3/2024 and $15.9 million for YTD 2024 was consistent with $5.0 million for Q3/2023 and $14.3 million for YTD 2023. Accretion of debt issue costs was higher for 2024 compared to 2023 due to the costs associated with the debt issued in conjunction with the Merger. In Q2/2024 we refinanced our remaining 8.75% senior notes with US$575 million of 7.375% notes and we recorded $24.4 million of early redemption expense.

Cash interest expense of $157.3 million ($3.75/boe) for YTD 2024 is consistent with expectations. Our annual guidance of $200 million ($3.58/boe) for 2024 reflects continued debt repayment and lower interest rates applicable to our credit facilities over the remainder of the year.

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 $0.1 million for Q3/2024 and $0.7 million for YTD 2024 compared to $0.4 million for Q3/2023 and $0.9 million for YTD 2023.

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2024		2023		Change		2024		2023		Change
Depletion	$	352,745	$	317,548	$	35,197	$	1,043,898	$	656,456	$	387,442
Depreciation	3,639		2,183		1,456		9,724		5,418		4,306
Depletion and depreciation	$	356,384	$	319,731	$	36,653	$	1,053,622	$	661,874	$	391,748
Depletion and depreciation per boe (1)	$	25.08	$	23.08	$	2.00	$	25.12	$	22.19	$	2.93

(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 $356.4 million ($25.08/boe) for Q3/2024 and $1.1 billion ($25.12/boe) for YTD 2024 compared to $319.7 million ($23.08/boe) for Q3/2023 and $661.9 million ($22.19/boe) for YTD 2023. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q3/2024 and YTD 2024 relative to Q3/2023 and YTD 2023 due to depletion on the assets acquired from Ranger which have a higher depletion rate than our other properties. The effect of the Merger was partially offset by an impairment loss of $833.7 million that was recorded at December 31, 2023.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at September 30, 2024.

2023 Impairment

At December 31, 2023, we recorded an impairment loss of $833.7 million in our legacy non-operated Eagle Ford CGU due to changes in our reserves and in our Viking CGU due to changes in our reserves and a loss recorded on a disposition of an asset.

SHARE-BASED COMPENSATION EXPENSE

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

We recorded SBC expense of $2.3 million for Q3/2024 and $17.4 million for YTD 2024 which is lower than $14.7 million for Q3/2023 and $41.4 million for YTD 2023. SBC expense for Q3/2024 and YTD 2024 decreased relative to the same periods of 2023 as YTD 2023 includes $16.2 million of non-cash expense related to awards assumed and settled in Baytex common shares in conjunction with the Merger with Ranger and due to a decrease in the Company's share price during YTD 2024.

Baytex Energy Corp.

Q3 2024 MD&A 14

FOREIGN EXCHANGE

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


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for exchange rates)	2024		2023		Change		2024		2023		Change
Unrealized foreign exchange (gain) loss	$	(24,401)	$	42,392	$	(66,793)	$	33,506	$	29,299	$	4,207
Realized foreign exchange (gain) loss	(151)		290		(441)		1,934		1,381		553
Foreign exchange (gain) loss	$	(24,552)	$	42,682	$	(67,234)	$	35,440	$	30,680	$	4,760
CAD/USD exchange rates:
At beginning of period	1.3687		1.3238				1.3205		1.3534
At end of period	1.3505		1.3537				1.3505		1.3537

We recorded a foreign exchange gain of $24.6 million for Q3/2024 and a loss of $35.4 million for YTD 2024 compared to losses of $42.7 million for Q3/2023 and $30.7 million for YTD 2023.

The unrealized foreign exchange gain of $24.4 million for Q3/2024 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 September 30, 2024 compared to June 30, 2024. The loss of $33.5 million for YTD 2024 is due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2024 compared to December 31, 2023. The unrealized foreign exchange loss of $42.4 million for Q3/2023 and $29.3 million for YTD 2023 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 September 30, 2023 compared to June 30, 2023 and December 31, 2022.

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 gain of $0.2 million for Q3/2024 and a loss of $1.9 million for YTD 2024 compared to losses of $0.3 million for Q3/2023 and $1.4 million for YTD 2023.

INCOME TAXES


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2024		2023		Change		2024		2023		Change
Current income tax (recovery) expense	$	(3,748)	$	808	$	(4,556)	$	4,407	$	3,278	$	1,129
Deferred income tax expense (recovery)	33,577		48,007		(14,430)		72,188		(114,830)		187,018
Total income tax expense (recovery)	$	29,829	$	48,815	$	(18,986)	$	76,595	$	(111,552)	$	188,147
Current income tax (recovery) expense per boe	$	(0.26)	$	0.06	$	(0.32)	$	0.11	$	0.11	$	—

We recorded a current income tax recovery of $3.7 million for Q3/2024 and expense of $4.4 million for YTD 2024 compared to expense of $0.8 million for Q3/2023 and $3.3 million for YTD 2023. The current tax recovery recorded in Q3/2024 and current tax expense in YTD 2024 primarily relates to repatriation and related taxes. The repatriation and related taxes for YTD 2024 have increased from YTD 2023 as a result of the Merger. The current tax recovery recorded in Q3/2024 is a recovery of previously accrued 2023 US taxes. We expect current income tax expense of $25 million ($0.45/boe) for 2024.

We recorded deferred tax expense of $33.6 million for Q3/2024 and $72.2 million for YTD 2024 compared to expense of $48.0 million for Q3/2023 and a recovery of $114.8 million for YTD 2023. The deferred tax expense recorded in Q3/2024 and YTD 2024 reflects income generated on our U.S. operations for the period as the tax pools associated with our Canadian operations are subject to a valuation allowance. The deferred tax expense recorded in Q3/2023 was due to income generated on our Canadian and U.S. operations for the period. The deferred tax recovery recorded in YTD 2023 was primarily related to the effects of the transaction structuring for the Merger in Q2/2023, partially offset by income generated on our Canadian and U.S. operations for the period.

Baytex Energy Corp.

Q3 2024 MD&A 15

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 and we estimate it could take between two and 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 Tax Court of Canada, 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 $208.6 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of 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.

Baytex Energy Corp.

Q3 2024 MD&A 16

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income for the three and nine months ended September 30, 2024 and 2023 are set forth in the following table.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2024		2023		Change		2024		2023		Change
Petroleum and natural gas sales	$	1,074,623	$	1,163,010	$	(88,387)	$	3,191,938	$	2,317,106	$	874,832
Royalties	(223,800)		(240,049)		16,249		(673,411)		(441,222)		(232,189)
Revenue, net of royalties	850,823		922,961		(72,138)		2,518,527		1,875,884		642,643

Expenses
Operating	(167,119)		(174,119)		7,000		(508,259)		(405,965)		(102,294)
Transportation	(36,883)		(27,983)		(8,900)		(100,032)		(59,562)		(40,470)
Blending and other	(51,902)		(49,830)		(2,072)		(183,795)		(162,506)		(21,289)
Operating netback (1)	$	594,919	$	671,029	$	(76,110)	$	1,726,441	$	1,247,851	$	478,590
General and administrative	(17,895)		(20,536)		2,641		(61,313)		(47,510)		(13,803)
Cash interest	(50,109)		(56,495)		6,386		(157,335)		(103,125)		(54,210)
Realized financial derivatives gain	331		2,055		(1,724)		3,562		23,835		(20,273)
Realized foreign exchange gain (loss)	151		(290)		441		(1,934)		(1,381)		(553)
Cash other income	9,107		1,367		7,740		7,011		1,013		5,998
Current income tax recovery (expense)	3,748		(808)		4,556		(4,407)		(3,278)		(1,129)
Cash share-based compensation	(2,305)		(14,699)		12,394		(17,393)		(25,203)		7,810
Adjusted funds flow (2)	$	537,947	$	581,623	$	(43,676)	$	1,494,632	$	1,092,202	$	402,430
Transaction costs	—		(2,263)		2,263		(1,539)		(43,966)		42,427
Exploration and evaluation	(82)		(409)		327		(749)		(941)		192
Depletion and depreciation	(356,384)		(319,731)		(36,653)		(1,053,622)		(661,874)		(391,748)
Non-cash share-based compensation	—		—		—		—		(16,237)		16,237
Non-cash financing and interest	(8,591)		(11,570)		2,979		(54,249)		(23,162)		(31,087)
Non-cash other income	—		—		—		—		1,271		(1,271)
Unrealized financial derivatives gain (loss)	22,596		(30,696)		53,292		1,036		(40,889)		41,925
Unrealized foreign exchange gain (loss)	24,401		(42,392)		66,793		(33,506)		(29,299)		(4,207)
(Loss) gain on dispositions and swaps	(1,091)		875		(1,966)		(4,741)		539		(5,280)

Deferred income tax (expense) recovery	(33,577)		(48,007)		14,430		(72,188)		114,830		(187,018)
Net income	$	185,219	$	127,430	$	57,789	$	275,074	$	392,474	$	(117,400)

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

We generated adjusted funds flow of $537.9 million for Q3/2024 compared $581.6 million for Q3/2023 which reflects lower commodity prices that resulted in decreased revenues net of royalties. Adjusted funds flow was $1.5 billion for YTD 2024 compared to $1.1 billion for YTD 2023 which was primarily due to higher production from the Merger that resulted in increased revenues net of royalties, along with additional operating, transportation and blending and other income. Cash interest and general and administrative expenses were also higher for YTD 2024 due to the additional debt outstanding and staffing levels following the Merger.

We reported net income of $185.2 million for Q3/2024 compared to net income of $127.4 million for Q3/2023. The increase in net income for Q3/2024 is the result of an unrealized foreign exchange gain, an unrealized financial derivatives gain, and a lower deferred income tax expense partially offset by a higher depletion rate and associated depletion expense. We reported net income of $275.1 million for YTD 2024 compared to net income of $392.5 million for YTD 2023. The decrease in net income for YTD 2024 relative to the same periods of 2023 is the result of deferred income tax expense recognized in 2024 compared to a deferred tax recovery recognized in 2023, a higher depletion rate and associated depletion expense, an unrealized foreign exchange loss and increased non-cash financing and interest costs.

Baytex Energy Corp.

Q3 2024 MD&A 17

OTHER COMPREHENSIVE INCOME

Other comprehensive income 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 $61.6 million for Q3/2024 and gain of $100.9 million for YTD 2024 relates to the change in value of our U.S. net assets and is due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2024 compared to June 30, 2024 and December 31, 2023. The CAD/USD exchange rate was 1.3505 CAD/USD as at September 30, 2024 compared to 1.3687 CAD/USD at June 30, 2024 and 1.3205 CAD/USD at December 31, 2023.

CAPITAL EXPENDITURES

Capital expenditures for the three and nine months ended September 30, 2024 and 2023 are summarized as follows.


	Three Months Ended September 30
	2024						2023
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	104,787	$	175,544	$	280,331	$	94,555	$	274,421	$	368,976
Facilities and other	15,686		10,315		26,001		12,498		27,717		40,215
Exploration and development expenditures	$	120,473	$	185,859	$	306,332	$	107,053	$	302,138	$	409,191
Property acquisitions	$	507	$	535	$	1,042	$	4,277	$	—	$	4,277
Proceeds from dispositions	$	236	$	(1,672)	$	(1,436)	$	(226)	$	—	$	(226)

	Nine Months Ended September 30
	2024						2023
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	311,143	$	604,144	$	915,287	$	327,026	$	394,850	$	721,876
Facilities and other	69,372		73,797		143,169		61,036		30,609		91,645
Exploration and development expenditures	$	380,515	$	677,941	$	1,058,456	$	388,062	$	425,459	$	813,521
Property acquisitions	$	36,584	$	3,210	$	39,794	$	4,721	$	—	$	4,721
Proceeds from dispositions	$	368	$	(4,524)	$	(4,156)	$	(511)	$	—	$	(511)

Exploration and development expenditures of $306.3 million for Q3/2024 were lower than $409.2 million for Q3/2023 and reflects the timing of development activity in our U.S. operations. Exploration and development expenditures were $1.1 billion for YTD 2024 compared to $813.5 million for YTD 2023. The increase for 2024 is primarily due to development activity on our operated Eagle Ford properties acquired from Ranger. We also completed property acquisitions, including the acquisition of 30.75 net sections of Duvernay lands adjacent to our existing acreage, in YTD 2024 for a total of $39.8 million.

In Canada, exploration and development expenditures were $120.5 million in Q3/2024 compared to $107.1 million in Q3/2023 and $380.5 million for YTD 2024 compared to $388.1 million for YTD 2023. Drilling and completion spending of $104.8 million in Q3/2024 was higher than Q3/2023 when we spent $94.6 million which reflects increased development activity levels on our light and heavy oil properties. YTD 2024 drilling and completion spending of $311.1 million reflects light and heavy oil development activity that was consistent with YTD 2023 when we spent $327.0 million. We also invested $69.4 million on facilities and other expenditures during YTD 2024 which is consistent with $61.0 million during YTD 2023.

Total U.S. exploration and development expenditures were $185.9 million for Q3/2024 and $677.9 million for YTD 2024 compared to $302.1 million in Q3/2023 and $425.5 million for YTD 2023. The decrease in exploration and development expenditures for Q3/2024 compared to Q3/2023 reflects cost savings realized on the properties acquired from Ranger, in addition to lower drilling activity. Exploration and development expenditures for YTD 2024 increased compared to YTD 2023 due to additional development related to the operated properties acquired from Ranger.

Exploration and development expenditures of $1.1 billion for YTD 2024 were consistent with expectations. Our revised annual guidance of approximately $1.25 billion reflects moderated exploration and development spending over the remainder of 2024.

Baytex Energy Corp.

Q3 2024 MD&A 18

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. We strive to actively manage our capital structure in response to changes in economic conditions. At September 30, 2024, 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 $2.5 billion at September 30, 2024 was consistent with $2.5 billion at December 31, 2023 which was due to the impact of a weaker Canadian dollar at September 30, 2024 on our U.S. dollar denominated debt and also reflects $39.8 million of property acquisitions along with $49.7 million of debt issuance costs incurred during YTD 2024, which included $24.4 million of early redemption expense. We expect net debt to decline over the remainder of 2024 as we continue to allocate 50% of free cash flow to the balance sheet.

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

Credit Facilities

At September 30, 2024, we had $466.1 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 May 9, 2024, we extended the maturity of the Credit Facilities from April 1, 2026 to May 9, 2028. There were no changes to the loan balances or financial covenants as a result of the amendment. Following the amendment, borrowing in Canadian funds previously based on the banker's acceptance rate has been replaced with borrowings based on the Canadian Overnight Repo Rate Average ("CORRA").

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, CORRA 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 7.5% for Q3/2024 and 7.9% for YTD 2024, which is consistent with 7.8% for Q3/2023 and 7.3% for YTD 2023.

At September 30, 2024, we had $5.7 million of outstanding letters of credit (December 31, 2023 - $5.6 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 September 30, 2024.


Covenant Description	Position as at September 30, 2024	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.2:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	10.5:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.0:1.0	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 September 30, 2024, the Company's Senior Secured Debt totaled $470.8 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 September 30, 2024 was $2.2 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 September 30, 2024 was $212.4 million.

(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at September 30, 2024, the Company's Total Debt totaled $2.3 billion of principal amounts outstanding.

Long-Term Notes

At September 30, 2024 we have two issuances of long-term notes outstanding with a total principal amount of $1.9 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. At September 30, 2024 there was US$800.0 million aggregate principal amount of the 8.50% Senior Notes outstanding.

On April 1, 2024, we closed a private offering of the US$575 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"). The 7.375% Senior Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15, 2032. 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. Proceeds from the 7.375% Senior Notes were used to redeem the remaining US$409.8 million aggregate principal amount of the outstanding 8.75% Senior Notes at 104.375% of par value, pay the related fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities. At September 30, 2024 there was US$575.0 million aggregate principal amount of the 7.375% Senior Notes outstanding.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2024, we issued 0.3 million common shares pursuant to our share-based compensation program. As at September 30, 2024, we had 787.3 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 nine months ended September 30, 2024, we repurchased 34.6 million common shares under our normal course issuer bid ("NCIB") at an average price of $4.77 per share for total consideration of $165.2 million. In June 2024, we renewed our NCIB under which Baytex is permitted to purchase for cancellation up to 70.1 million common shares over the 12-month period commencing July 2, 2024, which represents 10% of Baytex's public float, as defined by the TSX, as of June 18, 2024. Baytex obtained an exemption order from the Canadian securities regulators which permits the company to purchase its common shares through the NYSE and other U.S.-based trading systems.

Effective January 1, 2024, the Government of Canada introduced a 2% federal tax on equity repurchases. During the nine months ended September 30, 2024, Baytex recorded a $3.3 million liability, charged to shareholders’ capital, related to the federal tax on equity repurchases.

On January 2, April 1, July 2, and October 1, 2024, we paid a quarterly cash dividend of $0.0225 per share to shareholders of record. On October 31, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 2, 2025 for shareholders of record on December 13, 2024. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2024 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	$	466,108	$	—	$	—	$	466,108	$	—
Long-term notes - principal	1,856,869		—		—		—		1,856,869
Interest on long-term notes (1)	939,973		149,098		298,196		298,196		194,483
Lease obligations - principal	28,135		9,120		9,057		7,139		2,819
Processing agreements	5,178		530		850		543		3,255
Transportation agreements	177,670		53,710		86,796		24,646		12,518
Total	$	3,473,933	$	212,458	$	394,899	$	796,632	$	2,069,944

(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.

Q3 2024 MD&A 19

QUARTERLY FINANCIAL INFORMATION


	2024			2023				2022
($ thousands, except per common share amounts)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Petroleum and natural gas sales	1,074,623	1,133,123	984,192	1,065,515	1,163,010	598,760	555,336	648,986
Net income (loss)	185,219	103,898	(14,043)	(625,830)	127,430	213,603	51,441	352,807
Per common share - basic	0.23	0.13	(0.02)	(0.75)	0.15	0.37	0.09	0.65
Per common share - diluted	0.23	0.13	(0.02)	(0.75)	0.15	0.36	0.09	0.64
Adjusted funds flow (1)	537,947	532,839	423,846	502,148	581,623	273,590	236,989	255,552
Per common share - basic	0.68	0.65	0.52	0.60	0.68	0.47	0.43	0.47
Per common share - diluted	0.67	0.65	0.52	0.60	0.68	0.47	0.43	0.46
Free cash flow (2)	220,159	180,673	(88)	290,785	158,440	96,313	(1,918)	143,324
Per common share - basic	0.28	0.22	—	0.35	0.19	0.17	—	0.26
Per common share - diluted	0.28	0.22	—	0.35	0.18	0.16	—	0.26
Cash flows from operating activities	550,042	505,584	383,773	474,452	444,033	192,308	184,938	303,441
Per common share - basic	0.69	0.62	0.47	0.57	0.52	0.33	0.34	0.56
Per common share - diluted	0.69	0.62	0.47	0.57	0.52	0.33	0.34	0.55
Dividends declared	17,732	18,161	18,494	18,381	19,138	—	—	—
Per common share	0.0225	0.0225	0.0225	0.0225	0.0225	—	—	—
Exploration and development	306,332	339,573	412,551	199,214	409,191	170,704	233,626	103,634
Canada	120,473	101,916	158,126	75,137	107,053	96,403	184,606	85,641
U.S.	185,859	237,657	254,425	124,077	302,138	74,301	49,020	17,993
Property acquisitions	1,042	3,349	35,403	33,923	4,277	(62)	506	1,085
Proceeds from dispositions	(1,436)	(2,695)	(25)	(159,745)	(226)	(50)	(235)	(148)
Net debt (1)	2,493,269	2,639,014	2,639,841	2,534,287	2,824,348	2,814,844	995,170	987,446
Total assets	7,614,157	7,770,926	7,717,495	7,460,931	8,946,181	8,617,444	5,180,059	5,103,769
Common shares outstanding	787,328	804,977	821,322	821,681	845,360	862,192	545,553	544,930

Daily production
Total production (boe/d)	154,468	154,194	150,620	160,373	150,600	89,761	86,760	86,864
Canada (boe/d)	64,668	63,688	62,081	64,744	63,289	55,874	60,651	56,946
U.S. (boe/d)	89,800	90,506	88,540	95,629	87,311	33,887	26,109	29,918

Benchmark prices
WTI oil (US$/bbl)	75.10	80.57	76.96	78.32	82.26	73.78	76.13	82.64
WCS heavy oil ($/bbl)	83.98	91.72	77.73	76.86	93.02	78.85	69.44	77.37
Edmonton par oil ($/bbl)	97.91	105.30	92.16	99.72	107.93	95.13	99.04	109.57
CAD/USD avg exchange rate	1.3636	1.3684	1.3488	1.3619	1.3410	1.3431	1.3520	1.3577
AECO natural gas ($/mcf)	0.81	1.44	2.05	2.66	2.39	2.35	4.34	5.58
NYMEX natural gas (US$/mmbtu)	2.16	1.89	2.24	2.88	2.55	2.10	3.42	6.26

Total sales, net of blending and other expense ($/boe) (2)	71.97	75.93	67.12	68.00	80.34	66.82	63.48	74.93
Royalties ($/boe) (3)	(15.75)	(17.14)	(15.26)	(15.49)	(17.33)	(13.21)	(11.94)	(15.23)
Operating expense ($/boe) (3)	(11.76)	(11.95)	(12.65)	(11.17)	(12.57)	(14.62)	(14.40)	(13.06)
Transportation expense ($/boe) (3)	(2.60)	(2.37)	(2.18)	(2.02)	(2.02)	(1.78)	(2.18)	(1.85)
Operating netback ($/boe) (2)	41.86	44.47	37.03	39.32	48.42	37.21	34.96	44.79
Financial derivatives gain (loss) ($/boe) (3)	0.02	(0.16)	0.40	0.84	0.15	2.00	0.69	(6.21)
Operating netback after financial derivatives ($/boe) (2)	41.88	44.31	37.43	40.16	48.57	39.21	35.65	38.58

(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.

Baytex Energy Corp.

Q3 2024 MD&A 20

Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have remained relatively stable. Production steadily increased from 86,864 boe/d in Q4/2022 and reached 154,468 boe/d in Q3/2024 due to strong well performance from our development programs in Canada and the U.S., along with the production contribution from the Merger with Ranger.

Crude oil prices strengthened in Q3/2023 as a result of the announcement by OPEC+ of new production cuts, as well as the extension of voluntary production cuts by Saudi Arabia and Russia. This was reflected in our realized sales price of $80.34/boe for Q3/2023, which is our strongest realized pricing in the most recent eight quarters. Our realized price of $71.97/boe for Q3/2024 reflects lower crude oil prices due to concerns over weaker demand, higher inventories and slowing global economic activity.

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 $537.9 million and cash flows from operating activities of $550.0 million for Q3/2024 reflect strong production results from our development plans in the U.S. and Canada.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt(1) increased to $2.5 billion at Q3/2024 from $1.0 billion at Q4/2022 as a result of additional debt used to fund the Merger which closed in Q2/2023. The change in net debt also reflects free cash flow(2) of $944.4 million generated in the period since Q4/2022, along with $479.0 million allocated to shareholder returns.

(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, 2023 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 proposed standards that are aligned with the ISSB release, but include suggestions for Canadian-specific modifications. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. 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 financial arrangements that are excluded from the consolidated financial statements as at September 30, 2024, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the nine months ended September 30, 2024. 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, 2023.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2024, Baytex adopted amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.

These amendments have not had a material impact on our consolidated financial statements.

Baytex Energy Corp.

Q3 2024 MD&A 21

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.

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 September 30				Nine Months Ended September 30
($ thousands)	2024		2023		2024		2023
Petroleum and natural gas sales	$	1,074,623	$	1,163,010	$	3,191,938	$	2,317,106
Light oil and condensate (1)	(647,587)		(756,779)		(1,911,352)		(1,354,053)
NGL (1)	(50,101)		(46,972)		(145,542)		(88,969)
Natural gas sales (1)	(26,076)		(35,987)		(84,301)		(82,278)
Heavy oil sales	$	350,859	$	323,272	$	1,050,743	$	791,806
Blending and other expense (2)	(51,902)		(49,830)		(183,795)		(162,506)
Heavy oil, net of blending and other expense	$	298,957	$	273,442	$	866,948	$	629,300

(1)Component of petroleum and natural gas sales. See Note 13 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and nine months ended September 30, 2024 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.

Baytex Energy Corp.

Q3 2024 MD&A 22

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2024		2023		2024		2023
Petroleum and natural gas sales	$	1,074,623	$	1,163,010	$	3,191,938	$	2,317,106
Blending and other expense	(51,902)		(49,830)		(183,795)		(162,506)
Total sales, net of blending and other expense	1,022,721		1,113,180		3,008,143		2,154,600
Royalties	(223,800)		(240,049)		(673,411)		(441,222)
Operating expense	(167,119)		(174,119)		(508,259)		(405,965)
Transportation expense	(36,883)		(27,983)		(100,032)		(59,562)
Operating netback	$	594,919	$	671,029	$	1,726,441	$	1,247,851
Realized financial derivatives gain (1)	331		2,055		3,562		23,835
Operating netback after realized financial derivatives	$	595,250	$	673,084	$	1,730,003	$	1,271,686

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2024 for further information.

Free cash flow

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

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2024		2023		2024		2023
Cash flows from operating activities	$	550,042	$	444,033	$	1,439,399	$	821,279
Change in non-cash working capital	(20,813)		126,075		31,350		205,924
Additions to exploration and evaluation assets	—		(40)		—		(1,271)
Additions to oil and gas properties	(306,332)		(409,151)		(1,058,456)		(812,250)
Payments on lease obligations	(2,738)		(4,740)		(13,088)		(7,076)
Transaction costs	—		2,263		1,539		43,966
Cash premiums on derivatives	—		—		—		2,263
Free cash flow	$	220,159	$	158,440	$	400,744	$	252,835

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.

Baytex Energy Corp.

Q3 2024 MD&A 23

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.

The following table summarizes our calculation of net debt.


	As at
($ thousands)	September 30, 2024		December 31, 2023
Credit facilities	$	449,116	$	848,749
Unamortized debt issuance costs - Credit facilities (1)	16,992		15,987
Long-term notes	1,810,701		1,562,361
Unamortized debt issuance costs - Long-term notes (1)	46,168		35,114
Trade payables	584,696		477,295
Share-based compensation liability	23,962		35,732
Dividends payable	17,732		18,381
Other long-term liabilities	19,582		19,147
Cash	(21,311)		(55,815)
Trade receivables	(375,942)		(339,405)
Prepaids and other assets	(78,427)		(83,259)
Net debt	$	2,493,269	$	2,534,287

(1)Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2024. 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, transaction costs and cash premiums on derivatives.

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2024		2023		2024		2023
Cash flow from operating activities	$	550,042	$	444,033	$	1,439,399	$	821,279
Change in non-cash working capital	(20,813)		126,075		31,350		205,924
Asset retirement obligations settled	8,718		9,252		22,344		18,770
Transaction costs	—		2,263		1,539		43,966
Cash premiums on derivatives	—		—		—		2,263
Adjusted funds flow	$	537,947	$	581,623	$	1,494,632	$	1,092,202

Baytex Energy Corp.

Q3 2024 MD&A 24

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 September 30, 2024.

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: that we can effectively allocate capital across our assets; our 2024 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; that we intend to settle outstanding share based compensation awards in cash; 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; that we may issue or repurchase debt or equity securities from time to time; our intent to fund certain financial obligations with cash flow from operations and the expected timing of the 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; 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, 2023, 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

Baytex Energy Corp.

Q3 2024 MD&A 25

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.