EX-99 3 a992-q12024mda.htm EX-99.2

Document

Baytex Energy Corp.                                            

Q1 2024 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three months ended March 31, 2024 and 2023

Dated May 9, 2024

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2024. This information is provided as of May 9, 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 months ended March 31, 2024 ("Q1/2024") have been compared with the results for the three months ended March 31, 2023 ("Q1/2023"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 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 (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.

FIRST QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q1/2024. We invested $412.6 million on exploration and development expenditures and delivered production of 150,620 boe/d for Q1/2024 which reflects results from our development programs in the U.S. and Canada that are in line with expectations. The global crude oil market remained relatively balanced and benchmark prices were stable during Q1/2024 which resulted in adjusted funds flow(1) of $423.8 million.

Exploration and development expenditures totaled $412.6 million in Q1/2024 and were consistent with expectations. In the U.S. we invested $254.4 million during Q1/2024 and production averaged 88,540 boe/d which is higher than 26,109 boe/d for Q1/2023 due to the Merger with Ranger. We invested $158.1 million in Canada in Q1/2024 and generated production of 62,081 boe/d in Q1/2024 compared to 60,651 boe/d in Q1/2023 which reflects strong well performance from our light and heavy oil operations.

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

Baytex Energy Corp.                                            

Q1 2024 MD&A    2

Oil prices in Q1/2024 were consistent with Q1/2023 as a result of modest global supply growth, continued OPEC production curtailments and stable demand which has resulted in a more balanced crude market. The WTI benchmark price for Q1/2024 was US$76.96US/bbl which was consistent with Q1/2023 when WTI averaged US$76.13/bbl. Adjusted funds flow(1) of $423.8 million and cash flows from operating activities of $383.8 million for Q1/2024 reflect increased production compared to Q1/2023 when we generated adjusted funds flow of $237.0 million and cash flows from operating activities of $184.9 million.

Net debt(1) of $2.6 billion at March 31, 2024 was slightly higher than $2.5 billion at December 31, 2023 which was primarily due to the impact of a weaker Canadian dollar at March 31, 2024 on our U.S. dollar denominated debt and also reflects $18.5 million of dividends and $34.7 million of land acquisitions completed during Q1/2024. 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

The following table compares our 2024 annual guidance to our Q1/2024 results. Our 2024 annual guidance is unchanged with production guidance range of 150,000 to 156,000 boe/d and exploration and development expenditures of $1.2-$1.3 billion.

			2024 Annual Guidance (1)						Q1/2024 Results
Exploration and development expenditures			$1.2 - $1.3 billion						$412.6 million
Production (boe/d)			150,000 - 156,000						150,620
Expenses:
Average royalty rate (2)			23%						22.7%
Operating (3)			$11.25 - $12.00/boe						$12.65/boe
Transportation (3)			$2.35 - $2.55/boe						$2.18/boe
General and administrative (3)			$92 million ($1.65/boe)						$22.4 million ($1.64/boe)
Cash Interest (3)			$190 million ($3.40/boe)						$53.3 million ($3.89/boe)
Current Income Taxes (4)			$40 million ($0.72/boe)						$1.7 million ($0.12/boe)
Leasing expenditures			$12 million						$4.9 million
Asset retirement obligations			$30 million						$6.5 million

(1)As announced on December 6, 2023.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

(3)Refer to 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.                                            

Q1 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 March 31
			2024									2023
			Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate			11,493			54,543			66,036			16,398			15,280			31,678
Heavy oil			40,560			—			40,560			34,191			—			34,191
Natural Gas Liquids (NGL)			2,631			16,668			19,299			1,875			5,338			7,213
Total liquids (bbl/d)			54,684			71,211			125,895			52,464			20,618			73,082
Natural gas (mcf/d)			44,380			103,973			148,353			49,120			32,946			82,066
Total production (boe/d)			62,081			88,540			150,620			60,651			26,109			86,760
Production Mix
Segment as a percent of total			41		%	59		%	100		%	70		%	30		%	100		%
Light oil and condensate			19		%	62		%	44		%	27		%	59		%	37		%
Heavy oil			65		%	—		%	27		%	56		%	—		%	39		%
NGL			4		%	19		%	13		%	3		%	20		%	8		%
Natural gas			12		%	19		%	16		%	14		%	21		%	16		%

Production was 150,620 boe/d for Q1/2024 compared to 86,760 boe/d for Q1/2023. Total production was higher in Q1/2024 compared to Q1/2023 primarily due to production from the Eagle Ford properties acquired from Ranger along with our successful development program in Canada.

In Canada, production was 62,081 boe/d for Q1/2024 compared to 60,651 boe/d for Q1/2023. Our successful development program and strong well performance resulted in a 1,430 boe/d increase in production for Q1/2024 relative to Q1/2023. Strong production results from our Clearwater development resulted in Q1/2024 production of 17,599 boe/d at Peavine compared to 11,760 boe/d in Q1/2023. Higher production at Peavine was partially offset by the disposition of non-core light oil Viking assets in December 2023 that produced approximately 4,800 boe/d for Q1/2023.

In the U.S., production was 88,540 boe/d for Q1/2024 compared to 26,109 boe/d for Q1/2023. Production from the Merger was the primary factor that resulted in a 62,431 boe/d increase in production for Q1/2024 compared to Q1/2023. Production from the acquired Eagle Ford assets is primarily operated and is weighted towards light oil which resulted in a higher proportion of our total production being light oil in Q1/2024.

Total production of 150,620 boe/d for Q1/2024 is consistent with expectations and is at the lower end of our annual guidance of 150,000 - 156,000 boe/d which reflects production growth over the remainder of 2024.

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 was consistent between Q1/2024 and Q1/2023 as global supply and demand for crude oil remained relatively balanced. The WTI benchmark price averaged US$76.96/bbl for Q1/2024 compared to US$76.13/bbl for Q1/2023.

Baytex Energy Corp.                                            

Q1 2024 MD&A    4

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 typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark averaged US$78.95/bbl during Q1/2024, representing a premium of US$1.99/bbl relative to WTI, compared to US$77.42/bbl or a premium of US$1.29/bbl for Q1/2023. The MEH benchmark traded at a higher premium to WTI in Q1/2024 compared to Q1/2023 mainly due to 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.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $92.16/bbl during Q1/2024 compared to $99.04/bbl during Q1/2023. Edmonton par traded at a discount to WTI of US$8.63/bbl for Q1/2024 compared to a discount of US$2.88/bbl for Q1/2023 due to higher production in the Western Canadian Sedimentary Basin.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q1/2024 averaged $77.73/bbl compared to $69.44/bbl for the same period of 2023. The WCS heavy oil differential was US$19.33/bbl in Q1/2024 compared to US$24.77/bbl for Q1/2023 which was impacted by refinery turnarounds and reduced demand for Canadian heavy oil.

Natural Gas

Mild winter weather resulted in weak demand for North American natural gas and resulted in elevated inventory levels along with lower prices in Q1/2024 compared to Q1/2023.

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 that averaged US$2.24/mmbtu for Q1/2024 compared to US$3.42/mmbtu for Q1/2023 which reflects weak winter demand and elevated inventories in Q1/2024.

In Canada, we receive natural gas pricing based on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $2.05/mcf during Q1/2024 which is lower than $4.34/mcf for Q1/2023 due to mild winter weather and higher production in both the U.S. and Canada.

The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
			2024			2023			Change
Benchmark Averages
WTI oil (US$/bbl) (1)			76.96			76.13			0.83
MEH oil (US$/bbl) (2)			78.95			77.42			1.53
MEH oil differential to WTI (US$/bbl)			1.99			1.29			0.70
Edmonton par oil ($/bbl) (3)			92.16			99.04			(6.88)
Edmonton par oil differential to WTI (US$/bbl)			(8.63)			(2.88)			(5.75)
WCS heavy oil ($/bbl) (4)			77.73			69.44			8.29
WCS heavy oil differential to WTI (US$/bbl)			(19.33)			(24.77)			5.44
AECO natural gas ($/mcf) (5)			2.05			4.34			(2.29)
NYMEX natural gas (US$/mmbtu) (6)			2.24			3.42			(1.18)
CAD/USD average exchange rate			1.3488			1.3520			(0.0032)

(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.

Baytex Energy Corp.                                            

Q1 2024 MD&A    5

			Three Months Ended March 31
			2024									2023
			Canada			U.S.			Total			Canada			U.S.			Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)			$	91.05		$	101.93		$	100.03		$	99.23		$	103.27		$	101.18
Heavy oil, net of blending and other expense ($/bbl) (2)			65.22			—			65.22			51.15			—			51.15
NGL ($/bbl) (1)			26.60			26.08			26.15			35.90			32.83			33.63
Natural gas ($/mcf) (1)			2.42			2.37			2.39			3.53			4.02			3.73
Total sales, net of blending and other expense ($/boe) (2)			$	62.33		$	70.48		$	67.12		$	59.71		$	72.22		$	63.48

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

(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.

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $67.12/boe for Q1/2024 compared to $63.48/boe for Q1/2023. In Canada, our realized price of $62.33/boe for Q1/2024 was $2.62/boe higher than $59.71/boe for Q1/2023. Our realized price in the U.S. was $70.48/boe in Q1/2024 which is $1.74/boe lower than $72.22/boe in Q1/2023. The increase in our realized price in Canada for Q1/2024 was primarily a result of higher WCS benchmark pricing and higher heavy oil production compared to Q1/2023. The decrease in our realized price in the U.S. was primarily a result of contracts in place for our operated Eagle Ford production during Q1/2024.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $91.05/bbl for Q1/2024 compared to $99.23/bbl for Q1/2023. Our realized light oil and condensate price for Q1/2024 decreased with the decline in the benchmark price and represents a discount to the Edmonton par price of $1.11/bbl for Q1/2024 compared to a premium of $0.19/bbl in Q1/2023. We realized a discount to the Edmonton par price in Q1/2024 as a higher proportion of our light oil production is from our Duvernay assets which have a lower light oil price realization relative to our Viking assets.

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 $101.93/bbl for Q1/2024 compared to $103.27/bbl for Q1/2023. Expressed in U.S. dollars, our realized light oil and condensate price of US$75.57/bbl for Q1/2024 represents a discount to MEH of US$3.38/bbl for Q1/2024, compared to a discount of US$1.04/bbl for Q1/2023. The discount of US$3.38/bbl for Q1/2024 was primarily a result of contracts in place for our operated Eagle Ford production during Q1/2024.

Our realized heavy oil price, net of blending and other expense(1) was $65.22/bbl in Q1/2024 compared to $51.15/bbl in Q1/2023. This was $14.07/bbl higher than Q1/2023, compared to a $8.29/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 sales of the blended product based on the WCS benchmark in Q1/2024 compared to Q1/2023.

Our realized NGL price(2) 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 was $26.15/bbl in Q1/2024 or 25% of WTI (expressed in Canadian dollars) compared to $33.63/bbl or 33% of WTI (expressed in Canadian dollars) in Q1/2023. Our realized NGL price was lower as a percentage of WTI in Q1/2024 primarily due to lower demand for NGL products relative to Q1/2023.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. In the U.S., our realized natural gas price(2) was US$1.76/mcf for Q1/2024 compared to US$2.97/mcf for Q1/2023 which is primarily the result of the decrease in the NYMEX benchmark over the same period. In Canada our realized natural gas price was $2.42/mcf for Q1/2024 compared to $3.53/mcf in Q1/2023. The decrease in our realized price for Q1/2024 relative to Q1/2023 was less than the AECO benchmark as a greater proportion of our sales were based on the daily AECO index which was higher than the monthly AECO index for Q1/2024.

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

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

Baytex Energy Corp.                                            

Q1 2024 MD&A    6

PETROLEUM AND NATURAL GAS SALES

			Three Months Ended March 31
			2024									2023
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Oil sales
Light oil and condensate			$	95,221		$	505,894		$	601,115		$	146,456		$	142,011		$	288,467
Heavy oil			304,924			—			304,924			217,085			—			217,085
NGL			6,368			39,562			45,930			6,059			15,774			21,833
Total oil sales			406,513			545,456			951,969			369,600			157,785			527,385
Natural gas sales			9,800			22,423			32,223			16,022			11,929			27,951
Total petroleum and natural gas sales			416,313			567,879			984,192			385,622			169,714			555,336
Blending and other expense			(64,208)			—			(64,208)			(59,681)			—			(59,681)
Total sales, net of blending and other expense (1)			$	352,105		$	567,879		$	919,984		$	325,941		$	169,714		$	495,655

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

Total sales, net of blending and other expense, of $920.0 million for Q1/2024 increased $424.3 million from $495.7 million reported for Q1/2023. The increase in total sales is primarily the result of the Merger with Ranger along with higher production from our successful development programs.

In Canada, total sales, net of blending and other expense, of $352.1 million for Q1/2024 increased $26.2 million from $325.9 million reported for Q1/2023. The increase was primarily a result of higher realized pricing for Q1/2024 relative to Q1/2023 which resulted in a $14.8 million increase in total sales, net of blending and other expense. Higher production for Q1/2024 contributed to a $11.4 million increase in total sales, net of blending and other expense, relative to Q1/2023.

In the U.S., total petroleum and natural gas sales of $567.9 million for Q1/2024 increased $398.2 million from $169.7 million reported for Q1/2023. Total petroleum and natural gas sales increased $412.2 million from higher production in Q1/2024 relative to Q1/2023 as a result of the Merger with Ranger. The impact of increased production was partially offset by a $14.0 million decrease due to lower realized pricing compared to Q1/2023.

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
			2024									2023
($ thousands except for % and per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Royalties			$	56,564		$	152,607		$	209,171		$	43,855		$	49,398		$	93,253
Average royalty rate (1)(2)			16.1		%	26.9		%	22.7		%	13.5		%	29.1		%	18.8		%
Royalties per boe (3)			$	10.01		$	18.94		$	15.26		$	8.03		$	21.02		$	11.94

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

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

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

Royalties for Q1/2024 were $209.2 million or 22.7% of total sales, net of blending and other expense, compared to $93.3 million or 18.8% for Q1/2023. Total royalty expense and our average royalty rate were higher in Q1/2024 relative to Q1/2023 due to the Merger with Ranger which resulted in higher total sales, net of blending and other expense, along with a higher proportion of our production being from the Eagle Ford which has a higher royalty rate than our Canadian properties.

Our average royalty rate(1) in Canada of 16.1% for Q1/2024 was higher than 13.5% for Q1/2023 as a result of heavy oil production growth. In the U.S., royalties averaged 26.9% of total sales for Q1/2024, which is lower than 29.1% for Q1/2023 due to production contributed by the acquired Ranger assets which have a lower royalty rate relative to our legacy non-operated Eagle Ford properties.

Our average royalty rate of 22.7% for Q1/2024 is consistent with our annual guidance of 23% for 2024.

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.

OPERATING EXPENSE

			Three Months Ended March 31
			2024									2023
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Operating expense			$	85,403		$	88,032		$	173,435		$	91,180		$	21,228		$	112,408
Operating expense per boe (1)			$	15.12		$	10.93		$	12.65		$	16.70		$	9.03		$	14.40

(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 $173.4 million ($12.65/boe) for Q1/2024 compared to $112.4 million ($14.40/boe) for Q1/2023. Total operating expense for Q1/2024 increased relative to Q1/2023 due to higher production while lower per unit operating costs reflect the lower per boe operating expense on the properties acquired from Ranger.

In Canada, total operating expense was $85.4 million ($15.12/boe) for Q1/2024 which was lower than $91.2 million ($16.70/boe) for Q1/2023. The decrease in total and per unit operating expense for Q1/2024 reflects production growth at Peavine along with the disposition of non-core Viking assets in Q4/2023.

In the U.S., operating expense was $88.0 million ($10.93/boe) for Q1/2024 compared to $21.2 million ($9.03/boe) for Q1/2023. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$8.10/boe for Q1/2024 compared to US$6.68/boe for Q1/2023. The increase in total and per unit operating expense in Q1/2024 reflects the additional production from the properties acquired from Ranger along with higher workover and maintenance costs on our non-operated acreage.

Operating expense of $12.65/boe for Q1/2024 is consistent with expectations and our annual guidance range of $11.25 - $12.00/boe for 2024 reflects production growth over the remainder of the year.

TRANSPORTATION EXPENSE

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

The following table compares our transportation expense for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
			2024									2023
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Transportation expense			$	18,210		$	11,625		$	29,835		$	17,005		$	—		$	17,005
Transportation expense per boe (1)			$	3.22		$	1.44		$	2.18		$	3.12		$	—		$	2.18

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

Transportation expense was $29.8 million ($2.18/boe) for Q1/2024 compared to $17.0 million ($2.18/boe) for Q1/2023. In Canada, total transportation expense and per unit costs were higher in Q1/2024 as a result of additional heavy oil production relative to Q1/2023. In the U.S., transportation expense of $11.6 million consists of trucking and pipeline costs on our operated Eagle Ford operations acquired from Ranger.

Per unit transportation expense of $2.18/boe for Q1/2024 is consistent with expectations and is slightly below our annual guidance range of $2.35 - $2.55/boe for 2024.

Baytex Energy Corp.                                            

Q1 2024 MD&A    7

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 $64.2 million for Q1/2024 compared to $59.7 million for Q1/2023. Higher blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in Q1/2024 relative to Q1/2023.

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 months ended March 31, 2024 and 2023.

			Three Months Ended March 31
($ thousands)			2024			2023			Change
Realized financial derivatives gain
Crude oil			$	946		$	5,415		$	(4,469)
Natural gas			4,542			—			4,542
Total			$	5,488		$	5,415		$	73
Unrealized financial derivatives (loss) gain
Crude oil			$	(31,465)		$	9,210		$	(40,675)
Natural gas			(885)			—			(885)
Total			$	(32,350)		$	9,210		$	(41,560)
Total financial derivatives (loss) gain
Crude oil			$	(30,519)		$	14,625		$	(45,144)
Natural gas			3,657			—			3,657
Total			$	(26,862)		$	14,625		$	(41,487)

We recorded a total financial derivative loss of $26.9 million for Q1/2024 compared to a gain of $14.6 million for Q1/2023. The realized financial derivatives gain of $5.5 million for Q1/2024 was primarily a result of the market prices for natural gas settling at levels below those set in our derivative contracts. The unrealized financial derivatives loss of $32.4 million for Q1/2024 is primarily due to changes in forecasted crude oil pricing used to revalue the volumes outstanding on our crude oil and natural gas contracts in place at March 31, 2024 relative to December 31, 2023. The fair value of our financial derivative contracts resulted in a net liability of $9.1 million at March 31, 2024 compared to a net asset of $23.3 million at December 31, 2023.

Baytex Energy Corp.                                            

Q1 2024 MD&A    8

As at May 9, 2024 we had the following commodity financial derivative contracts for the period subsequent to March 31, 2024.

Remaining Period

Volume

Price/Unit (1)

Index

Oil

Basis differential

Apr 2024 to Jun 2024

4,000 bbl/d

Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.10/bbl

WCS

Basis differential

July 2024 to Dec 2024

9,000 bbl/d

Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.34/bbl

WCS

Basis differential

Apr 2024 to Dec 2024

3,000 bbl/d

Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.27/bbl

WCS

Basis differential (2)

July 2024 to Dec 2024

3,000 bbl/d

Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.25/bbl

WCS

Basis differential

July 2024 to Dec 2024

6,000 bbl/d

WTI less US$13.58/bbl

WCS

Basis differential

Apr 2024 to Dec 2024

2,750 bbl/d

WTI less US$2.94/bbl

MSW

Basis differential

July 2024 to Dec 2024

3,500 bbl/d

WTI less US$2.78/bbl

MSW

Basis differential (2)

Jan 2025 to Dec 2025

2,000 bbl/d

WTI less US$2.75/bbl

MSW

Collar

Apr 2024 to Jun 2024

35,250 bbl/d

US$60.00/US$100.00

WTI

Collar

July 2024 to Dec 2024

10,000 bbl/d

US$60.00/US$100.00

WTI

Collar

July 2024 to Sep 2024

10,000 bbl/d

US$60.00/US$100.00

WTI

Collar

Oct 2024 to Dec 2024

2,500 bbl/d

US$60.00/US$100.00

WTI

Collar

July 2024 to Dec 2024

2,500 bbl/d

US$60.00/US$94.15

WTI

Collar

July 2024 to Dec 2024

1,500 bbl/d

US$60.00/US$90.35

WTI

Collar

July 2024 to Dec 2024

1,000 bbl/d

US$60.00/US$90.00

WTI

Collar

July 2024 to Dec 2024

2,000 bbl/d

US$60.00/US$85.00

WTI

Collar

July 2024 to Dec 2024

2,000 bbl/d

US$60.00/US$84.60

WTI

Collar

July 2024 to Dec 2024

5,000 bbl/d

US$60.00/US$84.15

WTI

Collar

Oct 2024 to Dec 2024

3,500 bbl/d

US$60.00/US$87.10

WTI

Collar

Oct 2024 to Dec 2024

3,500 bbl/d

US$60.00/US$85.75

WTI

Collar

Jan 2025 to Mar 2025

5,000 bbl/d

US$60.00/US$88.70

WTI

Collar (2)

Jan 2025 to Mar 2025

2,500 bbl/d

US$60.00/US$90.20

WTI

Collar (2)

Jan 2025 to Mar 2025

2,500 bbl/d

US$60.00/US$90.05

WTI

Collar (2)

Jan 2025 to Mar 2025

2,500 bbl/d

US$60.00/US$90.00

WTI

Collar (2)

Jan 2025 to Jun 2025

2,500 bbl/d

US$60.00/US$94.25

WTI

Collar (2)

Jan 2025 to Jun 2025

2,500 bbl/d

US$60.00/US$93.90

WTI

Collar (2)

Jan 2025 to Jun 2025

5,000 bbl/d

US$60.00/US$91.95

WTI

Collar (2)

Jan 2025 to Jun 2025

2,500 bbl/d

US$60.00/US$90.00

WTI

Natural Gas

Collar

Apr 2024 to Dec 2024

5,000 mmbtu/d

US$3.00/US$4.19

NYMEX

Collar

Apr 2024 to Dec 2024

8,500 mmbtu/d

US$3.00/US$4.15

NYMEX

Collar

Apr 2024 to Dec 2024

5,000 mmbtu/d

US$3.00/US$4.10

NYMEX

Collar

Apr 2024 to Dec 2024

2,500 mmbtu/d

US$3.00/US$4.09

NYMEX

Collar

Apr 2024 to Dec 2024

2,500 mmbtu/d

US$3.00/US$4.06

NYMEX

Collar

Apr 2024 to Jun 2024

11,538 mmbtu/d

US$2.33/US$3.00

NYMEX

Collar

Jan 2025 to Dec 2025

7,000 mmbtu/d

US$3.00/US$4.01

NYMEX

Collar (2)

Jan 2025 to Dec 2025

7,000 mmbtu/d

US$3.00/US$4.32

NYMEX

(1)Based on the weighted average price per unit for the period.

(2)Contract entered subsequent to March 31, 2024.

Baytex Energy Corp.                                            

Q1 2024 MD&A    9

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
			2024									2023
($ per boe except for volume)			Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)			62,081			88,540			150,620			60,651			26,109			86,760
Operating netback:
Total sales, net of blending and other expense (1)			$	62.33		$	70.48		$	67.12		$	59.71		$	72.22		$	63.48
Less:
Royalties (2)			(10.01)			(18.94)			(15.26)			(8.03)			(21.02)			(11.94)
Operating expense (2)			(15.12)			(10.93)			(12.65)			(16.70)			(9.03)			(14.40)
Transportation expense (2)			(3.22)			(1.44)			(2.18)			(3.12)			—			(2.18)
Operating netback (1)			$	33.98		$	39.17		$	37.03		$	31.86		$	42.17		$	34.96
Realized financial derivatives gain (3)			—			—			0.40			—			—			0.69
Operating netback after financial derivatives (1)			$	33.98		$	39.17		$	37.43		$	31.86		$	42.17		$	35.65

(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)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.

Total operating netback of $37.03/boe for Q1/2024 was higher than $34.96/boe for Q1/2023 due to the increase in our realized price which resulted in higher per unit sales net of royalties during Q1/2024 relative to Q1/2023. A higher proportion of our production was from our U.S. properties in Q1/2024 which have lower operating and transportation expense which resulted in total operating and transportation expense of $14.83/boe for Q1/2024 that was lower than $16.58/boe for Q1/2023. Our operating netback net of realized gains and losses on financial derivatives was $37.43/boe for Q1/2024 compared to $35.65/boe for Q1/2023.

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.

The following table summarizes our G&A expense for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
($ thousands except for per boe)			2024			2023			Change
Gross general and administrative expense			$	28,763		$	14,416		$	14,347
Overhead recoveries			(6,351)			(2,682)			(3,669)
General and administrative expense			$	22,412		$	11,734		$	10,678
General and administrative expense per boe (1)			$	1.64		$	1.50		$	0.14

(1)General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period.

G&A expense was $22.4 million ($1.64/boe) for Q1/2024 compared to $11.7 million ($1.50/boe) for Q1/2023. G&A expense was $10.7 million higher relative to Q1/2023 which reflects the staffing costs associated with the personnel retained following the Merger with Ranger. G&A expense of $1.64/boe for Q1/2024 is consistent with our 2024 annual guidance of $1.65/boe.

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.

Baytex Energy Corp.                                            

Q1 2024 MD&A    10

The following table summarizes our financing and interest expense for the three months ended March 31, 2024 and 2023.

			Three Months Ended March 31
($ thousands except for per boe)			2024			2023			Change
Interest on credit facilities			$	18,289		$	6,216		$	12,073
Interest on long-term notes			34,678			12,094			22,584
Interest on lease obligations			313			65			248
Cash interest			$	53,280		$	18,375		$	34,905
Accretion of debt issue costs			3,060			524			2,536
Accretion of asset retirement obligations			4,927			4,826			101
Financing and interest expense			$	61,267		$	23,725		$	37,542
Cash interest per boe (1)			$	3.89		$	2.35		$	1.54
Financing and interest expense per boe (1)			$	4.47		$	3.04		$	1.43

(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 $61.3 million ($4.47/boe) for Q1/2024 compared to $23.7 million ($3.04/boe) for Q1/2023. Higher interest costs in Q1/2024 compared to Q1/2023 are primarily the result of the additional debt outstanding after the Merger with Ranger.

Cash interest of $53.3 million ($3.89/boe) for Q1/2024 was higher than $18.4 million ($2.35/boe) for Q1/2023 and is primarily a 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. Interest on our credit facilities increased in Q1/2024 relative to Q1/2023 due to higher applicable borrowing rates along with additional principal amounts outstanding following the Merger. The weighted average interest rate applicable on our credit facilities was 8.1% for Q1/2024 compared to 6.0% for Q1/2023.

Accretion of asset retirement obligations of $4.9 million for Q1/2024 was consistent with $4.8 million for Q1/2023. Accretion of debt issue costs was higher for Q1/2024 compared to Q1/2023 due to the increase in debt issue costs associated with the increased credit facilities and new long-term notes issued to fund the Merger with Ranger.

Cash interest expense of $3.89/boe for Q1/2024 is higher than our 2024 annual guidance of $3.40/boe which is consistent with expectations as we expect to reduce debt and increase production throughout the remainder of 2024.

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 $18.0 thousand for Q1/2024 compared to $163.0 thousand for Q1/2023.

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 months ended March 31, 2024 and 2023.

			Three Months Ended March 31
($ thousands except for per boe)			2024			2023			Change
Depletion			$	341,435		$	164,435		$	177,000
Depreciation			2,702			1,564			1,138
Depletion and depreciation			$	344,137		$	165,999		$	178,138
Depletion and depreciation per boe (1)			$	25.11		$	21.26		$	3.85

(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 $344.1 million ($25.11/boe) for Q1/2024 compared to $166.0 million ($21.26/boe) for Q1/2023. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q1/2024 relative to Q1/2023 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.

Baytex Energy Corp.                                            

Q1 2024 MD&A    11

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at March 31, 2024.

2023 Impairment

At December 31, 2023, we identified indicators of impairment for oil and gas properties 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. We recorded an impairment loss of $833.7 million.

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 $9.5 million for Q1/2024 which is consistent with $9.8 million for Q1/2023.

FOREIGN EXCHANGE

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

			Three Months Ended March 31
($ thousands except for exchange rates)			2024			2023			Change
Unrealized foreign exchange loss (gain)			$	38,718		$	(213)		$	38,931
Realized foreign exchange loss			1,219			150			1,069
Foreign exchange loss (gain)			$	39,937		$	(63)		$	40,000
CAD/USD exchange rates:
At beginning of period			1.3205			1.3534
At end of period			1.3533			1.3528

We recorded a foreign exchange loss of $39.9 million for Q1/2024 compared to a gain of $0.1 million for Q1/2023.

The unrealized foreign exchange loss of $38.7 million for Q1/2024 is due to changes in the reported amount of our long-term notes and credit facilities. The $38.7 million loss recorded in Q1/2024 is the result of a weak Canadian dollar relative to the U.S. dollar at March 31, 2024 compared to December 31, 2023. The unrealized foreign exchange gain of $0.2 million for Q1/2023 is primarily related to changes in the reported amount of our long-term notes due to a strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2023 compared to 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 loss of $1.2 million for Q1/2024 compared to $0.2 million for Q1/2023.

INCOME TAXES

			Three Months Ended March 31
($ thousands)			2024			2023			Change
Current income tax expense			$	1,680		$	1,120		$	560
Deferred income tax expense			15,801			15,523			278
Total income tax expense			$	17,481		$	16,643		$	838

Current income tax expense was $1.7 million for Q1/2024 compared to $1.1 million for Q1/2023.

Baytex Energy Corp.                                            

Q1 2024 MD&A    12

We recorded deferred tax expense of $15.8 million for Q1/2024 compared to $15.5 million for Q1/2023. The deferred tax expense recorded in Q1/2024 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 Q1/2023 reflects the income generated by our Canadian and U.S. operations for the period.

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 $166.6 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 potentially 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.                                            

Q1 2024 MD&A    13

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income for the three months ended March 31, 2024 and 2023 are set forth in the following table.

			Three Months Ended March 31
($ thousands)			2024			2023			Change
Petroleum and natural gas sales			$	984,192		$	555,336		$	428,856
Royalties			(209,171)			(93,253)			(115,918)
Revenue, net of royalties			775,021			462,083			312,938
Expenses
Operating			(173,435)			(112,408)			(61,027)
Transportation			(29,835)			(17,005)			(12,830)
Blending and other			(64,208)			(59,681)			(4,527)
Operating netback (1)			$	507,543		$	272,989		$	234,554
General and administrative			(22,412)			(11,734)			(10,678)
Cash interest			(53,280)			(18,375)			(34,905)
Realized financial derivatives gain			5,488			5,415			73
Realized foreign exchange loss			(1,219)			(150)			(1,069)
Other expense			(1,071)			(213)			(858)
Current income tax expense			(1,680)			(1,120)			(560)
Cash share-based compensation			(9,523)			(9,823)			300
Adjusted funds flow (2)			$	423,846		$	236,989		$	186,857
Transaction costs			(1,539)			(8,871)			7,332
Exploration and evaluation			(18)			(163)			145
Depletion and depreciation			(344,137)			(165,999)			(178,138)
Non-cash financing and interest			(7,987)			(5,350)			(2,637)
Non-cash other income			—			1,271			(1,271)
Unrealized financial derivatives (loss) gain			(32,350)			9,210			(41,560)
Unrealized foreign exchange (loss) gain			(38,718)			213			(38,931)
Gain (loss) on dispositions			2,661			(336)			2,997
Deferred income tax expense			(15,801)			(15,523)			(278)
Net (loss) income			$	(14,043)		$	51,441		$	(65,484)

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

We generated adjusted funds flow of $423.8 million for Q1/2024 compared to $237.0 million for Q1/2023. The $186.9 million increase in adjusted funds flow was primarily due to higher production from the Merger with Ranger, partially offset by higher general and administrative and cash interest costs. We reported a net loss of $14.0 million for Q1/2024 compared to net income of $51.4 million for Q1/2023. The decrease in net income for Q1/2024 relative to Q1/2023 is the result of a higher depletion rate and associated depreciation expense, as well as unrealized losses on financial derivatives and an unrealized foreign exchange loss.

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 gain of $110.6 million for Q1/2024 relates to the change in value of our U.S. net assets and is due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2024 compared to December 31, 2023. The CAD/USD exchange rate was 1.3533 CAD/USD as at March 31, 2024 compared to 1.3205 CAD/USD at December 31, 2023.

Baytex Energy Corp.                                            

Q1 2024 MD&A    14

CAPITAL EXPENDITURES

Capital expenditures for the three months ended March 31, 2024 and 2023 are summarized as follows.

			Three Months Ended March 31
			2024									2023
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Drilling, completion and equipping			$	126,007		$	219,939		$	345,946		$	154,953		$	48,836		$	203,789
Facilities and other			32,119			34,486			66,605			29,653			184			29,837
Exploration and development expenditures			$	158,126		$	254,425		$	412,551		$	184,606		$	49,020		$	233,626
Property acquisitions			$	34,275		$	1,128		$	35,403		$	506		$	—		$	506
Proceeds from dispositions			$	(25)		$	—		$	(25)		$	(235)		$	—		$	(235)

Exploration and development expenditures were $412.6 million for Q1/2024 compared to $233.6 million for Q1/2023. Exploration and development expenditures in Q1/2024 were higher compared to Q1/2023 as a result of development activity on the properties acquired from Ranger. We also completed property acquisitions, including the acquisition of 30.75 net sections of high-quality Duvernay lands adjacent to our existing acreage, in Q1/2024 for a total of $35.4 million.

In Canada, exploration and development expenditures were $158.1 million in Q1/2024 compared to $184.6 million in Q1/2023. Lower drilling and completion spending of $126.0 million in Q1/2024 relative to Q1/2023 when we spent $155.0 million was primarily the result of the disposition of non-core light oil Viking properties. We also invested $32.1 million on facilities and other expenditures during Q1/2024.

Total U.S. exploration and development expenditures were $254.4 million for Q1/2024 compared to $49.0 million in Q1/2023. The increase in exploration and development expenditures for Q1/2024 is due to development activity on our properties acquired from Ranger.

Exploration and development expenditures of $412.6 million for Q1/2024 were consistent with expectation. Our annual guidance of $1.2 - $1.3 billion reflects moderated activity levels over the remainder of 2024.

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 March 31, 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 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. At March 31, 2024, net debt(1) of $2.6 billion was consistent with $2.5 billion at December 31, 2023 and reflects the timing of exploration and development expenditures, minor property acquisitions, along with the effect of a weaker Canadian dollar relative to the U.S. dollar at March 31, 2024 compared to December 31, 2023.

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

Credit Facilities

At March 31, 2024, we had $849.9 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 are no changes to the loan balances or financial covenants as a result of the amendment. As a result of the amendment, borrowing in Canadian funds currently based on the banker's acceptance rate will be 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 Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the Credit Facilities was 8.1% for Q1/2024 compared to 6.0% for Q1/2023. The interest rate on our Credit Facilities has increased due to an increase in the margins applicable to our Credit Facilities in addition to higher underlying benchmark rates in 2024 relative to the same period in 2023.

At March 31, 2024, we had $5.7 million of outstanding letters of credit, $4.3 million of which is under a $20 million uncommitted unsecured demand revolving letter of credit facility (December 31, 2023 - $5.6 million outstanding). Letters of credit under this facility are guaranteed by Export Development Canada and do not use capacity available under the Credit Facilities.

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

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2024.

Covenant Description			Position as at March 31, 2024			Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)			0.4:1.0			3.5:1.0
Interest Coverage (3) (Minimum Ratio)			10.3:1.0			3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)			1.1:1.0			4:0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at March 31, 2024, the Company's Senior Secured Debt totaled $849.9 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 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. Financing and interest expense for the twelve months ended March 31, 2024 was $211.3 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 March 31, 2024, the Company's Total Debt totaled $2.5 billion of principal amounts outstanding.

Long-Term Notes

At March 31, 2024 we have two issuances of long-term notes outstanding with a total principal amount of $1.6 billion. The long-term notes do not contain any financial maintenance covenants.

On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes"). The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. At March 31, 2024 there was US$409.8 million aggregate principal amount of the 8.75% Senior Notes outstanding.

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 March 31, 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.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2024, we issued 0.3 million common shares pursuant to our share-based compensation program. As at March 31, 2024, we had 821.3 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 three months ended March 31, 2024, we repurchased 0.6 million common shares under our normal course issuer bid ("NCIB") at an average price of $4.76 per share.

On January 2 and April 1, 2024, we paid a quarterly cash dividend of CDN$0.0225 per share to shareholders of record. On May 9, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on July 2, 2024 for shareholders on record as at June 14, 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 March 31, 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
Financial derivatives			14,510			14,510			—			—			—
Credit facilities - principal			849,926			—			849,926			—			—
Long-term notes - principal (2)			1,637,155			—			—			554,555			1,082,600
Interest on long-term notes (1)(2)			705,645			140,545			281,089			184,175			99,836
Lease obligations - principal			33,829			12,847			9,195			7,213			4,574
Processing agreements			5,488			588			965			3,935			—
Transportation agreements			201,668			53,546			92,629			45,655			9,838
Total			$	3,448,221		$	222,036		$	1,233,804		$	795,533		$	1,196,848

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

(2)Excludes principal and interest on the 7.375% Senior Notes that were issued on April 1, 2024.

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.                                            

Q1 2024 MD&A    15

QUARTERLY FINANCIAL INFORMATION

			2024			2023												2022
($ thousands, except per common share amounts)			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Petroleum and natural gas sales			984,192			1,065,515			1,163,010			598,760			555,336			648,986			712,065			854,169
Net (loss) income			(14,043)			(625,830)			127,430			213,603			51,441			352,807			264,968			180,972
Per common share - basic			(0.02)			(0.75)			0.15			0.37			0.09			0.65			0.48			0.32
Per common share - diluted			(0.02)			(0.75)			0.15			0.36			0.09			0.64			0.47			0.32
Adjusted funds flow (1)			423,846			502,148			581,623			273,590			236,989			255,552			284,288			345,704
Per common share - basic			0.52			0.60			0.68			0.47			0.43			0.47			0.51			0.61
Per common share - diluted			0.52			0.60			0.68			0.47			0.43			0.46			0.51			0.60
Free cash flow (2)			(88)			290,785			158,440			96,313			(1,918)			143,324			111,568			245,316
Per common share - basic			—			0.35			0.19			0.17			—			0.26			0.20			0.43
Per common share - diluted			—			0.35			0.18			0.16			—			0.26			0.20			0.43
Cash flows from operating activities			383,773			474,452			444,033			192,308			184,938			303,441			310,423			360,034
Per common share - basic			0.47			0.57			0.52			0.33			0.34			0.56			0.56			0.63
Per common share - diluted			0.47			0.57			0.52			0.33			0.34			0.55			0.56			0.63
Dividends declared			18,494			18,381			19,138			—			—			—			—			—
Per common share – basic			0.02			0.02			0.02			—			—			—			—			—
Per common share – diluted			0.02			0.02			0.02			—			—			—			—			—
Exploration and development			412,551			199,214			409,191			170,704			233,626			103,634			167,453			96,633
Canada			158,126			75,137			107,053			96,403			184,606			85,641			117,150			51,881
U.S.			254,425			124,077			302,138			74,301			49,020			17,993			50,303			44,752
Property acquisitions			35,403			33,923			4,277			(62)			506			1,085			—			208
Proceeds from dispositions			(25)			(159,745)			(226)			(50)			(235)			(148)			(25,460)			(14)
Net debt (1)			2,639,841			2,534,287			2,824,348			2,814,844			995,170			987,446			1,113,559			1,123,297
Total assets			7,717,495			7,460,931			8,946,181			8,617,444			5,180,059			5,103,769			4,923,617			4,870,432
Common shares outstanding			821,322			821,681			845,360			862,192			545,553			544,930			547,615			560,139
Daily production
Total production (boe/d)			150,620			160,373			150,600			89,761			86,760			86,864			83,194			83,090
Canada (boe/d)			62,081			64,744			63,289			55,874			60,651			56,946			55,803			54,919
U.S. (boe/d)			88,540			95,629			87,311			33,887			26,109			29,918			27,391			28,170
Benchmark prices
WTI oil (US$/bbl)			76.96			78.32			82.26			73.78			76.13			82.64			91.56			108.41
WCS heavy oil ($/bbl)			77.73			76.86			93.02			78.85			69.44			77.37			93.62			122.05
Edmonton par oil ($/bbl)			92.16			99.72			107.93			95.13			99.04			109.57			116.79			137.79
CAD/USD avg exchange rate			1.3488			1.3619			1.3410			1.3431			1.3520			1.3577			1.3059			1.2766
AECO natural gas ($/mcf)			2.05			2.66			2.39			2.35			4.34			5.58			5.81			6.27
NYMEX natural gas (US$/mmbtu)			2.24			2.88			2.55			2.10			3.42			6.26			8.20			7.17
Total sales, net of blending and other expense ($/boe) (2)			67.12			68.00			80.34			66.82			63.48			74.93			87.68			105.44
Royalties ($/boe) (3)			(15.26)			(15.49)			(17.33)			(13.21)			(11.94)			(15.23)			(19.21)			(22.69)
Operating expense ($/boe) (3)			(12.65)			(11.17)			(12.57)			(14.62)			(14.40)			(13.06)			(14.39)			(14.21)
Transportation expense ($/boe) (3)			(2.18)			(2.02)			(2.02)			(1.78)			(2.18)			(1.85)			(1.67)			(1.56)
Operating netback ($/boe) (2)			37.03			39.32			48.42			37.21			34.96			44.79			52.41			66.98
Financial derivatives (loss) gain ($/boe) (3)			0.40			0.84			0.15			2.00			0.69			(6.21)			(9.98)			(16.41)
Operating netback after financial derivatives ($/boe) (2)			37.43			40.16			48.57			39.21			35.65			38.58			42.43			50.57

(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.

(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.                                            

Q1 2024 MD&A    16

Our results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have fluctuated. Production steadily increased from 83,090 boe/d in Q2/2022 and reached 160,373 boe/d in Q4/2023 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. Production of 150,620 boe/d in Q1/2024 reflects the timing of our development programs along with asset dispositions.

Commodity prices strengthened to multi-year highs in 2022 following Russia's invasion of Ukraine which created elevated uncertainty surrounding the global supply of oil and natural gas and is reflected in our realized sales price of $105.44/boe for Q2/2022, which is our strongest realized pricing in the most recent eight quarters. Our realized price of $67.12/boe for Q1/2024 reflects recent stability in crude oil prices as global supply growth and stable demand has resulted in a more balanced market.

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 $423.8 million for Q1/2024 reflects strong production results from our development plans in the U.S. and Canada as well as the Merger with Ranger.

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 $2.6 billion at Q1/2024 from $1.1 billion at Q2/2022 as a result of additional debt used to fund the Merger which closed in Q2/2023 along with $439.9 million of shareholder returns. The change in net debt also reflects free cash flow(2) of $1.0 billion generated over the last eight quarters.

(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.

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. In addition to the Risk Factors discussed in the AIF for the year ended December 31, 2023, additional information related to our emissions and sustainability initiatives is available on our website.

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 March 31, 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 three months ended March 31, 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.

In October 2022, the IASB issued Non-current Liabilities with Covenants which amended IAS 1 Presentation of Financial Statements. The amendments specify the classification and disclosure of a liability with covenants and is effective January 1, 2024.

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

Baytex Energy Corp.                                            

Q1 2024 MD&A    17

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
($ thousands)			March 31, 2024						March 31, 2023
Petroleum and natural gas sales			$	984,192					$	555,336
Light oil and condensate (1)			(601,115)						(288,467)
NGL (1)			(45,930)						(21,833)
Natural gas sales (1)			(32,223)						(27,951)
Heavy oil sales			$	304,924					$	217,085
Blending and other expense (2)			(64,208)						(59,681)
Heavy oil, net of blending and other expense			$	240,716					$	157,404

(1)Component of petroleum and natural gas sales. See Note 13 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three months ended March 31, 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.                                            

Q1 2024 MD&A    18

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

			Three Months Ended
($ thousands)			March 31, 2024						March 31, 2023
Petroleum and natural gas sales			$	984,192					$	555,336
Blending and other expense			(64,208)						(59,681)
Total sales, net of blending and other expense			$	919,984					$	495,655
Royalties			(209,171)						(93,253)
Operating expense			(173,435)						(112,408)
Transportation expense			(29,835)						(17,005)
Operating netback			$	507,543					$	272,989
Realized financial derivatives gain (1)			5,488						5,415
Operating netback after realized financial derivatives			$	513,031					$	278,404

(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 months ended March 31, 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 and transaction costs.

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

			Three Months Ended
($ thousands)			March 31, 2024						March 31, 2023
Cash flows from operating activities			$	383,773					$	184,938
Change in non-cash working capital			32,023						39,054
Additions to exploration and evaluation assets			—						(490)
Additions to oil and gas properties			(412,551)						(233,136)
Payments on lease obligations			(4,872)						(1,155)
Transaction costs			1,539						8,871
Free cash flow			$	(88)					$	(1,918)

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.                                            

Q1 2024 MD&A    19

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)			March 31, 2024			December 31, 2023
Credit facilities			$	835,363		$	848,749
Unamortized debt issuance costs - Credit facilities (1)			14,563			15,987
Long-term notes			1,602,417			1,562,361
Unamortized debt issuance costs - Long-term notes (1)			34,738			35,114
Trade payables			626,137			477,295
Share-based compensation liability			18,667			35,732
Dividends payable			18,494			18,381
Other long-term liabilities			19,622			19,147
Cash			(29,140)			(55,815)
Trade receivables			(423,119)			(339,405)
Prepaids and other assets			(77,901)			(83,259)
Net debt			$	2,639,841		$	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 months ended March 31, 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 and transaction costs.

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

			Three Months Ended
($ thousands)			March 31, 2024						March 31, 2023
Cash flow from operating activities			$	383,773					$	184,938
Change in non-cash working capital			32,023						39,054
Asset retirement obligations settled			6,511						4,126
Transaction costs			1,539						8,871
Adjusted funds flow			$	423,846					$	236,989

Baytex Energy Corp.                                            

Q1 2024 MD&A    20

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 changes were made to, internal controls over financial reporting during the three months ended March 31, 2024, except for the matter described below.

On June 20, 2023, Baytex completed the acquisition of Ranger, a publicly traded oil and gas company that was listed on the NASDAQ exchange. Ranger's operations have been included in the consolidated financial statements of Baytex since June 20, 2023. However, Baytex has not had sufficient time to appropriately assess the disclosure controls and procedures and internal controls over financial reporting previously used by Ranger and integrate them with those of Baytex. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of Ranger (as permitted by applicable securities laws in Canada and the U.S.). Baytex has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by June 20, 2024.

During the three months ended March 31, 2024, the assets previously held by Ranger contributed revenues of $309.1 million (representing 31% of total revenues) and net income before tax of $38.2 million (representing 1112% of net income before tax). At March 31, 2024, current assets of $256.4 million, non-current assets of $1.7 billion, current liabilities of $284.3 million and non-current liabilities of $95.6 million were associated with the acquired entity.

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: expectation 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; that we expect to increase production and reduce debt through the balance of 2024; 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 or sell assets; 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

Baytex Energy Corp.                                            

Q1 2024 MD&A    21

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 Corporation'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 Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation 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 are subject to the discretion of the Board of Directors of Baytex.