Baytex Energy Corp.                                            

Q2 2023 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three and six months ended June 30, 2023 and 2022

Dated July 27, 2023

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2023. This information is provided as of July 27, 2023. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and six months ended June 30, 2023 ("Q2/2023" and "YTD 2023") have been compared with the results for the three and six months ended June 30, 2022 ("Q2/2022" and "YTD 2022"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) as at June 30, 2023, and for the three and six months ended June 30, 2023 and 2022, its audited comparative consolidated financial statements for the years ended December 31, 2022 and 2021, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2022. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com 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 energy 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 assets in Texas.

SECOND QUARTER HIGHLIGHTS

Business Combination

On June 20, 2023, Baytex and Ranger Oil Corporation ("Ranger") completed the merger of the two companies (the "Merger") whereby Baytex acquired all of the issued and outstanding common shares of Ranger. The Merger increases our Eagle Ford scale and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford. Production from the Ranger assets is approximately 70% weighted towards high netback light oil and is primarily operated which increases our ability to effectively allocate capital.

Operating and financial results for Q2/2023 include Ranger operations from the closing date of June 20, 2023 to June 30, 2023. Production from the properties contributed approximately 7,500 boe/d and 3,800 boe/d of production to Q2/2023 and YTD 2023, respectively. The companies began integration in Q2/2023 and operations have continued in-line with expectations for both the legacy Baytex and Ranger assets. The Merger was primarily funded with a combination of cash and shares.

We issued 311.4 million common shares and paid cash consideration of $732.8 million in addition to the assumption of $1.1 billion of Ranger's net debt. The cash portion of the transaction was funded with our expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. We closed the US$800 million principal amount senior unsecured note offering on April 27, 2023 with the proceeds released from escrow at completion of the Merger.

Baytex Energy Corp.                                            

Q2 2023 MD&A    2

Second Quarter Operating and Financial Results

Baytex delivered strong operating and financial results in Q2/2023. Production of 89,761 boe/d for Q2/2023 reflects the production contribution from the Merger with Ranger in addition to our successful development programs in the U.S. and Canada. Wildfires impacted our operations in Alberta and resulted in the temporary curtailment of production which reduced production for Q2/2023 by approximately 4,500 boe/d. We invested $170.7 million on exploration and development expenditures and generated free cash flow(1) of $96.3 million during Q2/2023.

Exploration and development expenditures totaled $170.7 million in Q2/2023. In the U.S. we invested $74.3 million during Q2/2023 which included $34.1 million of expenditures on our operated Eagle Ford properties subsequent to acquisition on June 20, 2023 to June 30, 2023. Production in the U.S. averaged 33,887 boe/d in Q2/2023 compared to 28,170 boe/d in Q2/2022. The increase in U.S. production is due to the production contribution from the properties acquired from Ranger which added 7,500 boe/d for Q2/2023. Production on our non-operated properties in the U.S. declined slightly relative to Q2/2022 with overall activity decreasing on our acreage. We invested $96.4 million in Canada in Q2/2023 that was primarily directed towards light oil development and included completion activities for six Duvernay wells expected to come on production during the third quarter. Production in Canada averaged 55,874 boe/d during Q2/2023 compared to 54,919 boe/d in Q2/2022. Production for Q2/2023 reflects the temporary curtailment of production due to Alberta wildfires which reduced production for the period by approximately 4,500 boe/d. There was no significant physical damage to our operations or assets as a result of the wildfires.

Oil prices decreased in Q2/2023 on concerns of an economic slowdown causing lower demand for crude oil as central banks continued to increase interest rates to combat inflation. The WTI and WCS differential benchmarks averaged US$73.78/bbl and US $15.07/bbl during Q2/2023 compared to US$108.41/bbl and US$12.80/bbl respectively in Q2/2022. Adjusted funds flow(2) of $273.6 million and cash flows from operating activities of $192.3 million for Q2/2023 reflect commodity prices that were lower relative to Q2/2022 when we generated adjusted funds flow of $345.7 million and cash flows from operating activities of $360.0 million.

Net debt(2) of $2.8 billion at June 30, 2023 increased from $987.4 million at December 31, 2022 due to the cash consideration paid and net debt assumed in conjunction with the Merger with Ranger. We increased our shareholder returns to 50% of free cash flow in conjunction with the closing of the Merger which will allow us to increase our share buyback program and introduce a dividend. The remainder of our free cash flow will be allocated to debt reduction.

On June 23, 2023, we renewed our Normal Course Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Subsequent to June 30, 2023 and through to July 26, 2023, we repurchased 4.7 million common shares at an average price of $4.59 per share. The Board of Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023. 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.”

(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.

2023 GUIDANCE

Following the Merger with Ranger, Baytex has emerged as a well-capitalized, diversified oil-weighted North American exploration and production company with a strong free cash flow profile. For 2023, we continue to forecast exploration and development expenditures of $1,005 to $1,045 million, which are expected to generate production of 120,500 to 122,500 boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production mix for the second half of 2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.

The following tables summarizes our 2023 guidance for production and exploration and development expenditures.

	H1/2023 Actual	H2/2023 Guidance	2023 Guidance
Production (boe/d)	88,269	153,000-157,000	120,500-122,500
Exploration and development expenditures ($ millions)	$404	$601-$641	$1,005-$1,045

We have updated our full-year 2023 cost assumptions to reflect the Ranger acquisition. Operating expense guidance decreased by 13% to reflect the low cash cost structure of the Ranger assets, general and administrative expenses increased by 10% on a boe basis to reflect costs associated with Ranger personnel and interest expense guidance is higher due to the incremental debt associated with the Ranger acquisition and higher interest rates on our credit facilities.

Baytex Energy Corp.                                            

Q2 2023 MD&A    3

The following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.

	2023 Original Guidance (1)	2023 Revised Guidance
Expenses:
Average royalty rate (2)	20.0 - 22.0%	21.0 - 22.0%
Operating (3)	$14.00 - $14.75/boe	$12.25 - $12.75/boe
Transportation (3)	$1.90 - $2.10/boe	$2.00 - $2.10/boe
General and administrative (3)	$52 million ($1.63/boe)	$80 million ($1.80/boe)
Interest (3)	$65 million ($2.04/boe)	$150 million ($3.38/boe)
Leasing expenditures	$4 million	$13 million
Asset retirement obligations	$25 million	$25 million

(1)As announced on December 7, 2022.

(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.

Baytex Energy Corp.                                            

Q2 2023 MD&A    4

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 Eagle Ford assets in Texas.

Production

	Three Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	14,612		20,710		35,322		15,675		17,332		33,007
Heavy oil	32,821		—		32,821		28,586		—		28,586
Natural Gas Liquids (NGL)	1,434		7,186		8,620		1,818		5,650		7,468
Total liquids (bbl/d)	48,867		27,896		76,763		46,079		22,982		69,061
Natural gas (mcf/d)	42,043		35,946		77,989		53,036		31,133		84,169
Total production (boe/d)	55,874		33,887		89,761		54,919		28,170		83,090
Production Mix
Segment as a percent of total	62	%	38	%	100	%	66	%	34	%	100	%
Light oil and condensate	26	%	61	%	39	%	29	%	62	%	40	%
Heavy oil	59	%	—	%	37	%	52	%	—	%	34	%
NGL	3	%	21	%	10	%	3	%	20	%	9	%
Natural gas	12	%	18	%	14	%	16	%	18	%	17	%
	Six Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	15,500		18,010		33,510		16,619		16,914		33,533
Heavy oil	33,502		—		33,502		26,921		—		26,921
Natural Gas Liquids (NGL)	1,653		6,267		7,920		1,877		5,675		7,552
Total liquids (bbl/d)	50,655		24,277		74,932		45,417		22,589		68,006
Natural gas (mcf/d)	45,562		34,455		80,017		52,443		31,430		83,873
Total production (boe/d)	58,249		30,020		88,269		54,156		27,828		81,985
Production Mix
Segment as a percent of total	66	%	34	%	100	%	66	%	34	%	100	%
Light oil and condensate	27	%	60	%	38	%	31	%	61	%	41	%
Heavy oil	58	%	—	%	38	%	50	%	—	%	33	%
NGL	3	%	21	%	9	%	3	%	20	%	9	%
Natural gas	12	%	19	%	15	%	16	%	19	%	17	%

Production was 89,761 boe/d for Q2/2023 and 88,269 boe/d for YTD 2023 compared to 83,090 boe/d for Q2/2022 and 81,985 boe/d for YTD 2022. Production for Q2/2023 and YTD 2023 was higher than the same periods of 2022 primarily due to the Merger with Ranger which closed on June 20, 2023 and added approximately 7,500 boe/d to Q2/2023 production and 3,800 boe/d to YTD 2023 production.

Baytex Energy Corp.                                            

Q2 2023 MD&A    5

In Canada, production was 55,874 boe/d for Q2/2023 and 58,249 boe/d for YTD 2023 compared to 54,919 boe/d for Q2/2022 and

54,156 boe/d for YTD 2022. Our successful development program and strong well performance from our Clearwater assets at Peavine resulted in a 955 boe/d increase in production for Q2/2023 and 4,093 boe/d for YTD 2023 relative to the comparative periods of 2022. Production for Q2/2023 reflects the impact of wildfires in northwest Alberta which resulted in temporary shut-ins that reduced production by approximately 4,500 boe/d for Q2/2023.

In the U.S., production was 33,887 boe/d for Q2/2023 and 30,020 boe/d for YTD 2023 compared to 28,170 boe/d for Q2/2022 and

27,828 boe/d for YTD 2022. The increase in production in 2023 relative to 2022 is primarily due to the production contribution from the Merger with Ranger which added approximately 7,500 boe/d to Q2/2023 production and 3,800 boe/d to YTD 2023 production. Production from the acquired Eagle Ford assets is approximately 70% weighted towards high netback light oil and is primarily operated. U.S. results, excluding the Merger with Ranger, for Q2/2023 and YTD 2023 were in line with expectations and reflect reduced development activity on our non-operated Eagle Ford properties.

Total production of 88,269 boe/d for YTD 2023 is consistent with expectations and we expect production of 153,000-157,000 boe/d for the second half of 2023 and 120,500-122,500 boe/d for 2023.

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 prices for crude oil were lower during Q2/2023 and YTD 2023 as central banks continue to raise interest rates to combat inflation combined with expectations for slower economic activity and demand for crude oil. As a result, the WTI benchmark price averaged US$73.78/bbl for Q2/2023 and US$74.96/bbl for YTD 2023 compared to Q2/2022 and YTD 2022 when WTI was higher due to uncertainty around global supply caused by Russia's invasion of Ukraine and averaged US$108.41/bbl and US$101.35/bbl, respectively.

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$75.01/bbl during Q2/2023 and US$76.22/bbl during YTD 2023 which is lower than US$112.41/bbl during Q2/2022 and US$104.56/bbl during YTD 2022. The MEH benchmark trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$1.23/bbl and US$1.26/bbl for Q2/2023 and YTD 2023 compared to premiums of US$4.00/bbl and US$3.21/bbl for Q2/2022 and YTD 2022, respectively. The MEH benchmark traded at a lower premium to WTI in both periods of 2023 as a result of reduced refinery demand on the Gulf Coast relative to the same periods of 2022.

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 levels in Western Canada along with North American refinery demand. Canadian oil differentials were wider in 2023 relative to 2022 due to reduced demand caused by planned and unplanned refinery maintenance along with increased supply following record releases from the U.S. Strategic Petroleum Reserve.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $95.13/bbl during Q2/2023 and $97.09/bbl during YTD 2023 compared to $137.79/bbl during Q2/2022 and $126.72/bbl during YTD 2022. Edmonton par traded at a discount to WTI of US$2.95/bbl for Q2/2023 and US$2.91/bbl for YTD 2023 compared to a discount of US$0.47/bbl for Q2/2022 and US$1.68/bbl for YTD 2022.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q2/2023 and YTD 2023 averaged $78.85/bbl and $74.16/bbl, respectively, compared to $122.05/bbl and $111.48/bbl for the same periods of 2022. The WCS heavy oil differential was US$15.07/bbl in Q2/2023 and US$19.92/bbl in YTD 2023 compared to discounts of US$12.80/bbl for Q2/2022 and US$13.67/bbl for YTD 2022.

Natural Gas

Reduced demand for North American gas resulted in lower prices relative to 2022 which was impacted by geopolitical factors that caused higher global natural gas prices due to uncertainty of supply to Europe.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$2.10/mmbtu for Q2/2023 and US$2.76/mmbtu for YTD 2023 compared to US$7.17/mmbtu for Q2/2022 and US$6.06/mmbtu for YTD 2022.

Baytex Energy Corp.                                            

Q2 2023 MD&A    6

In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $2.35/mcf during Q2/2023 and $3.34/mcf during YTD 2023 which is lower than $6.27/mcf for Q2/2022 and $5.43/mcf for YTD 2022.

The following tables compare select benchmark prices and our average realized selling prices for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30			Six Months Ended June 30
	2023	2022	Change	2023	2022	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	73.78	108.41	(34.63)	74.96	101.35	(26.39)
MEH oil (US$/bbl) (2)	75.01	112.41	(37.40)	76.22	104.56	(28.34)
MEH oil differential to WTI (US$/bbl)	1.23	4.00	(2.77)	1.26	3.21	(1.95)
Edmonton par oil ($/bbl) (3)	95.13	137.79	(42.66)	97.09	126.72	(29.63)
Edmonton par oil differential to WTI (US$/bbl)	(2.95)	(0.47)	(2.48)	(2.91)	(1.68)	(1.23)
WCS heavy oil ($/bbl) (4)	78.85	122.05	(43.20)	74.16	111.48	(37.32)
WCS heavy oil differential to WTI (US$/bbl)	(15.07)	(12.80)	(2.27)	(19.92)	(13.67)	(6.25)
AECO natural gas ($/mcf) (5)	2.35	6.27	(3.92)	3.34	5.43	(2.09)
NYMEX natural gas (US$/mmbtu) (6)	2.10	7.17	(5.07)	2.76	6.06	(3.30)
CAD/USD average exchange rate	1.3431	1.2766	0.0665	1.3475	1.2714	0.0761

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

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

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

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

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

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

	Three Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	93.98	$	97.55	$	96.07	$	135.29	$	141.14	$	138.36
Heavy oil, net of blending and other expense ($/bbl) (2)	66.45		—		66.45		111.18		—		111.18
NGL ($/bbl) (1)	28.92		25.07		25.71		50.09		48.42		48.83
Natural gas ($/mcf) (1)	2.64		2.52		2.58		7.01		8.99		7.74
Total sales, net of blending and other expense ($/boe) (2)	$	66.34	$	67.60	$	66.82	$	104.91	$	106.48	$	105.44
	Six Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	96.74	$	99.96	$	98.47	$	124.05	$	131.77	$	127.95
Heavy oil, net of blending and other expense ($/bbl) (2)	58.69		—		58.69		101.01		—		101.01
NGL ($/bbl) (1)	32.86		28.35		29.29		46.43		45.66		45.85
Natural gas ($/mcf) (1)	3.12		3.23		3.17		5.84		7.52		6.47
Total sales, net of blending and other expense ($/boe) (2)	$	62.91	$	69.60	$	65.18	$	95.55	$	97.90	$	96.34

(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.

Baytex Energy Corp.                                            

Q2 2023 MD&A    7

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $66.82/boe for Q2/2023 and $65.18/bbl for YTD 2023 compared to $105.44/boe for Q2/2022 and $96.34/boe for YTD 2022. In Canada, our realized price of $66.34/boe for Q2/2023 was $38.57/boe lower than $104.91/boe for Q2/2022. Our realized price in the U.S. was $67.60/boe in Q2/2023 which is $38.88/boe lower than $106.48/boe in Q2/2022. Lower North American benchmark oil prices was the primary factor that resulted in lower realized pricing for our operations in Canada and the U.S. in Q2/2023 and YTD 2023 relative to the same periods of 2022.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $93.98/bbl for Q2/2023 and $96.74/bbl for YTD 2023 compared to $135.29/bbl for Q2/2022 and $124.05/bbl for YTD 2022. The decrease in our realized light oil and condensate price for Q2/2023 and YTD 2023 was primarily a result of lower benchmark prices and represents discounts to the Edmonton par price of $1.15/bbl and $0.35/bbl for Q2/2023 and YTD 2023, respectively, which are narrower than discounts of $2.50/bbl in Q2/2022 and $2.67/bbl in YTD 2022 due to strong realized pricing for our Viking light oil production in Saskatchewan.

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 $97.55/bbl for Q2/2023 and $99.96/bbl for YTD 2023 compared to $141.14/bbl for Q2/2022 and $131.77/bbl for YTD 2022. Expressed in U.S. dollars, our realized light oil and condensate price of US$72.63/bbl for Q2/2023 and US$74.18/bbl for YTD 2023 represents discounts to MEH of US$2.38/bbl and US$2.04/bbl for Q2/2023 and YTD 2023, respectively, compared to discounts of US$1.85/bbl for Q2/2022 and US$0.92/bbl for YTD 2022.

Our realized heavy oil price, net of blending and other expense(1) averaged $66.45/bbl in Q2/2023 and $58.69/bbl in YTD 2023 compared to $111.18/bbl in Q2/2022 and $101.01/bbl in YTD 2022. Our realized heavy oil, net of blending and other expense for Q2/2023 and YTD 2023 was $44.73/bbl and $42.32/bbl lower relative to Q2/2022 and YTD 2022, respectively, compared with a $43.20/bbl and $37.32/bbl decrease in the WCS benchmark price over the same periods. Our realized price decreased more than the benchmark price due to higher per unit blending costs relative to the WCS benchmark in both periods of 2023 compared to same periods of 2022.

Our realized NGL price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Our realized NGL price(2) was $25.71/bbl in Q2/2023 or 26% of WTI (expressed in Canadian dollars) and $29.29/bbl in YTD 2023 or 29% of WTI (expressed in Canadian dollars) compared to $48.83/bbl or 35% of WTI (expressed in Canadian dollars) in Q2/2022 and $45.85/bbl or 36% of WTI (expressed in Canadian dollars) in YTD 2022. Our realized NGL price in Canada and the U.S. was lower as a percentage of WTI in Q2/2023 and YTD 2023 due to lower demand for NGL products relative to the same periods of 2022.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. A portion of our natural gas sales in Canada and the U.S. are based on the respective daily index prices which fluctuate independently from the associated monthly index prices. Our realized natural gas price(2) in Canada was $2.64/mcf for Q2/2023 and $3.12/mcf for YTD 2023 compared to $7.01/mcf in Q2/2022 and $5.84/mcf for YTD 2022. In the U.S., our realized natural gas price was US$1.88/mcf for Q2/2023 and US$2.40/mcf for YTD 2023 compared to US$7.04/mcf for Q2/2022 and US$5.91/mcf for YTD 2022. The decrease in our realized gas price in Canada and the U.S. is relatively consistent with the decreases in the AECO monthly and NYMEX monthly benchmark prices in 2023 compared to the same periods of 2022.

(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.                                            

Q2 2023 MD&A    8

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended June 30
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	124,965	$	183,845	$	308,810	$	192,986	$	222,606	$	415,592
Heavy oil	251,449		—		251,449		346,101		—		346,101
NGL	3,772		16,391		20,163		8,288		24,895		33,183
Total oil sales	380,186		200,236		580,422		547,375		247,501		794,876
Natural gas sales	10,106		8,232		18,338		33,822		25,471		59,293
Total petroleum and natural gas sales	390,292		208,468		598,760		581,197		272,972		854,169
Blending and other expense	(52,995)		—		(52,995)		(56,895)		—		(56,895)
Total sales, net of blending and other expense (1)	$	337,297	$	208,468	$	545,765	$	524,302	$	272,972	$	797,274
	Six Months Ended June 30
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	271,420	$	325,855	$	597,275	$	373,141	$	403,426	$	776,567
Heavy oil	468,534		—		468,534		590,539		—		590,539
NGL	9,832		32,165		41,997		15,772		46,902		62,674
Total oil sales	749,786		358,020		1,107,806		979,452		450,328		1,429,780
Natural gas sales	26,128		20,162		46,290		55,449		42,765		98,214
Total petroleum and natural gas sales	775,914		378,182		1,154,096		1,034,901		493,093		1,527,994
Blending and other expense	(112,676)		—		(112,676)		(98,335)		—		(98,335)
Total sales, net of blending and other expense (1)	$	663,238	$	378,182	$	1,041,420	$	936,566	$	493,093	$	1,429,659

(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 $545.8 million for Q2/2023 decreased $251.5 million from $797.3 million reported for Q2/2022 while total sales, net of blending and other expense, of $1.0 billion for YTD 2023 decreased $388.2 million from $1.4 billion reported for YTD 2022. The decrease in total sales in both periods of 2023 relative to the same periods of 2022 reflects lower benchmark prices which more than offset the increase in production from our successful development programs along with the contribution of the Ranger assets.

In Canada, total sales, net of blending and other expense, was $337.3 million for Q2/2023 which is a decrease of $187.0 million from $524.3 million reported for Q2/2022. The decrease in total petroleum and natural gas sales was the result of lower realized pricing for Q2/2023 relative to Q2/2022 which resulted in a $196.1 million decrease in total sales, net of blending and other expense while higher production resulted in a $9.1 million increase in total sales, net of blending and other expense, relative to Q2/2022. Lower benchmark prices was the primary factor contributing to our total sales, net of blending and other expense, decreasing to $663.2 million in YTD 2023 from $936.6 million in YTD 2022.

In the U.S., petroleum and natural gas sales were $208.5 million for Q2/2023 which is a decrease of $64.5 million from $273.0 million reported for Q2/2022. Higher production in Q2/2023 relative to Q2/2022 contributed to a $55.4 million increase in total sales which was more than offset by lower realized pricing which resulted in a $119.9 million decrease in total sales for Q2/2023 relative to Q2/2022. The decrease in realized pricing in YTD 2023 resulted in petroleum and natural gas sales of $378.2 million for YTD 2023 compared to $493.1 million in YTD 2022 despite higher production in YTD 2023 relative to YTD 2022.

Baytex Energy Corp.                                            

Q2 2023 MD&A    9

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	47,309		$	60,611		$	107,920		$	91,133		$	80,426		$	171,559
Average royalty rate (1)(2)	14.0		%	29.1		%	19.8		%	17.4		%	29.5		%	21.5		%
Royalties per boe (3)	$	9.30		$	19.66		$	13.21		$	18.24		$	31.37		$	22.69
	Six Months Ended June 30
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	91,164		$	110,009		$	201,173		$	148,809		$	145,470		$	294,279
Average royalty rate (1)(2)	13.7		%	29.1		%	19.3		%	15.9		%	29.5		%	20.6		%
Royalties per boe (3)	$	8.65		$	20.25		$	12.59		$	15.18		$	28.88		$	19.83

(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 Q2/2023 were $107.9 million or 19.8% of total sales, net of blending and other expense, compared to $171.6 million or 21.5% for Q2/2022. Total royalties for YTD 2023 were $201.2 million or 19.3% of total sales, net of blending and other expense, compared to $294.3 million or 20.6% for YTD 2022. The decrease in total royalties in both periods of 2023 is primarily a result of lower benchmark prices along with a lower royalty rate on our Canadian production relative to the same periods of 2022. Our royalty rates of 19.8% for Q2/2023 and 19.3% for YTD 2023 were lower than 21.5% for Q2/2022 and 20.6% for YTD 2022.

Our Canadian royalty rates of 14.0% for Q2/2023 and 13.7% for YTD 2023 were lower than 17.4% for Q2/2022 and 15.9% for YTD 2022 due to lower benchmark commodity prices which resulted in a lower royalty rate on our Canadian properties in 2023 relative to 2022. In the U.S., royalties averaged 29.1% of total sales for Q2/2023 and YTD 2023 respectively, which is slightly lower than 29.5% for Q2/2022 and YTD 2022 due to the production contributed by the acquired Ranger assets which has a lower royalty rate relative to our legacy non-operated Eagle Ford assets.

Our average royalty rate of 19.3% for YTD 2023 is consistent with expectations and we have updated our annual guidance to 21.0 - 22.0% for 2023 which reflects the royalty rate on the properties acquired from Ranger which has a higher royalty rate than our corporate average.

OPERATING EXPENSE

	Three Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	91,354	$	28,084	$	119,438	$	82,471	$	24,955	$	107,426
Operating expense per boe (1)	$	17.97	$	9.11	$	14.62	$	16.50	$	9.73	$	14.21
	Six Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	182,534	$	49,312	$	231,846	$	161,011	$	47,181	$	208,192
Operating expense per boe (1)	$	17.31	$	9.08	$	14.51	$	16.43	$	9.37	$	14.03

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

Baytex Energy Corp.                                            

Q2 2023 MD&A    10

Total operating expense was $119.4 million ($14.62/boe) for Q2/2023 and $231.8 million ($14.51/boe) for YTD 2023 compared to $107.4 million ($14.21/boe) for Q2/2022 and $208.2 million ($14.03/boe) for YTD 2022. Operating expense for both periods of 2023 increased in total and per boe reflecting increased production and cost inflation throughout our operations in 2023 relative to 2022.

In Canada, operating expense was $91.4 million ($17.97/boe) for Q2/2023 and $182.5 million ($17.31/boe) for YTD 2023 compared to $82.5 million ($16.50/boe) for Q2/2022 and $161.0 million ($16.43/boe) for YTD 2022. Total operating expenses were higher in Canada as a result of higher production along with slightly higher per boe costs due to inflation.

U.S. operating expense was $28.1 million ($9.11/boe) for Q2/2023 and $49.3 million ($9.08/boe) for YTD 2023 compared to $25.0 million ($9.73/boe) for Q2/2022 and $47.2 million ($9.37/boe) in YTD 2022. Our U.S. operating expenses expressed in U.S. dollars, per unit operating expense was US$6.78/boe in Q2/2023 and US$6.74/boe in YTD 2023 which was lower than US$7.62/boe for Q2/2022 and US$7.37/boe in YTD 2022 as a result of lower workover activity in 2023.

Operating expense of $14.51 for YTD 2023 is consistent with expectations and we have updated our annual guidance range to $12.25 - $12.75/boe for 2023 which reflects the lower operating cost structure of the Ranger assets.

TRANSPORTATION EXPENSE

Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates. Transportation expense in our U.S. operations is primarily the costs incurred to deliver our production via truck or pipeline to a centralized sales point.

The following table compares our transportation expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	13,240	$	1,334	$	14,574	$	11,758	$	—	$	11,758
Transportation expense per boe (1)	$	2.60	$	0.43	$	1.78	$	2.35	$	—	$	1.56
	Six Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	30,245	$	1,334	$	31,579	$	20,973	$	—	$	20,973
Transportation expense per boe (1)	$	2.87	$	0.25	$	1.98	$	2.14	$	—	$	1.41

(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 $14.6 million ($1.78/boe) for Q2/2023 and $31.6 million ($1.98/boe) for YTD 2023 compared to $11.8 million ($1.56/boe) for Q2/2022 and $21.0 million ($1.41/boe) for YTD 2022. In Canada, total transportation expense and per unit costs are higher in Q2/2023 and YTD 2023 as a result of additional heavy oil production along with higher trucking rates relative to the same periods of 2022. Transportation expense in the U.S. is consistent with expectations for Q2/2023 and YTD 2023 and reflects trucking and pipeline transportation costs on our Eagle Ford operations acquired from Ranger. Per unit transportation expense of $1.98/boe for YTD 2023 is consistent with expectations and we have updated our annual guidance range to $2.00 - $2.10/boe to reflect the incremental transportation costs associated with the properties acquired from Ranger.

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 $53.0 million for Q2/2023 and $112.7 million for YTD 2023 compared to $56.9 million for Q2/2022 and $98.3 million for YTD 2022. The increase in blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in YTD 2023 relative to YTD 2022, while Q2/2023 was consistent with Q2/2022 due to curtailed heavy oil production from the wildfires in Alberta.

Baytex Energy Corp.                                            

Q2 2023 MD&A    11

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 revenue. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023		2022		Change		2023		2022		Change
Realized financial derivatives gain (loss)
Crude oil	$	16,363	$	(112,071)	$	128,434	$	21,778	$	(191,597)	$	213,375
Natural gas	2		(11,971)		11,973		2		(16,811)		16,813
Total	$	16,365	$	(124,042)	$	140,407	$	21,780	$	(208,408)	$	230,188
Unrealized financial derivatives gain (loss)
Crude oil	$	(17,124)	$	47,816	$	(64,940)	$	(7,914)	$	(91,502)	$	83,588
Natural gas	(2,279)		9,363		(11,642)		(2,279)		(7,271)		4,992
Equity total return swap ("Equity TRS")	—		1,589		(1,589)		—		1,280		(1,280)
Total	$	(19,403)	$	58,768	$	(78,171)	$	(10,193)	$	(97,493)	$	87,300
Total financial derivatives gain (loss)
Crude oil	$	(761)	$	(64,255)	$	63,494	$	13,864	$	(283,099)	$	296,963
Natural gas	(2,277)		(2,608)		331		(2,277)		(24,082)		21,805
Equity TRS	—		1,589		(1,589)		—		1,280		(1,280)
Total	$	(3,038)	$	(65,274)	$	62,236	$	11,587	$	(305,901)	$	317,488

We recorded a total financial derivative loss of $3.0 million for Q2/2023 and a gain of $11.6 million for YTD 2023 compared to a loss of $65.3 million for Q2/2022 and $305.9 million for YTD 2022. The realized financial derivatives gain of $16.4 million for Q2/2023 and $21.8 million for YTD 2023 were primarily a result of the market prices for crude oil and natural gas settling at levels below those set in our derivative contracts. The unrealized loss of $19.4 million for Q2/2023 and $10.2 million for YTD 2023 reflect changes in forecasted crude oil pricing used to revalue the unsettled notional volume outstanding on our crude oil contracts in place at June 30, 2023 relative to March 31, 2023 and December 31, 2022.The fair value of our financial derivative contracts resulted in a net asset of $24.6 million at June 30, 2023 compared to a net asset of $19.3 million at March 31, 2023 and a net liability of $10.1 million at December 31, 2022.

Baytex Energy Corp.                                            

Q2 2023 MD&A    12

We had the following commodity financial derivative contracts as at July 27, 2023.

	Period	Volume	Price/Unit (1)	Index
Oil
Basis differential (2)	July 2023 to Dec 2023	1,500 bbl/d	WTI less US$2.50/bbl	MSW
Basis differential (2)(3)	Jan 2024 to Dec 2024	1,500 bbl/d	WTI less US$2.65/bbl	MSW
Basis differential (2)	July 2023 to Dec 2023	2,000 bbl/d	WTI less US$14.98/bbl	WCS
Basis differential (2)	Aug 2023 to Dec 2023	6,000 bbl/d	WTI less US$13.62/bbl	WCS
Basis differential (2)	July 2023 to Dec 2023	5,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.10/bbl	WCS
Basis differential (2)	Jan 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
Put option	July 2023 to Dec 2023	5,000 bbl/d	US$60.00	WTI
Collar	July 2023 to Dec 2023	15,500 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2023 to Sep 2023	19,862 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2023 to Dec 2023	15,089 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Mar 2024	8,400 bbl/d	US$60.00/US$100.00	WTI
Collar	Apr 2024 to Jun 2024	1,750 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Jun 2024	14,500 bbl/d	US$60.00/US$100.00	WTI
Collar (3)	Jan 2024 to Jun 2024	2,500 bbl/d	US$60.00/US$90.00	WTI
Natural Gas
Basis differential (2)	July 2023 to Dec 2023	11,413 mmbtu/d	Baytex pays: NYMEX Baytex receives: HSC less US$0.1525/mmbtu	HSC IFERC FOM
Fixed Sell	Oct 2023 to Mar 2024	3,500 mmbtu/d	US$3.5025/mmbtu	NYMEX
Collar	July 2023 to Dec 2023	11,413 mmbtu/d	US$2.50/US$2.68	NYMEX
Collar	Jan 2024 to Mar 2024	11,538 mmbtu/d	US$2.50/US$3.65	NYMEX
Collar	Apr 2024 to Jun 2024	11,538 mmbtu/d	US$2.33/US$3.00	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.06	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.09	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.10	NYMEX
Collar	Jan 2024 to Dec 2024	8,500 mmbtu/d	US$3.00/US$4.15	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.19	NYMEX
Natural Gas Liquids
Fixed Sell	Jul 2023 to Mar 2024	34,364 gallon/d	US$0.2280/gallon	Mt. Belvieu Non-TET Ethane

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

(2)Contracts that fix the basis differential between certain oil reference prices.

(3)Contract entered subsequent to June 30, 2023.

Baytex Energy Corp.                                            

Q2 2023 MD&A    13

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023						2022
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	55,874		33,887		89,761		54,919		28,170		83,090
Operating netback:
Total sales, net of blending and other expense (1)	$	66.34	$	67.60	$	66.82	$	104.91	$	106.48	$	105.44
Less:
Royalties (2)	(9.30)		(19.66)		(13.21)		(18.24)		(31.37)		(22.69)
Operating expense (2)	(17.97)		(9.11)		(14.62)		(16.50)		(9.73)		(14.21)
Transportation expense (2)	(2.60)		(0.43)		(1.78)		(2.35)		—		(1.56)
Operating netback (1)	$	36.47	$	38.40	$	37.21	$	67.82	$	65.38	$	66.98
Realized financial derivatives gain (loss) (3)	—		—		2.00		—		—		(16.41)
Operating netback after financial derivatives (1)	$	36.47	$	38.40	$	39.21	$	67.82	$	65.38	$	50.57
	Six Months Ended June 30
	2023						2022
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	58,249		30,020		88,269		54,156		27,828		81,985
Operating netback:
Total sales, net of blending and other expense (1)	$	62.91	$	69.60	$	65.18	$	95.55	$	97.90	$	96.34
Less:
Royalties (2)	(8.65)		(20.25)		(12.59)		(15.18)		(28.88)		(19.83)
Operating expense (2)	(17.31)		(9.08)		(14.51)		(16.43)		(9.37)		(14.03)
Transportation expense (2)	(2.87)		(0.25)		(1.98)		(2.14)		—		(1.41)
Operating netback (1)	$	34.08	$	40.02	$	36.10	$	61.80	$	59.65	$	61.07
Realized financial derivatives gain (loss) (3)	—		—		1.36		—		—		(14.04)
Operating netback after financial derivatives (1)	$	34.08	$	40.02	$	37.46	$	61.80	$	59.65	$	47.03

(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.

Our operating netback was $37.21/boe for Q2/2023 and $36.10/boe for YTD 2023 compared to $66.98/boe for Q2/2022 and $61.07/boe for YTD 2022 due to lower benchmark pricing in Canada and the U.S. which resulted in a decrease in per unit sales net of royalties. Total operating and transportation expense of $16.40/boe for Q2/2023 and $16.49/boe for YTD 2023 were higher than $15.77/boe for Q2/2022 and $15.44/boe for YTD 2022 due to inflation which resulted in higher per boe operating and transportation costs. Operating netback including realized gains (losses) on financial derivatives was $39.21/boe for Q2/2023 and $37.46/boe for YTD 2023 compared to $50.57/boe for Q2/2022 and $47.03/boe for YTD 2022.

GENERAL AND ADMINISTRATIVE EXPENSE

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

Baytex Energy Corp.                                            

Q2 2023 MD&A    14

The following table summarizes our G&A expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2023		2022		Change		2023		2022		Change
Gross general and administrative expense	$	16,476	$	12,223	$	4,253	$	30,893	$	25,729	$	5,164
Overhead recoveries	(1,236)		(583)		(653)		(3,919)		(2,407)		(1,512)
General and administrative expense	$	15,240	$	11,640	$	3,600	$	26,974	$	23,322	$	3,652
General and administrative expense per boe (1)	$	1.87	$	1.54	$	0.33	$	1.69	$	1.57	$	0.12

(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 $15.2 million ($1.87/boe) for Q2/2023 and $27.0 million ($1.69/boe) for YTD 2023 compared to $11.6 million ($1.54/boe) for Q2/2022 and $23.3 million ($1.57/boe) for YTD 2022. G&A expense for Q2/2023 and YTD 2023 is consistent with expectations and was higher than the comparative periods of 2022 due to the increase in staffing levels and integration costs associated with the Merger with Ranger. G&A expense of $1.69/boe during YTD 2023 is consistent with expectations and our annual guidance of $80 million ($1.80/boe) reflects the additional staffing levels and administrative costs associated with the Merger with Ranger.

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 accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.

The following table summarizes our financing and interest expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2023		2022		Change		2023		2022		Change
Interest on credit facilities	$	7,535	$	4,070	$	3,465	$	13,751	$	7,109	$	6,642
Interest on long-term notes	20,565		16,356		4,209		32,659		33,700		(1,041)
Interest on lease obligations	155		48		107		$	220	$	92	128
Cash interest	$	28,255	$	20,474	$	7,781	$	46,630	$	40,901	$	5,729
Accretion of debt issue costs	1,847		2,734		(887)		2,371		3,429		(1,058)
Accretion of asset retirement obligations	4,395		3,869		526		9,221		6,991		2,230
Financing and interest expense	$	34,497	$	27,077	$	7,420	$	58,222	$	51,321	$	6,901
Cash interest per boe (1)	$	3.46	$	2.71	$	0.75	$	2.92	$	2.76	$	0.16
Financing and interest expense per boe (1)	$	4.22	$	3.58	$	0.64	$	3.64	$	3.46	$	0.18

(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 $34.5 million ($4.22/boe) for Q2/2023 and $58.2 million ($3.64/boe) for YTD 2023 compared to $27.1 million ($3.58/boe) for Q2/2022 and $51.3 million ($3.46/boe) for YTD 2022. Higher interest costs in 2023 relative to 2022 reflects the additional debt outstanding as a result of the Merger with Ranger in addition to an increase in interest rates.

Cash interest was $28.3 million ($3.46/boe) for Q2/2023 and $46.6 million ($2.92/boe) for YTD 2023 compared to $20.5 million ($2.71/boe) for Q2/2022 and $40.9 million ($2.76/boe) for YTD 2022. Cash interest was higher in both periods of 2023 relative to the same periods of 2022 which reflects the additional debt outstanding due to the Merger with Ranger including the issuance of US$800.0 million aggregate principal amount of long-term notes. Interest on our credit facilities in Q2/2023 and YTD 2023 was higher than the same periods of 2022 primarily due to the increase in benchmark borrowing rate along with an increase in the principal amounts outstanding. The weighted average interest rate applicable to our credit facilities was 6.8% for Q2/2023 and 6.5% for YTD 2023 which is higher than 2.6% for both Q2/2022 and YTD 2022.

Accretion of asset retirement obligations of $4.4 million for Q2/2023 and $9.2 million for YTD 2023 was higher than $3.9 million for Q2/2022 and $7.0 million for YTD 2022 due to a higher discount rate used in both periods of 2023. Accretion of debt issue costs was lower in both periods of 2023 relative to the comparative periods of 2022 due to lower debt issue costs outstanding for the majority of YTD 2023.

We have updated our cash interest annual guidance for 2023 to $150 million ($3.38/boe) which reflects the incremental debt associated with the Merger with Ranger in addition to higher interest rates on our credit facilities.

Baytex Energy Corp.                                            

Q2 2023 MD&A    15

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $0.4 million for Q2/2023 and $0.5 million for YTD 2023 compared to $7.2 million for Q2/2022 and $10.8 million for YTD 2022.

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2023		2022		Change		2023		2022		Change
Depletion	$	174,473	$	140,809	$	33,664	$	338,908	$	280,255	$	58,653
Depreciation	1,671		1,477		194		3,235		2,822		413
Depletion and depreciation	$	176,144	$	142,286	$	33,858	$	342,143	$	283,077	$	59,066
Depletion and depreciation per boe (1)	$	21.56	$	18.82	$	2.74	$	21.42	$	19.08	$	2.34

(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 $176.1 million ($21.56/boe) for Q2/2023 and $342.1 million ($21.42/boe) for YTD 2023 compared to $142.3 million ($18.82/boe) for Q2/2022 and $283.1 million ($19.08/boe) for YTD 2022. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q2/2023 and YTD 2023 relative to Q2/2022 and YTD 2022 as a result of the $245.2 million impairment reversal that was recorded at December 31, 2022 and an increase in future development costs attributed to proved plus probable reserves which resulted in a higher depletable base for our oil and gas properties in 2023. Depletion expense for Q2/2023 and YTD 2023 also includes depletion on the oil and gas properties acquired from Ranger subsequent to closing on June 20, 2023.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at June 30, 2023.

2022 Impairment Reversal

At December 31, 2022, we identified indicators of impairment reversal for oil and gas properties in five of our six CGUs due to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves, which resulted in an impairment reversal of $245.2 million. At December 31, 2022, we identified indicators of impairment reversal for E&E assets in the Peace River CGU due to an increase in land sale values and recorded an impairment reversal of $22.5 million. The total impairment reversal recorded at December 31, 2022 was $267.7 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 along with the share based compensation plan assumed from Ranger in June 2023. 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 financial liability included in trade and other payables, and includes gains or losses on equity total return swaps. The liability is re-measured at each reporting date and results in either a SBC expense or recovery based on changes in our share price.

We recorded SBC expense of $16.9 million for Q2/2023 and $26.7 million for YTD 2023 compared to $2.9 million for Q2/2022 and $6.9 million for YTD 2022. SBC expense for Q2/2023 and YTD 2023 includes $16.2 million of non-cash expense related to awards assumed and settled in Baytex common shares in conjunction with the Merger with Ranger. Regular expensing of compensation awards is considered a cash expense as we intend to settle currently outstanding and future awards in cash while Baytex is repurchasing shares as part of its shareholder return program.

Baytex Energy Corp.                                            

Q2 2023 MD&A    16

Cash SBC expense of $0.7 million for Q2/2023 reflects a decline in our share price at June 30, 2023 compared to March 31, 2023 which resulted in lower cash SBC expense compared to $2.6 million for Q2/2022 when we had a higher notional amount outstanding under the equity total return swaps. In Q1/2023 we reduced the notional amount of the equity total return swaps to match the number of awards outstanding under the Deferred Share Unit Plan where we previously had targeted an amount equivalent to approximately 90-100% of all cash settled awards outstanding. Cash SBC expense of $10.5 million for YTD 2023 was higher than $4.8 million for YTD 2022 as we applied a 1.5x performance factor for 2022 results to performance awards during 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 June 30						Six Months Ended June 30
($ thousands except for exchange rates)	2023		2022		Change		2023		2022		Change
Unrealized foreign exchange (gain) loss	$	(12,880)	$	27,499	$	(40,379)	$	(13,093)	$	12,951	$	(26,044)
Realized foreign exchange loss	941		210		731		1,091		413		678
Foreign exchange (gain) loss	$	(11,939)	$	27,709	$	(39,648)	$	(12,002)	$	13,364	$	(25,366)
CAD/USD exchange rates:
At beginning of period	1.3528		1.2484				1.3534		1.2656
At end of period	1.3238		1.2872				1.3238		1.2872

We recorded a foreign exchange gain of $11.9 million for Q2/2023 and $12.0 million for YTD 2023 compared to a loss of $27.7 million for Q2/2022 and $13.4 million for YTD 2022.

The unrealized foreign exchange gain of $12.9 million for Q2/2023 and $13.1 million for YTD 2023 is related to changes in the reported amount of our long-term notes and credit facilities due to a strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and December 31, 2022. A weakening of the Canadian dollar relative to the U.S. dollar resulted in an unrealized foreign exchange loss for Q2/2022 and YTD 2022 related to changes in the reported amount of our long-term notes outstanding at June 30, 2022 compared to March 31, 2022 and December 31, 2021.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $0.9 million for Q2/2023 and $1.1 million for YTD 2023 compared to a loss of $0.2 million for Q2/2022 and $0.4 million for YTD 2022.

INCOME TAXES

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023		2022		Change		2023		2022		Change
Current income tax expense	$	1,350	$	1,140	$	210	$	2,470	$	2,050	$	420
Deferred income tax (recovery) expense	(178,360)		39,920		(218,280)		(162,837)		(27,412)		(135,425)
Total income tax (recovery) expense	$	(177,010)	$	41,060	$	(218,070)	$	(160,367)	$	(25,362)	$	(135,005)

Current income tax expense was $1.4 million for Q2/2023 and $2.5 million for YTD 2023 compared to $1.1 million for Q2/2022 and $2.1 million for YTD 2022.

We recorded deferred tax recovery of $178.4 million for Q2/2023 and $162.8 million for YTD 2023 compared to expense of $39.9 million for Q2/2022 and a recovery $27.4 million for YTD 2022. The deferred tax recovery in Q2/2023 and YTD 2023 is primarily related to the effects of the transaction restructuring for the Ranger acquisition in Q2/2023 partially offset by income generated on our Canadian and U.S. operations for the period.

As disclosed in the 2022 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) in June 2016 that deny $591.0 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, we filed notices of objection with the CRA appealing each reassessment received. In mid-July 2023 we received a letter from the Appeals Division of the CRA proposing to confirm the reassessments. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals process.

Baytex Energy Corp.                                            

Q2 2023 MD&A    17

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three and six months ended June 30, 2023 and 2022 are set forth in the following table.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023		2022		Change		2023		2022		Change
Petroleum and natural gas sales	$	598,760	$	854,169	$	(255,409)	$	1,154,096	$	1,527,994	$	(373,898)
Royalties	(107,920)		(171,559)		63,639		(201,173)		(294,279)		93,106
Revenue, net of royalties	490,840		682,610		(191,770)		952,923		1,233,715		(280,792)
Expenses
Operating	(119,438)		(107,426)		(12,012)		(231,846)		(208,192)		(23,654)
Transportation	(14,574)		(11,758)		(2,816)		(31,579)		(20,973)		(10,606)
Blending and other	(52,995)		(56,895)		3,900		(112,676)		(98,335)		(14,341)
Operating netback (1)	$	303,833	$	506,531	$	(202,698)	$	576,822	$	906,215	$	(329,393)
General and administrative	(15,240)		(11,640)		(3,600)		(26,974)		(23,322)		(3,652)
Cash interest	(28,255)		(20,474)		(7,781)		(46,630)		(40,901)		(5,729)
Realized financial derivatives loss (gain)	16,365		(124,042)		140,407		21,780		(208,408)		230,188
Realized foreign exchange loss	(941)		(210)		(731)		(1,091)		(413)		(678)
Other expense	(141)		(751)		610		(354)		(1,001)		647
Current income tax expense	(1,350)		(1,140)		(210)		(2,470)		(2,050)		(420)
Cash share-based compensation	(681)		(2,570)		1,889		(10,504)		(4,809)		(5,695)
Adjusted funds flow (2)	$	273,590	$	345,704	$	(72,114)	$	510,579	$	625,311	$	(114,732)
Transaction costs	(32,832)		—		(32,832)		(41,703)		—		(41,703)
Exploration and evaluation	(369)		(7,210)		6,841		(532)		(10,780)		10,248
Depletion and depreciation	(176,144)		(142,286)		(33,858)		(342,143)		(283,077)		(59,066)
Non-cash share-based compensation	(16,237)		(372)		(15,865)		(16,237)		(2,078)		(14,159)
Non-cash financing and accretion	(6,242)		(6,603)		361		(11,592)		(10,420)		(1,172)
Non-cash other income	—		183		(183)		1,271		1,465		(194)
Unrealized financial derivatives (loss) gain	(19,403)		58,768		(78,171)		(10,193)		(97,493)		87,300
Unrealized foreign exchange gain (loss)	12,880		(27,499)		40,379		13,093		(12,951)		26,044
Gain (loss) on dispositions	—		207		(207)		(336)		441		(777)
Deferred income tax recovery (expense)	178,360		(39,920)		218,280		162,837		27,412		135,425
Net income for the period	$	213,603	$	180,972	$	32,631	$	265,044	$	237,830	$	27,214

(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 $273.6 million for Q2/2023 and $510.6 million for YTD 2023 compared to $345.7 million for Q2/2022 and $625.3 million for YTD 2022. The decrease in adjusted funds flow was primarily due to lower operating netback which was $202.7 million lower in Q2/2023 and $329.4 million lower in YTD 2023 relative to the same periods of 2022 as a result of lower commodity prices that resulted in decreased revenue, net of royalties. The decrease in operating netback was partially offset by realized gains on financial derivatives of $16.4 million for Q2/2023 and $21.8 million for YTD 2023 which increased $140.4 million and $230.2 million relative to Q2/2022 and YTD 2022, respectively, when we recorded realized losses. We reported net income of $213.6 million for Q2/2023 and $265.0 million for YTD 2023 compared to net income of $181.0 million reported for Q2/2022 and $237.8 million for YTD 2022.

Baytex Energy Corp.                                            

Q2 2023 MD&A    18

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation loss of $46.5 million for Q2/2023 and $47.0 million for YTD 2023 relates to the change in value of our U.S. net assets and is due to the strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and December 31, 2022. The CAD/USD exchange rate was 1.3238 CAD/USD as at June 30, 2023 compared to 1.3528 CAD/USD at March 31, 2023 and 1.3534 CAD/USD at December 31, 2022.

CAPITAL EXPENDITURES

Capital expenditures for the three and six months ended June 30, 2023 and 2022 are summarized as follows.

	Three Months Ended June 30
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	77,518	$	69,309	$	146,827	$	37,265	$	43,167	$	80,432
Facilities	11,324		857		12,181		6,912		1,414		8,326
Land, seismic and other	7,561		4,135		11,696		7,704		171		7,875
Exploration and development expenditures	$	96,403	$	74,301	$	170,704	$	51,881	$	44,752	$	96,633
Property acquisitions	$	(62)	$	—	$	(62)	$	208	$	—	$	208
Proceeds from dispositions	$	(50)	$	—	$	(50)	$	(14)			$	(14)
	Six Months Ended June 30
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	232,471	$	118,145	$	350,616	$	144,263	$	70,305	$	214,568
Facilities	28,309		857		29,166		14,678		1,800		16,478
Land, seismic and other	20,229		4,319		24,548		19,070		339		19,409
Exploration and development expenditures	$	281,009	$	123,321	$	404,330	$	178,011	$	72,444	$	250,455
Property acquisitions	$	444	$	—	$	444	$	267	$	—	$	267
Proceeds from dispositions	$	(285)	$	—	$	(285)	$	(41)	$	—	$	(41)

Exploration and development expenditures were $170.7 million for Q2/2023 and $404.3 million for YTD 2023 compared to $96.6 million for Q2/2022 and $250.5 million for YTD 2022. Exploration and development expenditures for Q2/2023 and YTD 2023 reflect increased development activity along with inflationary pressures that resulted in higher costs related to the same periods of 2022 and expenditures for development activity that occurred on the properties acquired from Ranger after the acquisition closed on June 20, 2023.

In Canada, exploration and development expenditures were $96.4 million in Q2/2023 and $281.0 million in YTD 2023 compared to $51.9 million in Q2/2022 and $178.0 million in YTD 2022. Drilling and completion spending of $77.5 million in Q2/2023 and $232.5 million in YTD 2023 reflects higher light and heavy oil development activity relative to Q2/2022 and YTD 2022 when we spent $37.3 million and $144.3 million, respectively. We also invested $28.3 million on facilities and $20.2 million on land, seismic and other expenditures during YTD 2023.

Total U.S. exploration and development expenditures were $74.3 million for Q2/2023 and $123.3 million for YTD 2023 compared to $44.8 million in Q2/2022 and $72.4 million during YTD 2022. Exploration and development activity for Q2/2023 and YTD 2023 includes $34.1 million of expenditures for development activity that occurred on the properties acquired from Ranger after the acquisition closed on June 20, 2023 to June 30, 2023. Excluding the Ranger acquisition, exploration and development expenditures in the U.S. were consistent for Q2/2023 and YTD 2023 and reflects slightly higher costs due to inflation along with a weaker Canadian dollar relative to the same periods of 2022.

Our exploration and development expenditures for YTD 2023 are consistent with expectations and we now expect full year expenditures of $1,005-$1,045 million for 2023 which reflects expenditures on our operated Eagle Ford properties acquired from Ranger.

Baytex Energy Corp.                                            

Q2 2023 MD&A    19

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management is to maintain a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At June 30, 2023, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables, 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.

The capital intensive nature of our operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties.

Management of debt levels is a priority for us in order to sustain operations and support our long-term plans. At June 30, 2023, net debt(1) was $2.8 billion compared to $987.4 million at December 31, 2022. The increase in net debt is primarily due to $732.8 million of cash consideration paid and the assumption of $1.1 billion of net debt assumed in conjunction with the Merger with Ranger. The cash portion of the transaction was funded with Baytex’s expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. Baytex closed the US$800 million principal amount senior unsecured note offering on April 27, 2023 with the proceeds released from escrow at completion of the Merger.

In June 2023, we renewed our normal course issuer bid ("NCIB") and began repurchasing our common shares in July 2023 as part of our shareholder return framework. Subsequent to Q2/2023 and through to July 26, 2023, we have spent $21.4 million to repurchase and cancel 4.7 million common shares. On July 27, 2023, the Board of Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023. 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.”

Credit Facilities

At June 30, 2023, the principal amount of borrowings outstanding under our credit facilities was $986.9 million. Our credit facilities include US$1.1 billion of revolving credit facilities (the "Revolving Facilities") and a US$150 million non-revolving term loan (the "Term Loan") (collectively, the "Credit Facilities").

On June 20, 2023, we amended our Credit Facilities to facilitate the cash consideration paid in conjunction with the Merger and to assume Ranger's net debt. The Revolving Facilities were increased to US$1.1 billion and mature on April 1, 2026. The Revolving 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. The Term Loan is secured and matures on June 20, 2025. The amended Credit Facilities contain an additional financial covenant of a maximum Total Debt to Bank EBITDA ratio of 4.0:1.0 and increased the Interest Coverage minimum ratio to 3.5:1.0 (from 2.0:1.0).

The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. 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 Revolving 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. Advances under the Term Loan can be drawn in U.S. funds and bear interest at the bank’s secured overnight financing rates ("SOFR") plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.8% for Q2/2023 and 6.5% for YTD 2023 compared to 2.8% and 2.6% for Q2/2022 and YTD 2022, respectively. The interest rate on our Credit Facilities has increased with higher government benchmark rates in 2023 relative to 2022.

As at June 30, 2023, Baytex had $16.8 million of outstanding letters of credit, $15.5 million of which is under a $20 million uncommitted unsecured demand revolving letter of credit facility (December 31, 2022 - $15.7 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.sedar.com.

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

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and our compliance therewith at June 30, 2023.

Covenant Description	Position as at June 30, 2023	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.5:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	13.3:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.2:1.0	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 agreement. At June 30, 2023 our Senior Secured Debt was $986.9 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended June 30, 2023 was $2.1 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 expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the twelve months ended June 30, 2023 were $155.8 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 and other payables, asset retirement obligations, leases, deferred income tax liabilities, and financial derivative liabilities. At June 30, 2023 our Total Debt was $2.6 billion.

Long-Term Notes

We have two issuances of long-term notes outstanding with a total principal amount of $1.6 billion at June 30, 2023. 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 and will be redeemable at par from April 1, 2026 to maturity. At June 30, 2023 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 were issued at 98.709% of par and 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. Net proceeds of $1.0 billion reflects $13.7 million for the original issue discount and Baytex also incurred transaction costs of $18.5 million in conjunction with the issuance.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the six months ended June 30, 2023, we issued 5.9 million common shares pursuant to our share-based compensation programs and issued 311.4 million common shares on closing of the Merger with Ranger. As at June 30, 2023, we had 862.2 million common shares issued and outstanding and no preferred shares issued and outstanding.

Subsequent to June 30, 2023 and through to July 26, 2023, we repurchased 4.7 million common shares under our NCIB at an average price of $4.59 per share.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of June 30, 2023 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
Trade and other payables	$	616,608	$	614,763	$	1,845	$	—	$	—
Financial derivatives	2,907		2,907		—		—		—
Credit facilities – principal (1)	986,903		—		986,903		—		—
Long-term notes – principal (1)	1,601,468		—		—		542,467		1,059,001
Interest on long-term notes (2)	793,845		137,481		274,962		215,922		165,480
Lease obligations – principal	42,191		20,297		8,722		7,095		6,077
Processing agreements	5,812		810		1,022		640		3,340
Transportation agreements	256,920		60,462		108,994		66,937		20,527
Total	$	4,306,654	$	836,720	$	1,382,448	$	833,061	$	1,254,425

(1)Principal amount of instruments.

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

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

Baytex Energy Corp.                                            

Q2 2023 MD&A    20

QUARTERLY FINANCIAL INFORMATION

	2023		2022				2021
($ thousands, except per common share amounts)	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Petroleum and natural gas sales	598,760	555,336	648,986	712,065	854,169	673,825	552,403	488,736
Net income (loss)	213,603	51,441	352,807	264,968	180,972	56,858	563,239	32,713
Per common share – basic	0.37	0.09	0.65	0.48	0.32	0.10	1.00	0.06
Per common share – diluted	0.36	0.09	0.64	0.47	0.32	0.10	0.98	0.06
Adjusted funds flow (1)	273,590	236,989	255,552	284,288	345,704	279,607	214,766	198,397
Per common share – basic	0.47	0.43	0.47	0.51	0.61	0.49	0.38	0.35
Per common share – diluted	0.47	0.43	0.46	0.51	0.60	0.49	0.37	0.35
Free cash flow (2)	96,313	(1,918)	143,324	111,568	245,316	121,318	137,133	101,215
Per common share – basic	0.17	—	0.26	0.20	0.43	0.21	0.24	0.18
Per common share – diluted	0.16	—	0.26	0.20	0.43	0.21	0.24	0.18
Cash flows from operating activities	192,308	184,938	303,441	310,423	360,034	198,974	240,567	178,961
Per common share – basic	0.33	0.34	0.56	0.56	0.63	0.35	0.43	0.32
Per common share – diluted	0.33	0.34	0.55	0.56	0.63	0.35	0.42	0.31
Exploration and development	170,704	233,626	103,634	167,453	96,633	153,822	73,995	94,235
Canada	96,403	184,606	85,641	117,150	51,881	126,130	59,821	75,499
U.S.	74,301	49,020	17,993	50,303	44,752	27,692	14,174	18,736
Property acquisitions	(62)	506	1,085	—	208	59	1,443	89
Proceeds from dispositions	(50)	(235)	(148)	(25,460)	(14)	(27)	(6,857)	(701)
Net debt (1)	2,814,844	995,170	987,446	1,113,559	1,123,297	1,275,680	1,409,717	1,564,658
Total assets (3)	8,617,444	5,180,059	5,103,769	4,923,617	4,870,432	4,917,811	4,834,643	4,453,971
Common shares outstanding	862,192	545,553	544,930	547,615	560,139	569,214	564,213	564,213
Daily production
Total production (boe/d)	89,761	86,760	86,864	83,194	83,090	80,867	80,789	79,872
Canada (boe/d)	55,874	60,651	56,946	55,803	54,919	53,385	50,362	48,124
U.S. (boe/d)	33,887	26,109	29,918	27,391	28,170	27,482	30,428	31,748
Benchmark prices
WTI oil (US$/bbl)	73.78	76.13	82.64	91.56	108.41	94.29	77.19	70.56
WCS heavy oil ($/bbl)	78.85	69.44	77.37	93.62	122.05	100.99	78.82	71.81
Edmonton par oil ($/bbl)	95.13	99.04	109.57	116.79	137.79	115.66	93.29	83.78
CAD/USD avg exchange rate	1.3431	1.3520	1.3577	1.3059	1.2766	1.2661	1.2600	1.2601
AECO natural gas ($/mcf)	2.35	4.34	5.58	5.81	6.27	4.59	4.94	3.54
NYMEX natural gas (US$/mmbtu)	2.10	3.42	6.26	8.20	7.17	4.95	5.83	4.01
Total sales, net of blending and other expense ($/boe) (2)	66.82	63.48	74.93	87.68	105.44	86.89	70.42	63.85
Royalties ($/boe) (4)	(13.21)	(11.94)	(15.23)	(19.21)	(22.69)	(16.86)	(13.47)	(12.32)
Operating expense ($/boe) (4)	(14.62)	(14.40)	(13.06)	(14.39)	(14.21)	(13.85)	(12.83)	(11.46)
Transportation expense ($/boe) (4)	(1.78)	(2.18)	(1.85)	(1.67)	(1.56)	(1.27)	(1.10)	(1.06)
Operating netback ($/boe) (2)	37.21	34.96	44.79	52.41	66.98	54.91	43.02	39.01
Financial derivatives (loss) gain ($/boe) (4)	2.00	0.69	(6.21)	(9.98)	(16.41)	(11.59)	(9.49)	(7.34)
Operating netback after financial derivatives ($/boe) (2)	39.21	35.65	38.58	42.43	50.57	43.32	33.53	31.67

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

(4)Calculated as royalties expense, 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.                                            

Q2 2023 MD&A    21

Our results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have strengthened. Production of 89,761 boe/d for Q2/2023 has steadily increased from 79,872 boe/d in Q4/2020 which reflects strong well performance and increased development activity as commodity prices have improved along with the production contribution from the Merger with Ranger which closed on June 20, 2023.

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 in our realized sales price of $105.44/boe for Q2/2022. Our realized price of $66.82/boe for Q2/2023 reflects recent declines in crude oil prices caused by concern over future demand and economic slowdowns.

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 $273.6 million for Q2/2023 reflects strong price realizations and production results from our development plans in the U.S. and Canada in addition to the Merger with Ranger.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, acquisitions and dispositions, changes in our free cash flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. The increase in net debt(1) from $1.6 billion at Q4/2020 to $2.8 billion at Q2/2023 is primarily a result of the Merger with Ranger which closed in Q2/2023 along with $159.0 million of shareholder returns. The change in net debt also reflects free cash flow(2) of $954.3 million 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.

Baytex Energy Corp.                                            

Q2 2023 MD&A    22

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, 2022 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, 2022, additional information related to our emissions and sustainability initiatives is available on our website.

Reporting Regulations

In June 2023, the International Sustainability Standards Board ("ISSB") issued IFRS S1 General Requirements for Disclosure of Sustainability-related Financial Information and IFRS S2 Climate-related Disclosures which are effective for annual reporting periods beginning on or after January 1, 2024. These standards provide for transition relief in IFRS S1 that allow reporting entity to report on only climate-related risks and opportunities in the first year of reporting under the sustainability standards.

The Canadian Securities Administrators ("CSA") are responsible for determining the reporting requirements for public companies in Canada and are responsible for decisions related to the adoption of the sustainability disclosure standard, including the effective annual reporting dates. The CSA issued proposed National Instrument NI-51-107 – Disclosure of Climate-related Matters in October 2021. The CSA intends to consider the ISSB standards in addition to development in United States reporting requirements in its decision relating to development of climate-related disclosure requirements for Canadian reporting issuers. The CSA will involve the Canadian Sustainability Standards Board ("CSSB") for a combined review of the suitability of the adopting the ISSB standards in Canada. There is no requirement for public companies in Canada to adopt the ISSB standards until the CSA and CSSB have issued a decision on reporting requirements in Canada. While we are actively reviewing the ISSB standards we have not yet determined the impact on future financial statements nor have we quantified the costs to comply with such standards.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at June 30, 2023, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the six months ended June 30, 2023 except for the critical accounting estimates related to the business combination with Ranger. 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, 2022.

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.

Baytex Energy Corp.                                            

Q2 2023 MD&A    23

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

	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2023		2022		2023		2022
Petroleum and natural gas sales	$	598,760	$	854,169	$	1,154,096	$	1,527,994
Light oil and condensate (1)	(308,810)		(415,592)		(597,275)		(776,567)
NGL (1)	(20,163)		(33,183)		(41,997)		(62,674)
Natural gas sales (1)	(18,338)		(59,293)		(46,290)		(98,214)
Heavy oil sales	$	251,449	$	346,101	$	468,534	$	590,539
Blending and other expense (2)	(52,995)		(56,895)		(112,676)		(98,335)
Heavy oil, net of blending and other expense	$	198,454	$	289,206	$	355,858	$	492,204

(1)Component of petroleum and natural gas sales. See Note 13 – Petroleum and Natural Gas Sales in the consolidated financial statements for the three and six months ended June 30, 2023 for further information.

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

Operating netback

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

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

	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2023		2022		2023		2022
Petroleum and natural gas sales	$	598,760	$	854,169	$	1,154,096	$	1,527,994
Blending and other expense	(52,995)		(56,895)		(112,676)		(98,335)
Total sales, net of blending and other expense	545,765		797,274		1,041,420		1,429,659
Royalties	(107,920)		(171,559)		(201,173)		(294,279)
Operating expense	(119,438)		(107,426)		(231,846)		(208,192)
Transportation expense	(14,574)		(11,758)		(31,579)		(20,973)
Operating netback	303,833		506,531		576,822		906,215
Realized financial derivatives gain (loss) (1)	16,365		(124,042)		21,780		(208,408)
Operating netback after realized financial derivatives	$	320,198	$	382,489	$	598,602	$	697,807

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three and six months ended June 30, 2023 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.

Baytex Energy Corp.                                            

Q2 2023 MD&A    24

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

	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2023		2022		2023		2022
Cash flows from operating activities	$	192,308	$	360,034	$	377,246	$	559,008
Change in non-cash working capital	40,795		(17,046)		79,849		$	60,294
Additions to exploration and evaluation assets	(741)		(2,338)		(1,231)		(5,897)
Additions to oil and gas properties	(169,963)		(94,295)		(403,099)		(244,558)
Payments on lease obligations	(1,181)		(1,039)		(2,336)		(2,213)
Transaction costs	32,832		—		41,703		—
Cash premiums on derivatives	2,263		—		2,263		—
Free cash flow	$	96,313	$	245,316	$	94,395	$	366,634

Non-GAAP Financial Ratios

Heavy oil, net of blending and other expense per bbl

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

Total sales, net of blending and other expense per boe

Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is calculated as total sales, net of blending and other expense (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period.

Average royalty rate

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

Operating netback per boe

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

Capital Management Measures

Net debt

We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We define net debt to be the sum of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade and other payables, cash, and trade and other receivables. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.

Baytex Energy Corp.                                            

Q2 2023 MD&A    25

The following table summarizes our calculation of net debt.

($ thousands)	June 30, 2023		December 31, 2022
Credit facilities	$	964,332	$	383,031
Unamortized debt issuance costs - Credit facilities (1)	22,571		2,363
Long-term notes	1,563,897		547,598
Unamortized debt issuance costs - Long-term notes (1)	37,571		6,999
Trade and other payables	616,608		281,404
Cash	(19,637)		(5,464)
Trade and other receivables	(370,498)		(228,485)
Net debt	$	2,814,844	$	987,446

(1)Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three and six months ended June 30, 2023. 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 our 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 retirement obligations settled during the applicable period, transaction costs and cash premiums on derivatives.

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

	Three Months Ended June 30				Six Months Ended June 30
($ thousands)	2023		2022		2023		2022
Cash flow from operating activities	$	192,308	$	360,034	$	377,246	$	559,008
Change in non-cash working capital	40,795		(17,046)		79,849		60,294
Asset retirement obligations settled	5,392		2,716		9,518		6,009
Transaction costs	32,832		—		41,703		—
Cash premiums on derivatives	2,263		—		2,263		—
Adjusted funds flow	$	273,590	$	345,704	$	510,579	$	625,311

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 June 30, 2023, 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 June 30, 2023, the assets previously held by Ranger contributed revenues of $49.0 million (representing 8% of total revenues) and net income before tax of $0.9 million (representing 3% of total net income before tax). At June 30, 2023, current assets of $178.4 million, non-current assets of $3.3 billion, current liabilities of $321.7 million and non-current liabilities of $74.4 million were associated with the acquired entity.

Baytex Energy Corp.                                            

Q2 2023 MD&A    26

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: expectations regarding our intention to further strengthen our balance sheet and the allocation of free cash flow, including with respect to debt repayment and shareholder returns; our 2023 guidance on a stand-alone basis with respect to exploration and development expenditures, average daily production, royalty rate and operating, transportation, general and administrative and interest expenses; the existence, operation and strategy of our risk management program; that we expect to cash settle share awards; the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; that we may issue debt or equity securities, sell assets or adjust capital spending.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; the future impact of wildfires on our production; that our core assets have more than 10 years development inventory at the current pace of development; 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, including operating and transportation costs; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our hedging program; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; 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: risks relating to any unforeseen liabilities of Baytex; that Baytex fails to meet its guidance; the volatility of oil and natural gas prices and price differentials (including the impacts of Covid-19); risks related to ongoing wildfires; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; risks associated with large projects; costs to develop and operate our properties, including transportation costs; public perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; 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 of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2022, 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.

Dividend Advisory

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) 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.