Baytex Energy Corp.
2023 MD&A                                                     1

BAYTEX ENERGY CORP.     Exhibit 99.3

Management’s Discussion and Analysis

For the years ended December 31, 2023 and 2022

Dated February 28, 2024

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the years ended December 31, 2023 and 2022. This information is provided as of February 28, 2024. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months and year ended December 31, 2023 ("Q4/2023" and "2023") have been compared with the results for the three months and year ended December 31, 2022 ("Q4/2022" and "2022"). This MD&A should be read in conjunction with the Company’s audited consolidated financial statements (“consolidated financial statements”) for the years ended December 31, 2023 and 2022, together with the accompanying notes and the Annual Information Form ("AIF") for the year ended December 31, 2023. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.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 issued 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 operated and non-operated assets in Texas.

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 increased 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 80% weighted towards high netback light oil and liquids and is primarily operated which increases our ability to effectively allocate capital.

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

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

Baytex Energy Corp.
2023 MD&A                                                     2

2023 ANNUAL HIGHLIGHTS

Baytex delivered strong operating and financial results in 2023. Our annual results include six months of operations following the Merger with Ranger and demonstrate the strength of our increased scale and diversified North American oil-weighted portfolio. Annual production of 122,154 boe/d was consistent with our revised annual guidance of 121,500 to 122,000 boe/d and reflects strong results from our drilling programs in Western Canada and the Eagle Ford in Texas. We invested $1.0 billion in exploration and development expenditures and generated free cash flow(1) of $543.6 million in 2023.

Exploration and development expenditures totaled $1.0 billion for 2023. In the U.S. we invested $549.6 million during 2023 and production averaged 60,997 boe/d which is higher than 28,245 boe/d in 2022 due to the Merger. We invested $463.2 million in Canada in 2023 and generated production of 61,157 boe/d during 2023 compared to 55,275 boe/d in 2022 which reflects growth driven by strong well performance from our heavy oil operations at Peavine.

Oil prices were lower in 2023 as a result of global supply growth which has resulted in a more balanced crude market relative to 2022 when prices were elevated as the global supply shortfall was exacerbated by uncertainty related to Russian supply. The average WTI benchmark price for 2023 was US$77.62/bbl which was US$16.61/bbl lower than 2022 when WTI averaged US$94.23/bbl.

Adjusted funds flow(2) of $1.6 billion in 2023 was higher than $1.2 billion for 2022 which reflects higher production following the Merger partially offset by lower realized pricing due to the decline in benchmark prices. Free cash flow of $543.6 million in 2023 was lower than $621.5 million for 2022 due to lower benchmark prices, inflationary pressures in Canada and the U.S. along with increased development activity following the Merger. Cash flows from operating activities increased to $1.3 billion in 2023 compared to $1.2 billion in 2022. The net loss of $233.4 million for 2023 includes an impairment loss of $833.7 million compared to net income of $855.6 million in 2022 which included impairment reversals of $267.7 million.

Net debt(2) of $2.5 billion at December 31, 2023 was $1.5 billion higher than $1.0 billion at December 31, 2022 due to the cash consideration paid and net debt assumed in conjunction with the Merger. Since the Merger on June 20, 2023, we have paid down $280.6 million of net debt and increased our shareholder returns to 50% of free cash flow which allowed us to increase our share buyback program and introduce a dividend. The remainder of our free cash flow will be allocated to the balance sheet.

On June 23, 2023, we renewed our Normal Course Issuer Bid ("NCIB") with the Toronto Stock Exchange for a share buyback program for up to 68.4 million shares (10% of our public float at the time). During 2023 we repurchased 40.5 million shares for $221.9 million representing 5% of the outstanding shares at the inception of the NCIB renewal. On October 2, 2023 and January 2, 2024, we paid a quarterly cash dividend of CDN$0.0225 per share as part of our shareholder returns commitment. On February 28, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders of record on March 15, 2024. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”

(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

Baytex Energy Corp.
2023 MD&A                                                     3

GUIDANCE

Our 2024 annual guidance includes exploration and development expenditures of $1.2 - $1.3 billion and is designed to generate annual production of 150,000 - 156,000 boe/d. Our annual production guidance remains unchanged despite weather-related disruptions in Texas that we estimate will result in Q1/2024 production that is approximately 2,000 boe/d lower than our budget expectation.

The following table compares our 2023 revised annual guidance and 2024 annual guidance to our 2023 results. Production, exploration and development expenditures, and expenses were relatively consistent with our revised annual guidance for 2023 which reflects our ongoing efforts to deliver strong operating results while we maintain a competitive cost structure. A higher proportion of our 2024 production will be from the Eagle Ford which will result in a modest increase in our per unit expected transportation costs for 2024 relative to our 2023 results along with a decrease in our operating costs. We continue to use free cash flow for debt repayment and expect cash interest of $3.40/boe in 2024 compared to $3.58/boe in 2023.

	2023 Revised Annual Guidance (1)	2023 Results		2024 Annual Guidance (2)
Exploration and development expenditures	~ $1,035 million	$1,012.8 million		$1.2 - $1.3 billion
Production (boe/d)	121,500 - 122,000 boe/d	122,154 boe/d		150,000 - 156,000
Expenses:
Average royalty rate (3)	21.0% - 22.0%	21.2	%	23%
Operating (4)	~ $12.75/boe	$12.80/boe		$11.25 - $12.00/boe
Transportation (4)	~ $2.10/boe	$2.00/boe		$2.35 - $2.55/boe
General and administrative (4)	$80 million ($1.80/boe)	$70 million ($1.57/boe)		$92 million ($1.65/boe)
Cash Interest (4)	$156 million ($3.50/boe)	$160 million ($3.58/boe)		$190 million ($3.40/boe)
Current Income Taxes (5)	$14 million ($0.31/boe)	$11 million ($0.24/boe)		$40 million ($0.72/boe)
Leasing expenditures	$13 million	$12 million		$12 million
Asset retirement obligations settled	$25 million	$26 million		$30 million

(1)As announced on November 2, 2023.

(2)As announced on December 6, 2023.

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

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

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

Baytex Energy Corp.
2023 MD&A                                                     4

RESULTS OF OPERATIONS

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

Production

	Years Ended December 31
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	15,698		37,691		53,389		16,060		17,041		33,101
Heavy oil	35,460		—		35,460		28,993		—		28,993
Natural Gas Liquids ("NGL")	2,090		12,214		14,304		1,896		5,679		7,575
Total liquids (bbl/d)	53,248		49,905		103,153		46,949		22,720		69,669
Natural gas (mcf/d)	47,454		66,556		114,010		49,954		33,146		83,101
Total production (boe/d)	61,157		60,997		122,154		55,275		28,245		83,519
Production Mix
Segment as a percent of total	50	%	50	%	100	%	66	%	34	%	100	%
Light oil and condensate	26	%	62	%	44	%	29	%	60	%	40	%
Heavy oil	58	%	—	%	29	%	52	%	—	%	35	%
NGL	3	%	20	%	12	%	3	%	20	%	9	%
Natural gas	13	%	18	%	15	%	16	%	20	%	16	%

Production averaged 122,154 boe/d in 2023 compared to 83,519 boe/d in 2022. Production was higher in 2023 primarily due to the production contribution from the properties acquired from Ranger along with our successful development program in Canada.

In Canada, production increased to 61,157 boe/d in 2023 compared to 55,275 boe/d in 2022. The 5,882 boe/d increase in production is primarily due to strong well performance from our Clearwater heavy oil development program at Peavine.

In the U.S., production was 60,997 boe/d in 2023 compared to 28,245 boe/d for 2022. The production from the Merger contributed to the 32,752 boe/d increase in production for 2023 relative to 2022. Production from the acquired Eagle Ford assets is primarily operated and is weighted towards light oil which resulted in a higher proportion of our total production being light oil in 2023.

Total production of 122,154 boe/d for 2023 was consistent with our revised annual guidance of approximately 121,500 - 122,000 boe/d. We expect production in 2024 to average 150,000 - 156,000 boe/d which is consistent with the production for the second half of 2023 and includes the impact of the non-core Viking disposition which was producing approximately 4,000 boe/d when the sale was completed in December 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 throughout 2023 relative to 2022 as a result of global supply growth which has resulted in a more balanced crude oil market relative to 2022 when prices were elevated as the global supply shortfall was exacerbated by uncertainty related to Russian supply. OPEC curtailed production during the second half of 2023 to stabilize the market after a period of weaker prices in the first half of 2023. As a result of these factors, the WTI benchmark price averaged US$77.62/bbl for 2023 which was US$16.61/bbl lower than US$94.23/bbl for 2022 when WTI was higher due to uncertainty around global supply caused by Russia's invasion of Ukraine.

Baytex Energy Corp.
2023 MD&A                                                     5

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark averaged US$79.29/bbl during 2023, representing a premium of US$1.67/bbl relative to WTI, compared to US$97.79/bbl or a premium of US$3.57/bbl for 2022. Reduced demand on the Gulf Coast during 2023 resulted in a slightly lower premium compared to 2022 when there was heightened uncertainty over global supply.

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 based on production and inventory levels in Western Canada.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $100.46/bbl for 2023 compared to $119.95/bbl for 2022. Edmonton par traded at a US$3.18/bbl discount to WTI in 2023 compared to a discount of US$2.07/bbl for 2022.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark price for 2023 averaged $79.58/bbl compared to $98.94/bbl for 2022. The WCS differential to WTI was US$18.65/bbl in 2023 which is consistent with US$18.21/bbl in 2022.

Natural Gas

Reduced demand for North American gas resulted in lower prices in 2023 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$2.74/mmbtu for 2023 compared to US$6.64/mmbtu for 2022.

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 $2.93/mcf during 2023 which is lower than $5.56/mcf during 2022.

The following tables compare select benchmark prices and our average realized selling prices for the years ended December 31, 2023 and 2022.

	Years Ended December 31
	2023	2022	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	77.62	94.23	(16.61)
MEH oil (US$/bbl) (2)	79.29	97.79	(18.50)
MEH oil differential to WTI (US$/bbl)	1.67	3.57	(1.90)
Edmonton par oil ($/bbl) (3)	100.46	119.95	(19.49)
Edmonton par oil differential to WTI (US$/bbl)	(3.18)	(2.07)	(1.11)
WCS heavy oil ($/bbl) (4)	79.58	98.94	(19.36)
WCS heavy oil differential to WTI (US$/bbl)	(18.65)	(18.21)	(0.44)
AECO natural gas price ($/mcf) (5)	2.93	5.56	(2.63)
NYMEX natural gas price (US$/mmbtu) (6)	2.74	6.64	(3.90)
CAD/USD average exchange rate	1.3495	1.3016	0.0479

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

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

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

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

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

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

Baytex Energy Corp.
2023 MD&A                                                     6

	Years Ended December 31
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	100.34	$	105.71	$	104.13	$	118.23	$	125.00	$	121.72
Heavy oil, net of blending and other expense ($/bbl) (2)	66.19		—		66.19		86.24		—		86.24
NGL ($/bbl) (1)	30.38		27.55		27.96		44.57		43.25		43.58
Natural gas ($/mcf) (1)	2.83		3.15		3.02		5.52		7.88		6.46
Total sales, net of blending and other expense ($/boe) (2)	$	67.39	$	74.27	$	70.82	$	86.10	$	93.36	$	88.56

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

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

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $70.82/boe for 2023 compared to $88.56/boe for 2022. In Canada, our realized sales price of $67.39/boe for 2023 was lower than $86.10/boe for 2022 and our realized sales price in the U.S. of $74.27/boe in 2023 decreased from $93.36/boe in 2022. The decrease in our realized price in Canada and the U.S. for 2023 was a result of lower North American benchmark prices relative to 2022.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) in 2023 was $100.34/bbl compared to $118.23/bbl in 2022. The decrease in our realized light oil and condensate price for 2023 was primarily a result of lower benchmark prices. Our realized price represents a discount of $0.12/bbl to the Edmonton par benchmark which reflects higher Duvernay production in the second half of 2023 which resulted in a narrower discount relative to $1.72/bbl in 2022.

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 $105.71/bbl for 2023 compared to $125.00/bbl for 2022. Expressed in U.S. dollars, our realized light oil and condensate price of US$78.33/bbl for 2023 was lower than US$96.04/bbl in 2022 and represents discounts to MEH of US$0.96/bbl for 2023 which is narrower than a discount of US$1.75/bbl in 2022. The narrower discount in 2023 reflects the additional production from the Merger in the second half of the year when the MEH benchmark was higher relative to the annual average benchmark price.

Our realized heavy oil price, net of blending and other expense(1) averaged $66.19/bbl in 2023 compared to $86.24/bbl in 2022. The $20.05/bbl decrease in our realized heavy oil price, net of blending and other expense is consistent with a $19.36/bbl decrease in WCS benchmark in 2023 compared to 2022.

Our realized NGL price(2) as a percentage of WTI will vary based on the product mix of our NGL volumes and changes in the market prices of the underlying products. Our realized NGL price was $27.96/bbl in 2023 or 27% of WTI (expressed in Canadian dollars) compared to $43.58/bbl or 36% of WTI (expressed in Canadian dollars) in 2022. Our realized NGL price in Canada and the U.S. was lower as a percentage of WTI in 2023 relative to 2022 which reflects lower demand as a result of increased production in North America.

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 $2.83/mcf for 2023 compared to $5.52/mcf for 2022. In the U.S., our realized natural gas price was US$2.33/mcf for 2023 compared to US$6.05/mcf for 2022. The decrease in our realized gas price in Canada and the U.S. is consistent with the decreases in the AECO monthly and NYMEX monthly benchmark prices in 2023 compared to 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.
2023 MD&A                                                     7

PETROLEUM AND NATURAL GAS SALES

	Years Ended December 31
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	574,910	$	1,454,213	$	2,029,123	$	693,043	$	777,506	$	1,470,549
Heavy oil	1,081,549		—		1,081,549		1,102,076		—		1,102,076
NGL	23,174		122,823		145,997		30,847		89,658		120,505
Total liquids sales	1,679,633		1,577,036		3,256,669		1,825,966		867,164		2,693,130
Natural gas sales	49,388		76,564		125,952		100,595		95,320		195,915
Total petroleum and natural gas sales	1,729,021		1,653,600		3,382,621		1,926,561		962,484		2,889,045
Blending and other expense	(224,802)		—		(224,802)		(189,454)		—		(189,454)
Total sales, net of blending and other expense (1)	$	1,504,219	$	1,653,600	$	3,157,819	$	1,737,107	$	962,484	$	2,699,591

(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 $3.2 billion for 2023 increased $458.2 million from $2.7 billion for 2022. The Merger with Ranger along with higher production from our successful development programs resulted in an increase in total sales in 2023 relative to 2022 partially offset by the effect of lower benchmark prices.

In Canada, total sales, net of blending and other expense, was $1.5 billion for 2023 which is a decrease of $232.9 million from $1.7 billion reported for 2022. The decrease in total petroleum and natural gas sales was the result of lower realized pricing for 2023 relative to 2022 which resulted in a $417.7 million decrease in total sales, net of blending and other expense. The effect of lower realized pricing was partially offset by higher production which resulted in a $184.8 million increase in total sales, net of blending and other expense, relative to 2022.

In the U.S., petroleum and natural gas sales of $1.7 billion in 2023 was $691.1 million higher than $962.5 million reported for 2022. Higher production in 2023 relative to 2022 was primarily due to the Merger with Ranger and contributed to a $1.1 billion increase in total petroleum and natural gas sales which was partially offset by lower realized pricing which resulted in a $425.0 million decrease in total petroleum and natural gas sales.

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 depending on 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 years ended December 31, 2023 and 2022.

	Years Ended December 31
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	213,148		$	456,644		$	669,792		$	277,428		$	285,536		$	562,964
Average royalty rate (1)(2)	14.2		%	27.6		%	21.2		%	16.0		%	29.7		%	20.9		%
Royalties per boe (3)	$	9.55		$	20.51		$	15.02		$	13.75		$	27.70		$	18.47

(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 2023 were $669.8 million or 21.2% of total sales, net of blending and other expense, compared to $563.0 million or 20.9% in 2022. Total royalty expense was higher in 2023 due to higher total sales, net of blending and other expense, relative to 2022. Our average royalty rate of 21.2% for 2023 was higher than 20.9% for 2022 due to a higher proportion of our production being from the Eagle Ford in 2023 which has a higher royalty rate than our Canadian properties. Our average royalty rate of 21.2% for 2023 was consistent with expectations and our annual guidance range of 21.0% - 22.0% for 2023.

In Canada, the average royalty rate(1) was 14.2% in 2023 which was lower than 16.0% for 2022 and reflects lower benchmark prices for our production in Canada. In the U.S., the average royalty rate was 27.6% for 2023 which is lower than 29.7% for 2022 due to production contributed by the acquired Ranger assets which have a lower royalty rate relative to our legacy non-operated Eagle Ford properties.

We expect our average royalty rate to be approximately 23% for 2024 which reflects a higher proportion of our production from the Eagle Ford in 2024 relative to 2023 with a full year of results including the Merger.

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

OPERATING EXPENSE

	Years Ended December 31
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	368,605	$	202,234	$	570,839	$	327,894	$	94,772	$	422,666
Operating expense per boe (1)	$	16.51	$	9.08	$	12.80	$	16.25	$	9.19	$	13.86

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

Total operating expense was $570.8 million ($12.80/boe) in 2023 compared to $422.7 million ($13.86/boe) in 2022. Total operating expense for 2023 increased relative to 2022 while per boe operating costs were lower as the Ranger properties have lower per boe operating expenses. Operating expense of $12.80/boe for 2023 was consistent with our revised annual guidance of ~ $12.75/boe.

In Canada, operating expense was $368.6 million ($16.51/boe) for 2023 compared to $327.9 million ($16.25/boe) for 2022. The total operating expenses were higher in Canada as a result of higher production while per boe operating costs in 2023 were relatively consistent with 2022.

Our U.S. operating expense was $202.2 million ($9.08/boe) for 2023 compared to $94.8 million ($9.19/boe) for 2022. Total operating expense in the U.S. was higher in 2023 relative to 2022 with the addition of production from the properties acquired from Ranger. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$6.73/boe for 2023 which is slightly lower than US$7.06/boe for 2022 which reflects the lower per unit operating cost on the acquired operated Eagle Ford properties.

We expect annual operating expense of $11.25 - $12.00/boe for 2024 which reflects a higher proportion of our production from our Eagle Ford properties relative to 2023, which have lower per unit operating costs.

TRANSPORTATION EXPENSE

Transportation expense includes the costs to move production 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 depending on trucking rates and hauling distances as we seek to optimize sales prices. Transportation expense in our U.S. operations reflects the costs incurred to deliver our production to a centralized sales point via truck or pipeline.

The following table compares our transportation expense for the years ended December 31, 2023 and 2022.

	Years Ended December 31
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	64,325	$	24,981	$	89,306	$	48,561	$	—	$	48,561
Transportation expense per boe (1)	$	2.88	$	1.12	$	2.00	$	2.41	$	—	$	1.59

(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 $89.3 million ($2.00/boe) for 2023 compared to $48.6 million ($1.59/boe) for 2022. In Canada, the total transportation expense and per unit costs are higher in 2023 relative to 2022 as a result of additional heavy oil production primarily at Peavine, along with higher trucking rates due to increased fuel surcharges and truck shortages. Transportation expense in the U.S. is consistent with expectations for 2023 and reflects trucking and pipeline transportation costs on our Eagle Ford operations acquired from Ranger.

Transportation expense of $2.00/boe in 2023 was slightly below our revised annual guidance of ~ $2.10/boe for 2023. We expect annual transportation expense of $2.35 - $2.55/boe for 2024 which reflects a higher proportion of our 2024 production from the Eagle Ford.

Baytex Energy Corp.
2023 MD&A                                                     8

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 $224.8 million for 2023 compared to $189.5 million for 2022. The increase in blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in 2023 relative to 2022.

FINANCIAL DERIVATIVES

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are entered. The following table summarizes the results of our financial derivative contracts for the years ended December 31, 2023 and 2022.

	Years Ended December 31
($ thousands)	2023		2022		Change
Realized financial derivatives gain (loss)
Crude oil	$	35,687	$	(299,788)	$	335,475
Natural gas	525		(34,693)		35,218
Total	$	36,212	$	(334,481)	$	370,693
Unrealized financial derivatives (loss) gain
Crude oil	$	(17,674)	$	136,879	$	(154,553)
Natural gas	6,157		5,082		1,075
Equity total return swap	—		(6,490)		6,490
Total	$	(11,517)	$	135,471	$	(146,988)
Total financial derivatives gain (loss)
Crude oil	$	18,013	$	(162,909)	$	180,922
Natural gas	6,682		(29,611)		36,293
Equity total return swap	—		(6,490)		6,490
Total	$	24,695	$	(199,010)	$	223,705

We recorded a financial derivatives gain of $24.7 million for 2023 compared to a loss of $199.0 million for 2022. The realized financial derivatives gain for 2023 of $36.2 million was primarily a result of market prices for crude oil and natural gas settling at levels below the prices set in our derivative contracts. The unrealized financial derivatives loss of $11.5 million for 2023 is primarily due to changes in forecasted crude oil pricing used to revalue the volumes outstanding on our crude oil and natural gas contracts in place at December 31, 2023 relative to December 31, 2022. The fair value of our financial derivative contracts resulted in a net asset of $23.3 million at December 31, 2023 compared to a net asset of $10.1 million at December 31, 2022.

Baytex Energy Corp.
2023 MD&A                                                     9

Baytex had the following commodity financial derivative contracts as at February 28, 2024.

	Period	Volume	Price/Unit (1)	Index
Oil
Basis differential	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
Basis differential	July 2024 to Dec 2024	4,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.40/bbl	WCS
Basis differential (2)	July 2024 to Dec 2024	5,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.18/bbl	WCS
Basis differential (2)	Apr 2024 to Dec 2024	3,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.27/bbl	WCS
Basis differential (2)	July 2024 to Dec 2024	3,000 bbl/d	WTI less US$13.70/bbl	WCS
Basis differential	Jan 2024 to Dec 2024	1,500 bbl/d	WTI less US$2.65/bbl	MSW
Basis differential (2)	Apr 2024 to Dec 2024	1,250 bbl/d	WTI less US$3.40/bbl	MSW
Basis differential (2)	July 2024 to Dec 2024	2,500 bbl/d	WTI less US$2.85/bbl	MSW
Collar	Jan 2024 to Mar 2024	10,400 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Jun 2024	24,500 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$90.21	WTI
Collar	Apr 2024 to Jun 2024	11,750 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$94.15	WTI
Collar	July 2024 to Dec 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Sep 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$100.00	WTI
Collar (2)	July 2024 to Dec 2024	9,000 bbl/d	US$60.00/US$84.58	WTI
Collar (2)	Oct 2024 to Dec 2024	7,000 bbl/d	US$60.00/US$86.43	WTI
Natural Gas
Fixed Sell	Jan 2024 to Mar 2024	3,500 mmbtu/d	US$3.5025	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	Jan 2024 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 entered subsequent to December 31, 2023.

Baytex Energy Corp.
2023 MD&A                                                     10

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the years ended December 31, 2023 and 2022.

	Years Ended December 31
	2023						2022
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	61,157		60,997		122,154		55,275		28,245		83,519
Operating netback:
Total sales, net of blending and other expense (1)	$	67.39	$	74.27	$	70.82	$	86.10	$	93.36	$	88.56
Less:
Royalties (2)	(9.55)		(20.51)		(15.02)		(13.75)		(27.70)		(18.47)
Operating expense (2)	(16.51)		(9.08)		(12.80)		(16.25)		(9.19)		(13.86)
Transportation expense (2)	(2.88)		(1.12)		(2.00)		(2.41)		—		(1.59)
Operating netback (1)	$	38.45	$	43.56	$	41.00	$	53.69	$	56.47	$	54.64
Realized financial derivatives gain (loss) (3)	—		—		0.81		—		—		(10.97)
Operating netback after financial derivatives (1)	$	38.45	$	43.56	$	41.81	$	53.69	$	56.47	$	43.67

(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 of $41.00/boe for 2023 was lower than $54.64/boe for 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 expense and transportation expense of $14.80/boe was lower than $15.45/boe in 2022 which reflects lower operating and transportation costs on the operated Eagle Ford properties acquired from Ranger. Including realized gains on financial derivatives, our operating netback was $41.81/boe for 2023 compared to $43.67/boe for 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.

The following table summarizes our G&A expense for the years ended December 31, 2023 and 2022.

	Years Ended December 31
($ thousands except for per boe)	2023		2022		Change
Gross general and administrative expense	$	84,096	$	55,785	$	28,311
Overhead recoveries	(14,307)		(5,515)		(8,792)
General and administrative expense	$	69,789	$	50,270	$	19,519
General and administrative expense per boe (1)	$	1.57	$	1.65	$	(0.08)

(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 $69.8 million ($1.57/boe) for 2023 compared to $50.3 million ($1.65/boe) for 2022. G&A expense was $19.5 million higher relative to 2022 due to the increase in staffing levels and integration costs associated with the Merger with Ranger. G&A expense of $69.8 million ($1.57/boe) for 2023 was lower than our revised annual guidance of $80 million ($1.80/boe). We expect annual G&A expense of $92 million ($1.65/boe) for 2024 which reflects a full-year of staffing costs associated with the personnel retained after the acquisition of Ranger.

Baytex Energy Corp.
2023 MD&A                                                     11

FINANCING AND INTEREST EXPENSE

Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.

The following table summarizes our financing and interest expense for the years ended December 31, 2023 and 2022.

	Years Ended December 31
($ thousands except for per boe)	2023		2022		Change
Interest on credit facilities	$	56,713	$	19,550	$	37,163
Interest on long-term notes	102,426		60,643		41,783
Interest on lease obligations	684		193		491
Cash interest	$	159,823	$	80,386	$	79,437
Amortization of debt issue costs	11,944		6,286		5,658
Accretion of asset retirement obligations	20,406		15,683		4,723
Early redemption expense	—		2,462		(2,462)
Financing and interest expense	$	192,173	$	104,817	$	87,356
Cash interest per boe (1)	$	3.58	$	2.64	$	0.94
Financing and interest expense per boe (1)	$	4.31	$	3.44	$	0.87

(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 $192.2 million ($4.31/boe) in 2023 compared to $104.8 million ($3.44/boe) in 2022. Higher interest costs in 2023 relative to 2022 are primarily a result of the additional debt outstanding after the Merger with Ranger.

Cash interest of $159.8 million ($3.58/boe) in 2023 was higher than $80.4 million ($2.64/boe) in 2022 as a result of additional debt outstanding in 2023 after the Merger which included the issuance of US$800.0 million aggregate principal amount of long-term notes. Interest on our credit facilities was higher in 2023 relative to 2022 due to the increase in applicable borrowing rates along with an increase in the principal amounts outstanding following the Merger. The weighted average interest rate applicable on our credit facilities was 7.6% in 2023 compared to 3.6% in 2022.

Accretion of asset retirement obligations of $20.4 million for 2023 was higher than $15.7 million for 2022 primarily due to higher discount rates in 2023 relative to 2022. Accretion of debt issues costs was higher in 2023 relative to 2022 due to the increase in debt issue costs associated with the expanded credit facilities and new long-term notes issued to fund the Merger with Ranger.

Cash interest of $159.8 million ($3.58/boe) for 2023 was consistent with our revised annual guidance of $156 million ($3.50/boe). We expect cash interest to be $190 million ($3.40/boe) for 2024.

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $8.9 million for 2023 compared to $30.2 million for 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 and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the years ended December 31, 2023 and 2022.

	Years Ended December 31
($ thousands except for per boe)	2023		2022		Change
Depletion and depreciation	$	1,047,904	$	587,050	$	460,854
Depletion and depreciation per boe(1)	$	23.50	$	19.26	$	4.24

(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.

Baytex Energy Corp.
2023 MD&A                                                     12

Depletion and depreciation expense was $1.0 billion ($23.50/boe) for 2023 compared to $587.1 million ($19.26/boe) for 2022. Total depletion and depreciation expense as well as the depletion and depreciation rate per boe were higher in 2023 relative to 2022 due to impairment reversals in Q4/2022 which increased the depletable base for our legacy assets in addition to depletion on the assets acquired from Ranger which have a higher depletion rate than our other properties.

IMPAIRMENT

2023 Impairment

At December 31, 2023, we identified indicators of impairment for oil and gas properties in our legacy non-operated Eagle Ford cash-generating unit ("CGU") due to changes in our reserves volumes and in our Viking CGU due to changes in reserves along with a loss recorded on disposition of an asset within the CGU. The recoverable amounts for the two CGUs were not sufficient to support their carrying values which resulted in an impairment of $833.7 million recorded at December 31, 2023.

At December 31, 2023, the recoverable amounts of the two CGUs were calculated using the following benchmark reference prices for the years 2024 to 2033 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to 2033 have been adjusted for inflation at an annual rate of 2.0%.

	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033
WTI crude oil (US$/bbl)	73.67	74.98	76.14	77.66	79.22	80.80	82.42	84.06	85.74	87.46
LLS crude oil (US$/bbl)	76.49	77.80	78.95	80.35	81.95	83.59	85.27	86.97	88.71	90.48
Edmonton par oil ($/bbl)	92.91	95.04	96.07	97.99	99.95	101.94	103.98	106.06	108.18	110.35
NYMEX Henry Hub gas (US$/mmbtu)	2.75	3.64	4.02	4.10	4.18	4.27	4.35	4.44	4.53	4.62
AECO gas ($/mmbtu)	2.20	3.37	4.05	4.13	4.21	4.30	4.38	4.47	4.56	4.65
Exchange rate (CAD/USD)	0.75	0.75	0.76	0.76	0.76	0.76	0.76	0.76	0.76	0.76

The following table summarizes the recoverable amount and impairment for each of the two CGUs at December 31, 2023 and demonstrates the sensitivity of the impairment to reasonably possible changes in key assumptions inherent in the calculation.

	Recoverable amount		Impairment loss		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Viking CGU	$	606,290	$	184,000	$	26,500	$	53,000	$	3,500
Eagle Ford Non-op CGU (1)	1,429,658		649,662		71,300		107,600		25,700

(1)There were no indicators of impairment identified for the Eagle Ford Operated CGU which includes the assets acquired from Ranger.

2022 Impairment Reversal

At December 31, 2022, indicators of impairment reversal were identified for oil and gas properties in five CGUs due to the increase in forecasted commodity prices in addition to changes in reserves volumes. The recoverable amount for three CGUs exceeded their carrying values which resulted in an impairment reversal of $245.2 million recorded at December 31, 2022. 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.

The following table summarizes the recoverable amount and impairment reversal for each of the five CGUs at December 31, 2022 and demonstrates the sensitivity of the impairment reversal to reasonably possible changes in key assumptions inherent in the calculation.

	Recoverable amount		Impairment  reversal		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU (1)	$	119,031	$	23,707	$	—	$	—	$	—
Peace River CGU (1)	676,939		140,534		—		—		—
Lloydminster CGU	449,250		—		11,500		53,000		—
Viking CGU	1,322,193		81,000		39,500		78,000		4,000
Eagle Ford Non-op CGU	2,102,646		—		95,800		131,100		28,500

(1)The impairment reversals for the Conventional and Peace River CGUs were limited to the total accumulated impairments less subsequent depletion of $23.7 million and $140.5 million, respectively. As a result, changes in the key assumptions presented in the table above have no impact on the amount of the impairment reversal as at December 31, 2022.

Baytex Energy Corp.
2023 MD&A                                                     13

SHARE-BASED COMPENSATION EXPENSE

Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with equity-classified 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 share-based compensation liability, and includes gains or losses on equity total return swaps. SBC expense varies with the quantity of unvested share awards outstanding and changes in the market price of our common shares.

We recorded SBC expense of $37.7 million for 2023 compared to $29.1 million for 2022. SBC expense for 2023 includes cash compensation expense of $21.5 million which is lower than $25.9 million for 2022. Lower cash SBC expense reflects a decrease in our share price during 2023 along with a reduction of the notional amount of equity return swaps outstanding in 2023 compared to 2022. SBC expense for 2023 also includes non-cash compensation expense of $16.2 million related to awards assumed in conjunction with the Merger which were settled in Baytex common shares.

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. 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.

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.

	Years Ended December 31
($ thousands except for exchange rates)	2023		2022		Change
Unrealized foreign exchange (gain) loss	$	(14,300)	$	45,073	$	(59,373)
Realized foreign exchange loss (gain)	3,452		(1,632)		5,084
Foreign exchange (gain) loss	$	(10,848)	$	43,441	$	(54,289)
CAD/USD exchange rates:
At beginning of period	1.3534		1.2656
At end of period	1.3205		1.3534

We recorded a foreign exchange gain of $10.8 million for 2023 compared to a loss of $43.4 million for 2022.

The unrealized foreign exchange gain of $14.3 million for 2023 is primarily related to changes in the reported amount of our long-term notes and credit facilities. The gain recorded in 2023 is due to a strengthening of the Canadian dollar relative to U.S. dollar at December 31, 2023 compared to December 31, 2022 and June 20, 2023 when additional U.S. denominated debt was issued to fund the Merger with Ranger. The unrealized foreign exchange loss of $45.1 million for 2022 relates to a weakening of the Canadian dollar relative to the U.S. dollar at December 31, 2022 compared to December 31, 2021 and reflects the remeasurement of our long-term notes and credit facilities.

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 $3.5 million for 2023 compared to a gain of $1.6 million for 2022.

INCOME TAXES

	Years Ended December 31
($ thousands)	2023		2022		Change
Current income tax expense	$	14,403	$	3,594	$	10,809
Deferred income tax (recovery) expense	(297,629)		31,716		(329,345)
Total income tax (recovery) expense	$	(283,226)	$	35,310	$	(318,536)

Baytex Energy Corp.
2023 MD&A                                                     14

Current income tax expense was $14.4 million for 2023 compared to $3.6 million recorded in 2022. Current income tax is higher in 2023 due to higher tax owed on our U.S. operations following the Merger with Ranger. We recorded a deferred income tax recovery of $297.6 million for 2023 compared to deferred tax expense of $31.7 million for 2022. The deferred tax recovery in 2023 is primarily related to the effects of the transaction structuring for the Merger in Q2/2023 along with the effects of impairment losses on our Canadian and U.S. assets in 2023.

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

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. We have also purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $166.6 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. Firstly, the reassessments allege that (i) the trusts were resettled, and (ii) the resulting successor trusts were not able to access the losses of the predecessor trusts. Secondly, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potentially penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to those/that taxpayer(s) to offset the reassessed income, including tax shelter from future years that may be carried back and applied to prior years.

The following table summarizes our Canadian and Foreign tax pools.

Canadian Tax Pools($ thousands)	December 31, 2023		December 31, 2022
Canadian oil and natural gas property expenditures	$	203,406	$	355,028
Canadian development expenditures	518,788		483,270
Undepreciated capital costs	280,564		275,987
Non-capital losses	643,697		818,326
Financing costs and other	98,816		62,442
Total Canadian tax pools	$	1,745,271	$	1,995,053
Foreign Tax Pools ($ thousands)
Depletion	1,893,577		139,013
Intangible drilling costs	352,021		$	—
Tangibles	213,372		14,483
Net operating losses	2,558,472		813,753
Other	468,554		96,157
Total Foreign tax pools	$	5,485,996	$	1,063,406

Baytex Energy Corp.
2023 MD&A                                                     15

NET (LOSS) INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the years ended December 31, 2023 and 2022 are set forth in the following table.

	Years Ended December 31
($ thousands)	2023		2022		Change
Petroleum and natural gas sales	$	3,382,621	$	2,889,045	$	493,576
Royalties	(669,792)		(562,964)		(106,828)
Revenue, net of royalties	2,712,829		2,326,081		386,748
Expenses
Operating	(570,839)		(422,666)		(148,173)
Transportation	(89,306)		(48,561)		(40,745)
Blending and other	(224,802)		(189,454)		(35,348)
Operating netback (1)	$	1,827,882	$	1,665,400	$	162,482
General and administrative	(69,789)		(50,270)		(19,519)
Cash interest	(159,823)		(80,386)		(79,437)
Realized financial derivatives gain (loss)	36,212		(334,481)		370,693
Realized foreign exchange (loss) gain	(3,452)		1,632		(5,084)
Other expense	(815)		(7,253)		6,438
Current income tax expense	(14,403)		(3,594)		(10,809)
Cash share-based compensation	(21,462)		(25,897)		4,435
Adjusted funds flow (2)	$	1,594,350	$	1,165,151	$	429,199
Transaction costs	(49,045)		—		(49,045)
Exploration and evaluation	(8,896)		(30,239)		21,343
Depletion and depreciation	(1,047,904)		(587,050)		(460,854)
Non-cash share-based compensation	(16,237)		(3,159)		(13,078)
Non-cash financing and interest	(32,350)		(24,431)		(7,919)
Non-cash other income	1,271		4,009		(2,738)
Unrealized financial derivatives (loss) gain	(11,517)		135,471		(146,988)
Unrealized foreign exchange gain (loss)	14,300		(45,073)		59,373
(Loss) gain on dispositions	(141,295)		4,898		(146,193)
Impairment (loss) reversal	(833,662)		267,744		(1,101,406)
Deferred income tax recovery (expense)	297,629		(31,716)		329,345
Net (loss) income	$	(233,356)	$	855,605	$	(1,088,961)

(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 $1.6 billion for 2023 compared to $1.2 billion for 2022. The $429.2 million increase in adjusted funds flow for 2023 is due to higher production from the Merger with Ranger which was partially offset by lower commodity prices and also resulted in a $370.7 million improvement in realized gains (losses) on financial derivatives.

We reported net loss of $233.4 million for 2023 compared to net income of $855.6 million for 2022. The decrease in net income for 2023 relative to 2022 is primarily a result of the $833.7 million impairment loss recorded in 2023 compared to the $267.7 million impairment reversal recorded in 2022 and a $460.9 million increase in depletion and depreciation expense as a result of the oil and gas properties acquired from Ranger. The decrease in net income was partially offset by a $329.3 million decrease in deferred income tax expense primarily related to the effects of the transaction structuring for the Merger.

Baytex Energy Corp.
2023 MD&A                                                     16

OTHER COMPREHENSIVE (LOSS) INCOME

Other comprehensive (loss) income is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation loss of $65.3 million for 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 December 31, 2023 compared to December 31, 2022 and June 20, 2023 when we completed the Merger with Ranger. The CAD/USD exchange rate was 1.3205 CAD/USD at December 31, 2023 compared to 1.32485 CAD/USD at June 20, 2023 and 1.3534 CAD/USD at December 31, 2022.

CAPITAL EXPENDITURES

Capital expenditures for the years ended December 31, 2023 and 2022 are summarized as follows.

	Years Ended December 31
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	393,127	$	492,030	$	885,157	$	321,836	$	136,746	$	458,582
Facilities	46,225		42,167		88,392		32,573		3,151		35,724
Land, seismic and other	23,846		15,392		39,238		26,393		843		27,236
Exploration and development expenditures	$	463,198	$	549,589	$	1,012,787	$	380,802	$	140,740	$	521,542
Property acquisitions	20,023		18,891		38,914		1,352		—		1,352
Proceeds from dispositions	$	(160,256)	$	—	$	(160,256)	$	(25,649)	$	—	$	(25,649)

Exploration and development expenditures were $1.0 billion for 2023 compared to $521.5 million for 2022. Exploration and development expenditures for 2023 reflect increased development activity in Canada along with development activity on the properties acquired from Ranger after the Merger closed on June 20, 2023.

In Canada, exploration and development expenditures were $463.2 million in 2023 which is $82.4 million higher than $380.8 million in 2022. Drilling and completion spending of $393.1 million in 2023 reflects higher light and heavy oil development activity relative to 2022 when we spent $321.8 million. We also invested $46.2 million on facilities, $23.8 million on land, seismic and other expenditures and completed a non-core property disposition of certain Viking assets for proceeds of $159.7 million, including closing adjustments.

Total U.S. exploration and development expenditures were $549.6 million for 2023 which is $408.8 million higher than $140.7 million for 2022. Exploration and development activity for 2023 reflects expenditures for development activity on our operated properties after closing of the Merger on June 20, 2023 along with additional activity on our non-operated properties in the Eagle Ford.

Total exploration and development expenditures of $1.0 billion for 2023 were consistent with our revised annual guidance of approximately $1.0 billion. We expect annual exploration and development expenditures of $1.2 - $1.3 billion for 2024.

CAPITAL RESOURCES AND LIQUIDITY

Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions. We strive to actively manage our capital structure in response to changes in economic conditions. At December 31, 2023, our capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.

In order to manage our capital structure and liquidity, we may from time to time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

We are committed to maintaining a strong balance sheet. Upon reaching a total debt(1) target of $1.5 billion we intend to direct 75% of free cash flow(2) to shareholder returns. At December 31, 2023, net debt(3) of $2.5 billion was $1.5 billion higher than $1.0 billion at December 31, 2022. The increase in net debt for 2023 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. 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 which was repaid in August 2023 along with 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. As of December 31, 2023 we have reduced net debt by $280.6 million since closing the Merger on June 20, 2023.

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. As of December 31, 2023, we repurchased 40.5 million common shares at an average price of $5.48 per share for total consideration of $221.9 million.

Our shareholder returns framework includes a quarterly dividend. On October 2, 2023 and January 2, 2024, we paid a quarterly cash dividend of CDN$0.0225 per share to shareholders of record. On February 28, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders on record as at March 15, 2024. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”

(1)Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.com.

(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 for further information.

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

Credit Facilities

At December 31, 2023, we had $864.7 million of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (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 Credit Facilities were increased to US$1.1 billion and mature on April 1, 2026. The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.

There are no mandatory principal payments required prior to maturity which could be extended upon our request. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the Credit Facilities was 7.6% for 2023 as compared to 3.6% for 2022. The interest rate on our Credit Facilities has increased due to an increase in the margins applicable to our Credit Facilities along with higher government benchmark rates in 2023 relative to 2022.

As at December 31, 2023, Baytex had $5.6 million of outstanding letters of credit, $4.7 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.sedarplus.com and through the U.S. Securities and Exchange Commission at www.sec.gov.

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at December 31, 2023.

Covenant Description	Position as at December 31, 2023	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.4:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	11.3:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.1:1.0	4.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2023, the Company's Senior Secured Debt totaled $864.7 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 December 31, 2023 was $2.2 billion.

(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the twelve months ended December 31, 2023 were $195.2 million.

(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, other long-term liabilities, dividends payable, share-based compensation liability, asset retirement obligations, leases, deferred income tax liabilities, and financial derivative liabilities. At December 31, 2023 our Total Debt was $2.5 billion.

Long-Term Notes

We have two issuances of long-term notes outstanding with a total principal amount of $1.6 billion as at December 31, 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 after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. At December 31, 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 transaction costs of $18.5 million incurred 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 year ended December 31, 2023, we issued 311.4 million common shares on closing of the Merger with Ranger in addition to 5.9 million common shares to settle awards outstanding in conjunction with the Merger. As at February 28, 2024, we had 821.7 million common shares issued and outstanding and no preferred shares issued and outstanding.

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 December 31, 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
Credit Facilities - principal	$	864,736	$	—	$	864,736	$	—	$	—
Long-term notes - principal	1,597,475		—		—		541,114		1,056,361
Interest on long-term notes (1)	722,732		137,138		274,276		191,515		119,803
Lease obligations - principal (2)	37,553		15,722		10,415		7,128		4,288
Processing agreements	5,642		618		1,003		563		3,458
Transportation agreements	212,400		52,691		94,866		47,601		17,242
Total	$	3,440,538	$	206,169	$	1,245,296	$	787,921	$	1,201,152

(1)Excludes interest on Credit Facilities as interest payments on Credit Facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing.

(2)Includes leases which are committed to that have not yet commenced as at December 31, 2023.

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

Baytex Energy Corp.
2023 MD&A                                                     17

FOURTH QUARTER OPERATING AND FINANCIAL RESULTS

	Three Months Ended December 31
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Total daily production
Light oil and condensate (bbl/d)	14,143		55,981		70,124		14,511		17,594		32,105
Heavy oil (bbl/d)	39,569		—		39,569		32,819		—		32,819
NGL (bbl/d)	2,937		20,223		23,160		1,958		5,703		7,661
Total liquids (bbl/d)	56,649		76,204		132,853		49,288		23,297		72,585
Natural gas (mcf/d)	48,573		116,548		165,121		45,953		39,726		85,679
Total production (boe/d)	64,744		95,629		160,373		56,946		29,918		86,864
Operating netback ($/boe)
Light oil and condensate ($/bbl) (1)	$	99.93	$	105.83	$	104.64	$	108.21	$	114.64	$	111.73
Heavy oil, net of blending and other expense ($/bbl) (2)	62.48		—		62.48		64.06		—		64.06
NGL ($/bbl) (1)	27.38		26.68		26.76		39.68		38.36		38.70
Natural gas ($/mcf) (1)	2.40		3.07		2.87		5.38		6.93		6.10
Total sales, net of blending and other per boe (2)	63.06		71.34		68.00		70.20		83.94		74.93
Royalties per boe (3)	(9.69)		(19.42)		(15.49)		(10.06)		(25.06)		(15.23)
Operating expense per boe (3)	(15.61)		(8.17)		(11.17)		(15.98)		(7.48)		(13.06)
Transportation expense per boe (3)	(3.02)		(1.33)		(2.02)		(2.83)		—		(1.85)
Operating netback per boe (2)	$	34.74	$	42.42	$	39.32	$	41.33	$	51.40	$	44.79
Financial
Petroleum and natural gas sales	$	437,889	$	627,626	$	1,065,515	$	417,952	$	231,034	$	648,986
Royalties	(57,746)		(170,824)		(228,570)		(52,718)		(68,973)		(121,691)
Revenue, net of royalties	380,143		456,802		836,945		365,234		162,061		527,295
Operating	(93,006)		(71,867)		(164,873)		(83,742)		(20,593)		(104,335)
Transportation	(18,005)		(11,739)		(29,744)		(14,817)		—		(14,817)
Blending and other	(62,296)		—		(62,296)		(50,174)		—		(50,174)
Operating netback (2)	$	206,836	$	373,196	$	580,032	$	216,501	$	141,468	$	357,969
General and administrative	—		—		(22,280)		—		—		(14,945)
Cash interest	—		—		(56,698)		—		—		(19,711)
Realized financial derivatives gain (loss)	—		—		12,377		—		—		(49,665)
Other	—		—		(11,283)		—		—		(18,096)
Adjusted funds flow (4)	$	206,836	$	373,196	$	502,148	$	216,501	$	141,468	$	255,552
Net (loss) income	$	(255,238)	$	(531,505)	$	(625,830)	$	366,104	$	88,480	$	352,807
Exploration and development expenditures	$	75,137	$	124,077	$	199,214	$	85,641	$	17,993	$	103,634
Property acquisitions	15,032		18,891		33,923		1,085		—		1,085
Proceeds from dispositions	$	(159,745)	$	—	$	(159,745)	$	(148)	$	—	$	(148)
Net debt (4)					$	2,534,287					987,446

(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.

(3)Calculated as royalties expense, operating expense or transportation expense divided by barrels of oil equivalent production volume for the applicable period.

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

Baytex Energy Corp.
2023 MD&A                                                     18

	Three Months Ended December 31
	2023	2022	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	78.32	82.64	(4.32)
MEH oil (US$/bbl) (2)	80.62	85.88	(5.26)
MEH oil differential to WTI (US$/bbl)	2.30	3.24	(0.94)
Edmonton par oil ($/bbl) (3)	99.72	109.57	(9.85)
Edmonton par oil differential to WTI (US$/bbl)	(5.10)	(1.94)	(3.16)
WCS heavy oil ($/bbl) (4)	76.86	77.37	(0.51)
WCS heavy oil differential to WTI (US$/bbl)	(21.88)	(25.65)	3.77
AECO natural gas price ($/mcf) (5)	2.66	5.58	(2.92)
NYMEX natural gas price (US$/mmbtu) (6)	2.88	6.26	(3.38)
CAD/USD average exchange rate	1.3619	1.3577	0.0042

(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.

Our operating and financial results for Q4/2023 reflect the successful execution of our 2023 development programs in the U.S. and Canada. We invested $199.2 million on exploration and development expenditures in Q4/2023 and delivered production of 160,373 boe/d. Free cash flow(1) was $290.8 million in Q4/2023 which reflects the disciplined execution of our development programs.

In Canada, production averaged 64,744 boe/d in Q4/2023 which was 7,798 boe/d higher than 56,946 boe/d reported for Q4/2022 as a result of our successful Clearwater development program at Peavine and our light oil Duvernay development. Lower benchmark pricing resulted in a realized price of $63.06/boe for Q4/2023 which was $7.14/boe lower than $70.20/boe for Q4/2022. The Edmonton Par benchmark averaged $99.72/bbl for Q4/2023 compared to $109.57/bbl for Q4/2022 and the WCS heavy oil benchmark was $76.86/bbl in Q4/2023 compared to $77.37/bbl for the same period of 2022. Lower commodity prices were the main factor that resulted in an operating netback(1) of $206.8 million ($34.74/boe) for Q4/2023 which was $9.7 million ($6.60/boe) lower than $216.5 million ($41.33/boe) reported for Q4/2022. Exploration and development expenditures were $75.1 million in Q4/2023 compared to $85.6 million in Q4/2022.

In the U.S., production averaged 95,629 boe/d for Q4/2023 which is 65,711 boe/d higher than 29,918 boe/d reported for Q4/2022 reflecting the production contribution from the Merger with Ranger. The MEH benchmark averaged US$80.62/bbl in Q4/2023 which was US$5.26/boe lower than US$85.88/bbl during Q4/2022 and resulted in a realized price of $71.34/boe which was $12.60/boe lower than our realized price of $83.94/boe in Q4/2022. Operating netback of $373.2 million ($42.42/boe) was $231.7 million ($8.98/boe) higher than $141.5 million ($51.40/boe) for Q4/2022 which reflects lower benchmark commodity prices and the additional production following the acquisition of operated Eagle Ford properties as part of the Merger. Activity on the acquired lands resulted in exploration and development expenditures of $124.1 million in Q4/2023 which were higher compared to Q4/2022 when we spent $18.0 million.

(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.

Baytex Energy Corp.
2023 MD&A                                                     19

We generated adjusted funds flow(1) of $502.1 million in Q4/2023 which is $246.6 million higher than $255.6 million in Q4/2022. The increase in adjusted funds flow for Q4/2023 reflects higher production after the acquisition of operated Eagle Ford properties as part of the Merger with Ranger along with lower commodity prices relative to Q4/2022. The production contribution from the properties acquired from Ranger was the primary factor for the increase in production of 160,373 boe/d in Q4/2023 compared to 86,864 boe/d for Q4/2022. Higher production resulted in an operating netback(2) of $580.0 million for Q4/2023 which was $222.1 million higher than the same period of 2022 despite lower commodity prices that resulted in operating netback(2) of $39.32/boe for Q4/2023 which was $5.47/boe lower than $44.79/boe in Q4/2022. We recorded realized financial derivatives gains of $12.4 million in Q4/2023 compared to losses of $49.7 million in Q4/2022. G&A expense of $22.3 million in Q4/2023 was higher than $14.9 million in Q4/2022 due to additional administrative costs and staff retention required for the operation of the properties acquired from Ranger. Interest expense of $56.7 million in Q4/2023 was $37.0 million higher than $19.7 million for Q4/2022 which reflects the additional debt outstanding as a result of the Merger with Ranger in addition to an increase in interest rates during 2023. Net debt(1) was $2.5 billion at Q4/2023 compared to $1.0 billion in Q4/2022.

We recorded a net loss of $625.8 million in Q4/2023 compared to net income of $352.8 million in Q4/2022. The decrease in net income for Q4/2023 relative to Q4/2022 is primarily a result of the $833.7 million impairment loss recorded in Q4/2023 due to changes in reserves volumes and the loss on a disposition within the Viking CGU, compared to $267.7 million of impairment reversals recorded in Q4/2022, as well as an increase in depletion and depreciation expense as a result of the oil and gas properties acquired from Ranger.

(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.
2023 MD&A                                                     20

QUARTERLY FINANCIAL INFORMATION

	2023				2022
($ thousands, except per common share amounts)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Petroleum and natural gas sales	1,065,515	1,163,010	598,760	555,336	648,986	712,065	854,169	673,825
Net (loss) income	(625,830)	127,430	213,603	51,441	352,807	264,968	180,972	56,858
Per common share - basic	(0.75)	0.15	0.37	0.09	0.65	0.48	0.32	0.10
Per common share - diluted	(0.75)	0.15	0.36	0.09	0.64	0.47	0.32	0.10
Adjusted funds flow (1)	502,148	581,623	273,590	236,989	255,552	284,288	345,704	279,607
Per common share - basic	0.60	0.68	0.47	0.43	0.47	0.51	0.61	0.49
Per common share - diluted	0.60	0.68	0.47	0.43	0.46	0.51	0.60	0.49
Free cash flow (2)	290,785	158,440	96,313	(1,918)	143,324	111,568	245,316	121,318
Per common share - basic	0.35	0.19	0.17	—	0.26	0.20	0.43	0.21
Per common share - diluted	0.35	0.18	0.16	—	0.26	0.20	0.43	0.21
Cash flows from operating activities	474,452	444,033	192,308	184,938	303,441	310,423	360,034	198,974
Per common share - basic	0.57	0.52	0.33	0.34	0.56	0.56	0.63	0.35
Per common share - diluted	0.57	0.52	0.33	0.34	0.55	0.56	0.63	0.35
Dividends declared	18,381	19,138	—	—	—	—	—	—
Per common share – basic	0.02	0.02	—	—	—	—	—	—
Per common share – diluted	0.02	0.02	—	—	—	—	—	—
Exploration and development expenditures	199,214	409,191	170,704	233,626	103,634	167,453	96,633	153,822
Canada	75,137	107,053	96,403	184,606	85,641	117,150	51,881	126,130
U.S.	124,077	302,138	74,301	49,020	17,993	50,303	44,752	27,692
Property acquisitions	33,923	4,277	(62)	506	1,085	—	208	59
Proceeds from dispositions	(159,745)	(226)	(50)	(235)	(148)	(25,460)	(14)	(27)
Net debt (1)	2,534,287	2,824,348	2,814,844	995,170	987,446	1,113,559	1,123,297	1,275,680
Total assets (3)	7,460,931	8,946,181	8,617,444	5,180,059	5,103,769	4,923,617	4,870,432	4,917,811
Common shares outstanding	821,681	845,360	862,192	545,553	544,930	547,615	560,139	569,214
Daily production
Total production (boe/d)	160,373	150,600	89,761	86,760	86,864	83,194	83,090	80,867
Canada (boe/d)	64,744	63,289	55,874	60,651	56,946	55,803	54,919	53,385
U.S. (boe/d)	95,629	87,311	33,887	26,109	29,918	27,391	28,170	27,482
Benchmark prices
WTI oil (US$/bbl)	78.32	82.26	73.78	76.13	82.64	91.56	108.41	94.29
WCS heavy ($/bbl)	76.86	93.02	78.85	69.44	77.37	93.62	122.05	100.99
Edmonton Light ($/bbl)	99.72	107.93	95.13	99.04	109.57	116.79	137.79	115.66
CAD/USD avg exchange rate	1.3619	1.3410	1.3431	1.3520	1.3577	1.3059	1.2766	1.2661
AECO gas ($/mcf)	2.66	2.39	2.35	4.34	5.58	5.81	6.27	4.59
NYMEX gas (US$/mmbtu)	2.88	2.55	2.10	3.42	6.26	8.20	7.17	4.95
Total sales, net of blending and other expense ($/boe) (2)	68.00	80.34	66.82	63.48	74.93	87.68	105.44	86.89
Royalties ($/boe) (4)	(15.49)	(17.33)	(13.21)	(11.94)	(15.23)	(19.21)	(22.69)	(16.86)
Operating expense ($/boe) (4)	(11.17)	(12.57)	(14.62)	(14.40)	(13.06)	(14.39)	(14.21)	(13.85)
Transportation expense ($/boe) (4)	(2.02)	(2.02)	(1.78)	(2.18)	(1.85)	(1.67)	(1.56)	(1.27)
Operating netback ($/boe) (2)	39.32	48.42	37.21	34.96	44.79	52.41	66.98	54.91
Financial derivatives gain (loss) ($/boe) (4)	0.84	0.15	2.00	0.69	(6.21)	(9.98)	(16.41)	(11.59)
Operating netback after financial derivatives ($/boe) (2)	40.16	48.57	39.21	35.65	38.58	42.43	50.57	43.32

(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 expenses, transportation expense or financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp.
2023 MD&A                                                     21

Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have fluctuated. Production steadily increased from 80,867 boe/d in Q1/2022 to 160,373 boe/d in Q4/2023 which reflects strong well performance from our development programs in Canada and the U.S. 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. The impact of increased commodity prices is reflected in our realized price of $105.44/boe for Q2/2022 which is our strongest realized pricing in the most recent eight quarters. Our Q4/2023 realized price of $68.00/boe reflects recent declines in crude oil prices as global supply growth has resulted in a more balanced market.

Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow(1) of $502.1 million for Q4/2023 reflects strong production results from our development plans in the U.S. and Canada in addition to the Merger partially offset by declining price realizations.

Net debt can fluctuate depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. The increase in net debt(1) from $1.3 billion at Q1/2022 to $2.5 billion at Q4/2023 is primarily a result of the Merger which closed in Q2/2023 along with $418.4 million of shareholder returns. Since closing the Merger in Q2/2023 we have reduced net debt by $280.6 million which demonstrates our priority to maintain a strong balance sheet. The change in net debt also reflects free cash flow(2) of $1.2 billion generated over the last eight quarters.

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

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

ENVIRONMENTAL REGULATIONS

As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the Risk Factors section of this MD&A 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 this MD&A, 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 developments 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 December 31, 2023, nor are any such arrangements outstanding as of the date of this MD&A.

Baytex Energy Corp.
2023 MD&A                                                     22

CRITICAL ACCOUNTING ESTIMATES

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined with certainty. Revisions to estimates are recognized prospectively. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.

Reserves

The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the determination of recoverable value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent qualified reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL reserves and the related cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook.

Estimates of economically recoverable oil, natural gas and NGL reserves and the related cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes, capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in the Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred income tax assets and in the determination of recoverable value estimates for non-financial assets.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition of a business in accordance with IFRS. The determination of the fair value assigned to assets acquired and liabilities assumed requires management to make assumptions and estimates. These assumptions or estimates used in determining the fair value of assets acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill. The determination of the acquisition-date fair value measurement of oil and gas properties acquired represents the largest fair value estimate which is derived from the present value of expected cash flows associated with estimated acquired proved and probable oil and gas reserves prepared by an independent qualified reserve evaluator using assumptions as outlined under "reserves", on an after-tax basis and applying a discount rate. Assumptions used to arrive at the fair value of oil and gas properties are further verified by way of market comparisons and third party sources.

Cash-generating Units

The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.

Identification of Impairment and Impairment Reversal Indicators

Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. These indicators can be internal such as changes in estimated proved and probable oil and gas reserves ("CGU reserves") and internally estimated oil and gas resources, or external such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.

Measurement of Recoverable Amount

If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved and probable oil and gas reserves and the discount rate used to present value future cash flows. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.

Baytex Energy Corp.
2023 MD&A                                                     23

Asset Retirement Obligations

The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the facilities, the estimated time period during which these costs will be incurred in the future, and risk-free discount rates and inflation rates. The Company uses risk-free discount rates. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements.

Income Taxes

Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes.

SPECIFIED FINANCIAL MEASURES

In this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of blending and other expense, heavy oil sales, net of blending and other expense, and average royalty rate) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This MD&A also contains the terms "adjusted funds flow" and "net debt" which are capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.

Non-GAAP Financial Measures

Total sales, net of blending and other expense and heavy oil, net of blending and other expense

Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated as heavy oil sales less blending and other expense. We believe including the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.

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

	Three Months Ended						Years Ended December 31
($ thousands)	December 31, 2023		September 30, 2023		December 31, 2022		2023		2022
Petroleum and natural gas sales	$	1,065,515	$	1,163,010	$	648,986	$	3,382,621	$	2,889,045
Light oil and condensate (1)	(675,072)		(756,779)		(330,016)		(2,029,123)		(1,470,549)
NGL (1)	(57,027)		(46,972)		(27,276)		(145,997)		(120,505)
Natural gas sales (1)	(43,674)		(35,987)		(48,116)		(125,952)		(195,915)
Heavy oil sales	$	289,742	$	323,272	$	243,578	$	1,081,549	$	1,102,076
Blending and other expense - heavy oil (2)	(62,296)		(49,830)		(50,174)		(224,802)		(189,454)
Heavy oil, net of blending and other expense	$	227,446	$	273,442	$	193,404	$	856,747	$	912,622

(1)Component of petroleum and natural gas sales; see Note 14 Petroleum and Natural Gas Sales in the Consolidated Financial Statements for the year ended December 31, 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.

Baytex Energy Corp.
2023 MD&A                                                     24

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

	Three Months Ended						Years Ended December 31
($ thousands)	December 31, 2023		September 30, 2023		December 31, 2022		2023		2022
Petroleum and natural gas sales	$	1,065,515	$	1,163,010	$	648,986	$	3,382,621	$	2,889,045
Blending and other expense	(62,296)		(49,830)		(50,174)		(224,802)		(189,454)
Total sales, net of blending and other expense	$	1,003,219	$	1,113,180	$	598,812	$	3,157,819	$	2,699,591
Royalties	(228,570)		(240,049)		(121,691)		(669,792)		(562,964)
Operating expense	(164,873)		(174,119)		(104,335)		(570,839)		(422,666)
Transportation expense	(29,744)		(27,983)		(14,817)		(89,306)		(48,561)
Operating netback	$	580,032	$	671,029	$	357,969	$	1,827,882	$	1,665,400
Realized financial derivatives gain (loss) (1)	12,377		2,055		(49,665)		36,212		(334,481)
Operating netback after realized financial derivatives	$	592,409	$	673,084	$	308,304	$	1,864,094	$	1,330,919

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss; see Note 18 Financial Instruments and Risk Management in the Consolidated Financial Statements for the year ended December 31, 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, transaction costs, and cash premiums on derivatives.

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

	Three Months Ended						Years Ended December 31
($ thousands)	December 31, 2023		September 30, 2023		December 31, 2022		2023		2022
Cash flow from operating activities	$	474,452	$	444,033	$	303,441	$	1,295,731	$	1,172,872
Change in non-cash working capital	14,971		126,075		(55,632)		220,895		$	(26,072)
Transaction costs	5,079		2,263		—		49,045		—
Additions to exploration and evaluation assets	1,271		(40)		(462)		—		(6,359)
Additions to oil and gas properties	(200,537)		(409,151)		(103,172)		(1,012,787)		(515,183)
Payments on lease obligations	(4,451)		(4,740)		(851)		(11,527)		(3,732)
Cash premiums on derivatives	—		—		—		2,263		—
Free cash flow	$	290,785	$	158,440	$	143,324	$	543,620	$	621,526

As a result of changes in commodity prices, development plans and capital costs, higher interest rates and debt outstanding, along with the Viking disposition, we no longer expect to generate $1 billion of free cash flow for the period from July 1, 2023 to June 30, 2024, as stated in our press release dated June 20, 2023. We are no longer providing an estimate of our free cash flow for the aforementioned period. Please see our press release dated February 28, 2024 available on SEDAR+ at www.sedarplus.com for our current expectations regarding free cash flow for full year 2024.

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.

Baytex Energy Corp.
2023 MD&A                                                     25

Total sales, net of blending and other expense per boe

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

Average royalty rate

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

Operating netback per boe

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

Capital Management Measures

Net debt

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

The following table summarizes our calculation of net debt.

	As at
($ thousands)	December 31, 2023		September 30, 2023		December 31, 2022
Credit Facilities	$	848,749	$	1,028,867	$	383,031
Unamortized debt issuance costs - Credit Facilities (1)	15,987		17,889		2,363
Long-term notes	1,562,361		1,600,397		547,598
Unamortized debt issuance costs - Long-term notes (1)	35,114		37,243		6,999
Trade payables	477,295		685,392		227,332
Share-based compensation liability	35,732		—		54,072
Dividends payable	18,381		19,138		—
Other long-term liabilities	19,147		—		—
Cash	(55,815)		(23,899)		(5,464)
Trade receivables	(339,405)		(540,679)		(222,108)
Prepaids and other assets	(83,259)		—		(6,377)
Net debt	$	2,534,287	$	2,824,348	$	987,446

(1)Unamortized debt issuance costs were obtained from Note 8 Credit Facilities and Note 9 Long-term Notes from the Consolidated Financial Statements for the year ended December 31, 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 the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirements obligations settled during the applicable period, transaction costs and cash premiums on derivatives.

Baytex Energy Corp.
2023 MD&A                                                     26

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

	Three Months Ended						Years Ended December 31
($ thousands)	December 31, 2023		September 30, 2023		December 31, 2022		2023		2022
Cash flows from operating activities	$	474,452	$	444,033	$	303,441	$	1,295,731	$	1,172,872
Change in non-cash working capital	14,971		126,075		(55,632)		220,895		(26,072)
Asset retirement obligations settled	7,646		9,252		7,743		26,416		18,351
Transaction costs	5,079		2,263		—		49,045		—
Cash premiums on derivatives	—		—		—		2,263		—
Adjusted funds flow	$	502,148	$	581,623	$	255,552	$	1,594,350	$	1,165,151

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of December 31, 2023, an evaluation was conducted to determine the effectiveness of our “disclosure controls and procedures” (as defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) and in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109")) under the supervision of and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer of Baytex (collectively the "certifying officers"). Based on that evaluation, the certifying officers concluded that our disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that we file or submit under the Exchange Act or under Canadian securities legislation is (i) recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and communicated to our management, including the certifying officers, to allow timely decisions regarding the required disclosure.

It should be noted that while the certifying officers believe that our disclosure control and procedures provide a reasonable level of assurance that they are effective, they do not expect that our disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met.

Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting. Internal control over our financial reporting is a process designed under the supervision of and with the participation of management, including the certifying officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

Management has assessed the effectiveness of our "internal control over financial reporting" as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act and as defined by NI 52-109. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that our internal control over financial reporting was effective as of December 31, 2023. As permitted by applicable securities laws in Canada and the U.S., management excluded from its design and assessment the internal control over financial reporting for Ranger Oil Corporation ("Ranger"), which was acquired on June 20, 2023. The consolidated financial statements as at and for the year ended December 31, 2023 include $3.5 billion of total assets and $691.9 million of revenues, net of royalties from the acquired entity.

The effectiveness of our internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm.

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Changes in Internal Control over Financial Reporting

Management excluded from its design and assessment the internal control over financial reporting for Ranger Oil Corporation ("Ranger") (as permitted by applicable securities laws in Canada and the U.S.), which was acquired on June 20, 2023. Other than Ranger, there has been no change in the Baytex's internal control over financial reporting that occurred during the year ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

In accordance with the provision of NI 52-109 and consistent with the SEC guidance, the scope of the evaluation did not include internal controls over financial reporting of Ranger. 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.

In 2023, the assets previously held by Ranger contributed revenues of $939.4 million (representing 28% of total revenues) and net income before tax of $165.1 million. At December 31, 2023, current assets of $220.3 million, non-current assets of $3.3 billion, current liabilities of $250.8 million  and non-current liabilities of $97.7 million were associated with the acquired entity.

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SELECTED ANNUAL INFORMATION

The following table summarizes key annual financial and operating information over the three most recently completed financial years.

($ thousands, except per common share amounts)	2023		2022		2021
Revenues, net of royalties	$	2,712,829	$	2,326,081	$	1,529,039
Adjusted funds flow (1)	$	1,594,350	$	1,165,151	$	745,628
Per common share - basic	$	2.26	$	2.09	$	1.32
Per common share - diluted	$	2.26	$	2.07	$	1.30
Net (loss) income	$	(233,356)	$	855,605	$	1,613,600
Per common share - basic	$	(0.33)	$	1.53	$	2.86
Per common share - diluted	$	(0.33)	$	1.52	$	2.82
Total assets	$	7,460,931	$	5,103,769	$	4,834,643
Credit facilities - principal	$	864,736	$	385,394	$	506,514
Long-term notes - principal	$	1,597,475	$	554,597	$	885,920
Total sales, net of blending and other expense ($/boe) (2)	$	70.82	$	88.56	$	60.93
Total production (boe/d)	122,154		83,519		80,156

(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.

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FORWARD-LOOKING STATEMENTS

In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to but not limited to: expectation that we can effectively allocate capital across our assets; our intentions of allocating our annual free cash flow to shareholder returns through share buybacks, dividends and debt reduction; that production growth will be driven by our Canadian assets; our commitment to reduce our inactive wellbore count; for 2023, our capital budget, expected average daily production, expected royalty rate and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; that we intend to settle outstanding share based compensation awards in cash; the expected time to resolve the reassessment of our tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions; that we may issue or repurchase debt or equity securities from time to time or sell assets; our intent to fund certain financial obligations with cash flow from operations and the expected timing of the financial obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

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

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control.These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2023, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission not later than March 31, 2024 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.

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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.

RISK FACTORS

We are focused on long-term strategic planning and have identified key risks, uncertainties and opportunities associated with our business that can impact the financial and operational results. Listed below is a description of these risks and uncertainties.

Risks Relating to Our Business and Operations

Crude oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on our business, results of operations, or cash flows and financial condition

Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Low prices for crude oil and natural gas produced by us could have a material adverse effect on our operations, financial condition and the value and amount of our reserves.

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, OPEC+, the condition of the Canadian, United States, European and Asian economies, the impacts of geopolitical events, including the Russian Ukrainian war and conflicts in the Middle East, or other adverse economic or political development in the United States, Europe, or Asia, the impact of pandemics/epidemics, government regulation, the supply of crude oil in North America and internationally, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Additionally, the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Natural gas prices realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas. All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium crude oil and heavy crude oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions, refining demand, storage capacity, the availability and cost of diluents used to blend and transport product and the quality of the oil produced, all of which are beyond our control. In addition, there is not sufficient pipeline capacity for Canadian crude oil to access the American refinery complex or tidewater to access world markets and the availability of additional transport capacity via rail is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery outages, which contributes to this volatility.

There is also a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being produced in the U.S. If light sweet crude oil production remains at current levels or continues to increase, demand for the light crude oil production from our U.S. operations could result in widening price discounts to the world crude prices.

Decreases to or prolonged periods of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of currently producing wells without an equivalent decrease in expenses due to fixed costs, a delay or cancellation of existing or future drilling, development or construction programs, un-utilized long-term transportation commitments and a reduction in the value and amount of our reserves.

We conduct assessments of the carrying value of our assets in accordance with IFRS. If crude oil and natural gas forecast prices change, the carrying value of our assets could be subject to revision and our net earnings could be adversely affected.

Our success is highly dependent on our ability to develop existing properties and add to our oil and natural gas reserves

Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced. As a result, our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future oil and natural gas exploration may involve unprofitable efforts, not only from unsuccessful wells, but also from wells that are

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productive but do not produce sufficient hydrocarbons to return a profit. Completion of a well does not assure a profit on the investment. Drilling hazards or environmental liabilities or damages and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays or failure in obtaining governmental, landowner or other stakeholder approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow from operating activities to varying degrees.

There is no assurance we will be successful in developing our reserves or acquiring additional reserves at acceptable costs. Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserve life of our properties will decline, which may adversely affect our business, financial condition, results of operations and prospects.

The anticipated benefits of acquisitions may not be achieved and the Company may dispose of non-core assets for less than their carrying value on the financial statements

Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Additionally, significant acquisitions can change the nature of our operations and business if acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Management continually assesses the value and contribution of our assets. In this regard, non‑core assets may be periodically disposed of so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Company, if disposed of, may realize less on disposition than their carrying value on the financial statements of the Company.

Availability and cost of capital or borrowing to maintain and/or fund future development and acquisitions

The business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital (including, but not limited to, debt and equity financing) become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired.

Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and, in particular, interest in our securities along with our ability to maintain ourcredit ratings. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to our credit rating agencies, or should our business prospects deteriorate, our credit ratings could be downgraded. Additionally, from time to time, our securities may not meet the investment criteria or characteristics of a particular institutional or other investor, including institutional investors who are not willing or able to hold securities of oil and gas companies for reasons unrelated to financial or operational performance. This may include changes to market-based factors or investor strategies, including ESG, or responsible investing criteria/rankings (for example, ESG, social impact or environmental scores), the implementation of new financial market regulations and fossil fuel divestment initiatives undertaken by governments, pension funds and/or other institutional investors. These events would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing, and may increase our borrowing costs.

From time to time we may enter into transactions which may be financed in whole or in part with debt or equity. The level of our indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise. Additionally, from time to time, we may issue securities from treasury in order to reduce debt, complete acquisitions and/or optimize our capital structure.

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Restrictions and/or costs associated with regulatory initiatives to combat climate change and the physical risks of climate change may have a material adverse affect on our business

Regulatory and Policy Initiatives

Our exploration and production facilities and other operational activities emit GHGs. As such, GHG emissions regulation (including carbon taxes) enacted in jurisdictions where we operate will impact us. In addition, certain of our assets have a higher GHG emissions intensity than others and may be disproportionately impacted.

Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating costs, additional taxes, increased construction and development costs, additional monitoring and compliance costs, a requirement to redesign or retrofit current facilities, permitting delays, additional costs associated with the purchase of emission credits or allowances and reduced demand for crude oil. Additionally, if GHG emissions regulation differs by region or type of production, all or part of our production could be subject to costs which are disproportionately higher than those of other producers.

The direct or indirect costs of compliance with GHG emissions regulation may have a material adverse affect on our business, financial condition, results of operations and prospects. At this time, it is not possible to predict whether compliance costs will have a material adverse affect on our financial condition, results of operations or prospects.

Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds.

Physical Risk

Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rain fall, hurricanes, drought and wildfires may restrict our ability to access our properties, cause operational difficulties including damage to machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain assets are located where they are exposed to forest fires, floods, heavy rains, hurricanes, drought and other extreme weather conditions which can lead to significant downtime, damage to such assets and/or increased costs of construction and maintenance. Moreover, extreme weather conditions may lead to disruptions in our ability to transport produced oil and natural gas as well as goods and services in our supply chain.

An energy transition that lessens demand for petroleum products may have an adverse affect on our business

A transition away from the use of petroleum products, which may include conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy, could reduce demand for oil and natural gas. Certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and gas products. The Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company's business and financial condition by decreasing its cash flow from operating activities and the value of its assets.

The amount of oil and natural gas that we can produce and sell is subject to the availability and cost of gathering, processing and pipeline systems

We deliver our products through gathering, processing and pipeline systems to which we do not own and purchasers of our products rely on third party infrastructure to deliver our products to market. The lack of access to capacity in any of the gathering, processing and pipeline systems could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Alternately, a substantial decrease in the use of such systems can increase the cost we incur to use them. In addition, many of the pipeline systems that we use are controlled by a single company and rates are set through a regulatory process, as a result we are subject to the outcome of those regulatory processes. Any significant change in market factors, regulatory decisions or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition.

Our operations in the United States are concentrated in the Eagle Ford shale of South Texas and as a result are highly exposed to the gulf coast refining complex and events which negatively impact the functioning of infrastructure in that area which could harm our business and, in turn, our financial condition. Such events include adverse weather conditions, terrorism, local market changes, government regulation and taxation which may result in limitations on the U.S.' ability to export crude oil.

Access to the pipeline capacity for the export of crude oil from Canada has, at times, been inadequate for the amount of Canadian production being exported. This has resulted in significantly lower prices being realized by Canadian producers compared with the WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas from Canada. There can be no certainty that current investment in pipelines will provide sufficient long-term take-away capacity or that currently operating systems will remain in service. There is also no certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption and/or increased supply of crude oil, will not occur.

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There is no certainty that crude-by-rail transportation and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on pipeline systems. In addition, our crude-by-rail shipments may be impacted by service delays, inclement weather, derailment or blockades and could adversely impact our crude oil sales volumes or the price received for our product. Crude oil produced and sold by us may be involved in a derailment or incident that results in legal liability or reputational harm.

A portion of our production may be processed through facilities controlled by third parties. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the same for sale.

Failure to retain or replace our leadership and key personnel may have an adverse affect on our business

Our success is dependent upon our management, our leadership capabilities and the quality and competency of our talent. Contributions of the existing management team to the immediate and near-term operations of the Company are likely to be of central importance. In addition, certain of the Company's current employees may have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our financial condition, results of operations and prospects.

Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders

Income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely affects our financial condition, results of operations and prospects.

In addition, tax authorities having jurisdiction over us or our Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of our Shareholders. We file all required income tax returns and believe that we are in full compliance with the applicable tax legislation. However, such returns are subject to audit and reassessment by the applicable taxation authority. At present, the Canadian tax authorities have reassessed the returns of certain of our subsidiaries. Any such reassessment may have an impact on current and future taxes payable. We believe appropriate provisions for current and deferred income taxes have been made in our Financial Statements; however, it is difficult to predict the outcome of audit findings by tax authorities. These findings may increase the amount of our tax liabilities and adversely affect our business, financial condition and results of operations.

We may participate in larger projects and may have more concentrated risk in certain areas of our operations

We have a variety of exploration, development and construction projects underway at any given time. Project delays may result in delayed revenue receipts and cost overruns may result in projects being uneconomic. Our ability to complete projects is dependent on general business, community relationships and market conditions as well as other factors beyond our control, including the availability of skilled labour and manpower, the availability and proximity of pipeline capacity and rail terminals, weather, environmental and regulatory matters, ability to access lands, availability of drilling and other equipment and supplies, and availability of processing capacity.

We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing

We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the frequency of operational shut-ins and unintentional communication with other adjacent wells and reduce the total recoverable reserves from the reservoir.

Our financial performance is significantly affected by the cost of developing and operating our assets

Our development and operating costs are affected by a number of factors including, but not limited to: price inflation, access to skilled and unskilled labour, availability of equipment, scheduling delays, trucking and fuel costs, failure to maintain quality construction standards, the cost of new technologies and supply chain disruptions. Labour costs, natural gas, electricity, water, diluent and chemicals are examples of some of the operating and other costs that are susceptible to significant fluctuation. Increases to development and operating costs could have a material adverse effect on our financial condition, results of operations or prospects.

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Current or future controls, legislation or regulations applicable to the oil and gas industry could adversely affect us

Operations

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government. All such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse. The exercise of discretion by governmental authorities under existing controls, legislation or regulations, the implementation of new controls, legislation or regulations or the modification of existing controls, legislation or regulations affecting the oil and gas industry could reduce demand for crude oil and natural gas, increase our costs, or delay or restrict our operations, all of which would have a material adverse effect on our financial condition, results of operations or prospects.

Environment

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, provincial and local laws and regulations. Environmental legislation provides for, among other things, the initiation and approval of new oil and natural gas projects, and restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. New environmental legislation at the federal, state, and provincial levels may increase uncertainty among oil and natural gas industry participants as the new laws are implemented, and the effects of the new rules and standards are felt in the oil and natural gas industry.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liabilities and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.

The Company may have to pay certain costs associated with abandonment and reclamation

The Company will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Company's approvals and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation costs are substantial. The Company records a provision for abandonment and reclamation costs in its financial statements, this provision requires significant judgement and reflects the Company's best estimate of the costs to complete the required abandonment and reclamation work. Actual results may be significantly different than the estimated amounts.

Foreign Investment and Competition Act Legislation

In addition to regulatory requirements mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada) and the Hart-Scott-Rodino Antitrust Improvements Act in the United States.

Water use restrictions and/or limited access to water or other fluids may impact the Company's ability to fracture its wells or carry out waterflood operations

The Company undertakes or intends to undertake certain hydraulic fracturing, SAGD, CSS and waterflooding programs. To undertake such operations the Company needs to have access to sufficient volumes of water, or other liquids. There is no certainty that the Company will have access to the required volumes of water. In addition, in certain areas there may be restrictions on water use for activities such as hydraulic fracturing, SAGD, CSS and waterflooding. If the Company is unable to access such water it may not be able to undertake hydraulic fracturing, SAGD, CSS or waterflooding activities, which may reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

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Public perception and its influence on the regulatory regime

Concern over the impact of oil and gas development on the environment and climate change has received considerable attention in the media and recent public commentary, and the social value proposition of resource development is being challenged. Additionally, certain pipeline leaks, rail car derailments, major weather events and induced seismicity events have gained media, environmental and other stakeholder attention. Future laws and regulation may be impacted by such incidents, which could have a material adverse effect on our financial condition, results of operations or prospects.

New regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Hydraulic fracturing has featured prominently in recent political, media and activist commentary on the subject of water usage, induced seismicity events and environmental damage. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Company's costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Regulations regarding the disposal of fluids used in the Company's operations may increase its costs of compliance or subject it to regulatory penalties or litigation

The safe disposal of hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal, provincial and state governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Company's costs of compliance.

Our economic hedging activities may negatively impact our income and our financial condition

In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial instruments and physical sales contracts to manage our exposure under a derivative program. The terms of these arrangements may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production, and for certain assets will result in us paying royalties at a reference price which is higher than the hedged price. We may also suffer financial loss due to derivative arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also increased exposure to counterparty credit risk. To the extent that our current derivative agreements are beneficial to us, these benefits will only be realized for the period and for the commodity quantities in those contracts. In addition, there is no certainty that we will be able to obtain additional economic hedges at prices that have an equivalent benefit to us, which may adversely impact our revenues in future periods.

Variations in interest rates and foreign exchange rates could adversely affect our financial condition

There is a risk that interest rates will continue to increase. An increase in interest rates could result in a significant increase in the amount we pay to service debt and could have an adverse effect on our financial condition, results of operations and prospects.

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our revenues. A substantial portion of our operations and production are in the United States and, as such, we are exposed to foreign currency risk on both revenues and costs to the extent the value of the Canadian dollar decreases relative to the U.S. dollar. In addition, we are exposed to foreign currency risk as a large portion of our indebtedness is denominated in U.S. dollars and the interest payable thereon is payable in U.S. dollars. Future Canada/U.S. foreign exchange rates could also impact the future value of our reserves as determined by our independent evaluator.

A decline in the value of the Canadian dollar relative to the United States dollar provides a competitive advantage to United States companies acquiring Canadian oil and gas properties and may make it more difficult for us to replace reserves through acquisitions.

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There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves, including many factors beyond our control

The reserves estimates are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies, historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of which may vary considerably from actual results.

All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our reserves as at December 31, 2023 are estimated using forecast prices and costs. If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the estimated price assumptions, the present value of estimated future net revenues for our reserves and net asset value would be reduced and the reduction could be significant. Our actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material.

Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves and such variances could be material.

Acquiring, developing and exploring for oil and natural gas involves many physical hazards. We have not insured and cannot fully insure against all risks related to our operations

Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to: encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, fires, explosions, equipment failures and other accidents, gaseous leaks, uncontrollable or unauthorized flows of crude oil, natural gas or well fluids, migration of harmful substances, oil spills, corrosion, adverse weather conditions, pollution, acts of vandalism, theft and terrorism and other adverse risks to the environment.

Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect on our business, financial condition, results of operations and prospects.

We are not the operator of a significant portion of our drilling locations in the Eagle Ford and, therefore, we will not be able to control the timing of development, associated costs or the rate of production of that acreage

Marathon Oil is the operator of a significant portion of our Eagle Ford acreage which is located in the Karnes and Atascosa counties and we are reliant upon Marathon Oil to operate successfully. Marathon Oil will make decisions based on its own best interest and the collective best interest of all of the working interest owners of this acreage, which may not be in our best interest. We have a limited ability to exercise influence over the operational decisions of Marathon Oil, including the setting of capital expenditure budgets and determination of drilling locations and schedules. The success and timing of development activities, operated by Marathon Oil, will depend on a number of factors that will largely be outside of our control, including the timing and amount of capital expenditures, Marathon Oil's expertise and financial resources, approval of other participants in drilling wells, selection of technology, and the rate of production of reserves.

To the extent that the capital expenditure requirements related to our Eagle Ford acreage exceeds our budgeted amounts, it may reduce the amount of capital we have available to invest in our other assets. We have the ability to elect whether or not to participate in well locations proposed by Marathon Oil on an individual basis. If we elect to not participate in a well location, we forgo any revenue from such well until Marathon Oil has recouped, from our working interest share of production from such well, 300% to 500% of our working interest share of the cost of such well.

Our thermal heavy oil projects face additional risks compared to conventional oil and gas production

Our thermal heavy oil projects are capital intensive projects which rely on specialized production technologies. Certain current technologies for the recovery of heavy oil, such as CSS and SAGD, are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of

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production using new technologies. A large increase in recovery costs could cause certain projects that rely on CSS, SAGD or other new technologies to become uneconomic, which could have an adverse effect on our financial condition and our reserves. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.

Project economics and our earnings may be reduced if increases in operating costs are incurred. Factors which could affect operating costs include, without limitation: the costs imposed by GHG emissions regulations, labour costs; the cost of catalysts and chemicals; the cost of natural gas and electricity; water handling and availability; power outages; produced sand causing issues of erosion, hot spots and corrosion; reliability of facilities; maintenance costs; the cost to transport sales products; and the cost to dispose of certain by-products.

We may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required vendor services to compete.

The oil and natural gas industry is highly competitive in all of its phases. The Company competes with numerous other entities in the exploration for, and the development, production and marketing of, oil and natural gas, as well as for capital, acquisitions of reserves and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and materials such as drilling rigs, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities, pipeline and refining capacity, as well as many other services, and in many other respects, with a substantial number of other organizations, many of which may have greater technical and financial resources than the Company. As a result, some of the Company's competitors may have greater opportunities and be able to access, services or vendors that the Company is not able to access, thereby limiting its ability to compete.

Our information technology systems are subject to certain risks

We utilize and have become increasingly dependent upon a number of information technology systems for the administration and management of our business and are subject to a variety of information technology and system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company's information technology systems by third parties or insiders. If our ability to access and use these systems is interrupted and cannot be quickly and easily restored then such event could have a material adverse effect on us. Furthermore, although the Company has security measures and controls in place to mitigate these risks, a breach of its security measures and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws, and/or disruption to business activities. The significance of any such event is difficult to quantify but may in certain circumstances be material and could have a material adverse effect on the Company's business, financial condition and results of operations.

Adverse results from litigation may have an adverse affect on our business and reputation

In the normal course of our operations, we may become involved in, be named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions. Potential litigation may develop in relation to personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access rights, environmental issues, including claims relating to contamination or natural resource damages and contract disputes. The outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse effect on our financial condition.

Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities at maturity could adversely affect our financial condition

Our Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms, if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations, including future capital expenditures, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund ongoing operations. In the event that the Credit Facilities are not extended prior to maturity, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will not be renewed for the same amount or on the same terms.

Failure to comply with the covenants in the agreements governing our debt, including our obligation to repay the Senior Notes at maturity, could adversely affect our financial condition

We are required to comply with the covenants in our Credit Facilities and the Senior Notes. If we fail to comply with such covenants, are unable to repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our creditors. The proceeds from

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any sale of our assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale were applied towards our debt would the remainder, if any, be available for the benefit of our Shareholders.

Expansion into New Activities

Our operations and the expertise of our management are currently focused primarily on oil and natural gas production, exploration and development in the Provinces of Alberta and Saskatchewan and the State of Texas. In the future, we may acquire or move into new industry related activities or new geographical areas and may acquire different energy-related assets. As a result, we may face unexpected risks or, alternatively, our exposure to one or more existing risk factors may be significantly increased, which may in turn result in our future operational and financial conditions being adversely affected.

Indigenous Land and Rights Claims

Opposition by Indigenous groups to the conduct of the Company's operations, development or exploratory activities in any of the jurisdictions in which the Company conducts business may negatively impact it in terms of public perception, diversion of management's time and resources, and legal and other advisory expenses, and could adversely impact the Company's progress and ability to explore and develop properties.

Indigenous peoples have claimed Indigenous rights and title in portions of Western Canada. We are not aware that any claims have been made in respect of our properties and assets. However, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays in the construction of infrastructure systems and facilities which could have a material adverse effect on our business and financial results.

We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a default risk

We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to us may adversely affect our results of operations, cash flow from operating activities and financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of credit, which would decrease our available liquidity and increase our costs.

Geopolitical risk and conflicts in or around major oil and gas producing nations can significantly impact commodity prices and, therefore the financial condition of the oil and gas industry

Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Financial and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on the global economy, energy and commodity prices. The short-, medium- and long-term implications of any such conflicts is difficult to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflict(s), it may have the effect of heightening many of the other risks described herein, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of capital; and supply chains and cost-effective and timely transportation.

The Company could lose its status as a "foreign private issuer" in the United States

The Company is required to assess its "foreign private issuer" ("FPI") status under U.S. securities laws on an annual basis at the end of its second quarter. While the Company currently qualifies as an FPI, it could lose its FPI status in the future. If the Company were to lose its status as an FPI it would be required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country. In addition, if the Company loses its FPI status, it would be required to report as a U.S. domestic issuer and be subject to other U.S. securities laws applicable to U.S. domestic issuers. The regulatory and compliance costs to our business under U.S. securities laws as a U.S. domestic issuer may be significantly greater than the costs our business incurs as a foreign private issuer. For example, as a U.S. domestic issuer, the Company would be required to file periodic reports and registration statements with the SEC on U.S. domestic issuer forms, which are more detailed and extensive in certain respects than the forms available to the Company as a foreign private issuer. The Company would also be required to report its oil and gas reserves and production information in accordance with applicable U.S. disclosure requirements. Such conversion and modifications would involve additional costs and may restrict the Company’s access to capital markets for a period of time until it has satisfied SEC reporting requirements. In addition, the Company may lose its ability to rely upon exemptions from certain corporate governance requirements on U.S. stock exchanges that are available to FPIs, which could also increase its costs.

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Conflicts of interest may arise between the Company and its directors and officers

Circumstances may arise where directors and officers of the Company are directors or officers of other companies involved in the oil and gas industry which are in competition to, or otherwise in conflict with, the interests of the Company. Directors are required to abstain from voting on matters when they are in conflict. Employees, including officers, are not permitted to partake in activities that do not support the best interests of the Company. Where employee conflicts exist, they are to be provided in writing to our Human Resources Department, which discloses all conflicts to Chief Legal Officer. See the Company’s Code of Business Conduct and Ethics at www.baytexenergy.com.

Risks Related to Ownership of our Securities

Changes in market-based factors may adversely affect the trading price of the Common Shares

The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity prices, interest rates, foreign exchange rates, the decision of certain indices to include our Common Shares and the comparability of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.

Forward-Looking Information rely upon assumptions which may not prove correct

Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Dividends on the Company's Common Shares and Common Share repurchases are variable

The future acquisition by the Company of Common Shares pursuant to a share buyback (including through its NCIB) and the payment of dividends, if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback or to pay dividends will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, our business performance, financial condition, financial requirements, commodity prices, 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 the Company under applicable corporate law. In the future, there can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback and there can be no assurance that dividends will be paid or, if paid the amount of such dividends.

Certain Risks for United States and other non-resident Shareholders

The ability of investors resident in the United States to enforce civil remedies is limited

We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary, Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators), and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.

Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States

We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not required to be included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, be utilized.

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We have included estimates of proved reserves and proved and probable reserves. Probable reserves have a lower certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable reserves are different than NI 51-101; therefore, proved, probable and proved and probable reserves disclosed may not be comparable to United States standards.

As a consequence of the foregoing, our reserves estimates and production volumes may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

There is additional taxation applicable to non-residents

Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these taxes may change from time to time.