Document

EX-99.2 3 a992-q12022mda.htm EX-99.2 Document

Baytex Energy Corp.

Q1 2022 MD&A 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three months ended March 31, 2022 and 2021

Dated April 28, 2022

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2022. This information is provided as of April 28, 2022. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months ended March 31, 2022 ("Q1/2022") has been compared with the results for the three months ended March 31, 2021 ("Q1/2021"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 2022, its audited comparative consolidated financial statements for the years ended December 31, 2021 and 2020, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2021. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.

This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning in accordance with International Financial Reporting Standards ("IFRS") as prescribed by the International Accounting Standards Board. The terms "operating netback", "free cash flow", "average royalty rate", "heavy oil, net of blending and other expense" and "total sales, net of blending and other expense" are specified financial measures that do not have any standardized meaning as prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. This MD&A also contains the terms "adjusted funds flow", "net debt" and "net debt to adjusted funds flow ratio" which are capital management measures. Refer to our advisory on forward-looking information and statements and a summary of our specified financial measures at the end of the MD&A.

BAYTEX ENERGY CORP.

Baytex Energy Corp. is a North American focused energy company based in Calgary, Alberta. The company operates in Canada and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford assets in Texas.

FIRST QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q1/2022. Energy prices strengthened to multi-year highs due to elevated uncertainty of global oil and natural gas supply after Russia's invasion of Ukraine in addition to limited production growth reflecting oil and gas producers' capital discipline. As a result, the average WTI benchmark price for Q1/2022 was US$94.29/bbl which was US$36.45/bbl higher than Q1/2021 when WTI averaged US$57.84/bbl. With higher commodity prices, we generated adjusted funds flow(1) of $279.6 million and free cash flow(2) of $121.3 million which contributed to a $134.0 million reduction in net debt(1). Strong well performance across all of our assets resulted in production of 80,867 boe/d which was consistent with our annual guidance range of 80,000 - 83,000 boe/d.

Exploration and development expenditures were $153.8 million for Q1/2022 with $126.1 million invested in Canada and $27.7 million in the U.S. In Canada, we brought 12 (12.0 net) heavy oil wells and 58 (56.5 net) light oil wells on production during Q1/2022 which resulted in production of 53,385 boe/d that increased 1,346 boe/d from Q1/2021. In the U.S., we brought 15 (4.7 net) wells on production during Q1/2022 which resulted in production of 27,482 boe/d or 741 boe/d higher than Q1/2021.

Adjusted funds flow(1) of $279.6 million in Q1/2022 was $123.0 million higher than Q1/2021 as a result of higher benchmark prices. The increase in commodity prices was the primary factor that resulted in a $188.4 million increase in operating netback for Q1/2022 relative to Q1/2021. Our strong operating and financial results contributed to net income of $56.9 million for Q1/2022 compared to a net loss of $35.4 million for Q1/2021.

(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.

Q1 2022 MD&A 2

We used our free cash flow(1) of $121.3 million generated during Q1/2022 to reduce our debt. Net debt(2) of $1.28 billion at March 31, 2022 was $134.0 million lower compared to $1.41 billion at December 31, 2021. The decrease in net debt also reflects the strengthening of the Canadian dollar during Q1/2022 to 1.2484 CAD/USD at March 31, 2022 compared to 1.2656 CAD/USD at December 31, 2021.

(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.

2022 GUIDANCE

The following table compares our revised 2022 annual guidance to our previously announced guidance. Operational success, the continued strong economics of our drilling program as well as inflationary pressures being experienced throughout our industry have caused us to review our capital program for the year.

We are now forecasting 2022 exploration and development expenditures of $450 to $500 million, up from our original guidance of $400 - $450 million which was set anticipating WTI of approximately US$65/bbl for 2022. The incremental capital reflects additional activity on our Clearwater lands and the Eagle Ford as well as expected capital cost inflation. With continued strong operating momentum and production growth on our Clearwater lands, we are increasing our production guidance for 2022 to 83,000 to 85,000 boe/d. We also adjusted several of our cost assumptions to reflect higher commodity pricing, inflationary pressures and higher production volumes. Interest expense guidance is lower as we expect to reduce net debt during the remainder of 2022.


	Original Annual Guidance (1)	Revised Annual Guidance
Exploration and development expenditures	$400 - $450 million	$450 - $500 million
Production (boe/d)	80,000 - 83,000	83,000 - 85,000

Expenses:
Average royalty rate(2)	18.5% - 19.0%	20.0% - 20.5%
Operating(3)	$12.25 - $13.00/boe	$13.00 - $13.50/boe
Transportation(3)	$1.20 - $1.30/boe	$1.30 - $1.40/boe
General and administrative(3)	$43 million ($1.45/boe)	$43 million ($1.40/boe)
Interest(3)	$80 million ($2.70/boe)	$75 million ($2.45/boe)

Leasing expenditures	$3 million	no change
Asset retirement obligations	$20 million	no change

(1)As announced on December 1, 2021.

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

Baytex Energy Corp.

Q1 2022 MD&A 3

RESULTS OF OPERATIONS

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

Production


	Three Months Ended March 31
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	17,573		16,492		34,065		19,228		16,202		35,430
Heavy oil	25,236		—		25,236		21,989		—		21,989
Natural Gas Liquids (NGL)	1,935		5,701		7,636		1,970		4,268		6,238
Total liquids (bbl/d)	44,744		22,193		66,937		43,187		20,470		63,657
Natural gas (mcf/d)	51,843		31,731		83,574		53,109		37,630		90,739
Total production (boe/d)	53,385		27,482		80,867		52,039		26,741		78,780

Production Mix
Segment as a percent of total	66	%	34	%	100	%	66	%	34	%	100	%

Light oil and condensate	33	%	60	%	42	%	37	%	61	%	45	%
Heavy oil	47	%	—	%	31	%	42	%	—	%	28	%
NGL	4	%	21	%	9	%	4	%	16	%	8	%
Natural gas	16	%	19	%	18	%	17	%	23	%	19	%

Production was 80,867 boe/d for Q1/2022 compared to 78,780 boe/d for Q1/2021. Total production was higher in Q1/2022 compared to Q1/2021 due to our successful development programs in the U.S. and Canada including strong well results from our Clearwater development program.

In Canada, production of 53,385 boe/d for Q1/2022 was higher compared to 52,039 boe/d for Q1/2021. Our successful 2021 development program and strong well performance from our Clearwater development program has resulted in production for Q1/2022 that was 1,346 boe/d higher relative to Q1/2021.

In the U.S., production of 27,482 boe/d for Q1/2022 was higher than 26,741 boe/d for Q1/2021. Limited development activity throughout 2020 resulted in lower production levels in the U.S. during Q1/2021 when activity began to increase as commodity prices stabilized. We initiated production from 15 (4.7 net) wells during Q1/2022 compared to 24 (7.0 net) wells during the comparative period in 2021.

Total production of 80,867 boe/d for Q1/2022 is consistent with expectations and our original annual guidance range of 80,000 - 83,000 boe/d. Our revised annual guidance of 83,000 - 85,000 boe/d for 2022 reflects our strong operating momentum to date and production growth on our Clearwater lands.

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 traded at multi-year highs during Q1/2022. Russia's invasion of Ukraine has led to significant economic sanctions and uncertainty over oil supply from Russia while global supply growth has been limited with reduced capital investment. Oil demand continues to improve as global economic activity increases and economies recover from the pandemic. These factors resulted in the WTI benchmark price averaging US$94.29/bbl for Q1/2022 which was US$36.45/bbl higher relative to Q1/2021 when WTI averaged US$57.84/bbl.

Baytex Energy Corp.

Q1 2022 MD&A 4

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$96.72/bbl during Q1/2022 which is US$37.36/bbl higher than US$59.36/bbl during Q1/2021. The MEH benchmark trades at a premium to WTI as a result of access to global markets. For Q1/2022 the premium of US$2.43/bbl to WTI was larger than a US$1.52/bbl premium to WTI during Q1/2021 as a result of Russia's invasion of Ukraine and heightened concerns over global oil 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 from period to period based on production and inventory levels in Western Canada.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $115.66/bbl during Q1/2022 compared to $66.58/bbl during Q1/2021. Edmonton par traded at a discount to WTI of US$2.94/bbl for Q1/2022 which is narrower compared to a discount of US$5.27/bbl for Q1/2021 due to higher demand for Canadian light oil in Q1/2022.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q1/2022 averaged $100.99/bbl compared to $57.46/bbl for the same period of 2021. The WCS heavy oil differential was US$14.53/bbl in Q1/2022 which is wider compared to US$12.46/bbl for Q1/2021. Floods in Western Canada in late 2021 caused a temporary shut down of the Trans Mountain pipeline and resulted in a WCS differential of US$17.38/bbl in January 2022.

Natural Gas

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$4.95/mmbtu for Q1/2022 which is higher than US$2.69/mmbtu for Q1/2021. Strong demand and lower U.S. production resulted in reduced natural gas inventory levels which contributed to higher NYMEX benchmark prices for Q1/2022 relative to Q1/2021.

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. Lower production and an increased demand for natural gas resulted in reduced inventory levels in Canada and contributed to stronger AECO benchmark pricing in 2022 relative to 2021. The AECO benchmark averaged $4.59/mcf during Q1/2022 which is higher than $2.93/mcf for Q1/2021.

The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
	2022	2021	Change
Benchmark Averages
WTI oil (US$/bbl)(1)	94.29	57.84	36.45
MEH oil (US$/bbl)(2)	96.72	59.36	37.36
MEH oil differential to WTI (US$/bbl)	2.43	1.52	0.91
Edmonton par oil ($/bbl)(3)	115.66	66.58	49.08
Edmonton par oil differential to WTI (US$/bbl)	(2.94)	(5.27)	2.33
WCS heavy oil ($/bbl)(4)	100.99	57.46	43.53
WCS heavy oil differential to WTI (US$/bbl)	(14.53)	(12.46)	(2.07)
AECO natural gas price ($/mcf)(5)	4.59	2.93	1.66
NYMEX natural gas price (US$/mmbtu)(6)	4.95	2.69	2.26
CAD/USD average exchange rate	1.2661	1.2663	(0.0002)

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

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

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

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

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

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

Baytex Energy Corp.

Q1 2022 MD&A 5


	Three Months Ended March 31
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)(1)	$	113.91	$	121.82	$	117.74	$	64.46	$	72.42	$	68.10
Heavy oil, net of blending and other expense ($/bbl)(2)	89.38		—		89.38		46.45		—		46.45
NGL ($/bbl)(1)	42.96		42.89		42.91		24.61		34.21		31.18
Natural gas ($/mcf)(1)	4.64		6.06		5.17		3.03		7.84		5.02
Total sales, net of blending and other expense ($/boe)(2)	$	85.81	$	89.00	$	86.89	$	47.47	$	60.36	$	51.84

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

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe was $86.89/boe for Q1/2022 compared to $51.84/boe for Q1/2021. In Canada, our realized price of $85.81/boe for Q1/2022 was $38.34/boe higher than $47.47/boe for Q1/2021. Our realized price in the U.S. was $89.00/boe in Q1/2022 which is $28.64/boe higher than $60.36/boe in Q1/2021. The increase in our realized price in Canada and the U.S. for Q1/2022 was a result of higher North American benchmark prices relative to the same period of 2021.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $113.91/bbl for Q1/2022 compared to $64.46/bbl for Q1/2021. Our realized light oil and condensate price for Q1/2022 increased with the improvement in the benchmark price and represents a discount of $1.75/bbl to the Edmonton par price which is similar to a discount of $2.12/bbl for Q1/2021.

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 $121.82/bbl for Q1/2022 compared to $72.42/bbl for Q1/2021. Expressed in U.S. dollars, our realized light oil and condensate price of US$96.22/bbl for Q1/2022 represents a discount to MEH of US$0.50/bbl. Production increased as benchmark prices strengthened during Q1/2022 which resulted in stronger price realizations relative to Q1/2021 when our discount to MEH was US$2.17/bbl.

Our realized heavy oil price, net of blending and other expense averaged $89.38/bbl in Q1/2022 compared to $46.45/bbl in Q1/2021. Our realized heavy oil, net of blending and other expense for Q1/2022 was $42.93/bbl higher relative to Q1/2021 which is consistent with a $43.53/bbl increase in the WCS benchmark price relative to Q1/2021.

Our realized NGL price as a percentage of WTI can vary from period to period based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Our realized NGL price was $42.91/bbl in Q1/2022 or 36% of WTI (expressed in Canadian dollars) compared to $31.18/bbl or 43% of WTI (expressed in Canadian dollars) in Q1/2021. Our realized NGL price was lower as a percentage of WTI in Q1/2022 relative to the same period of 2021 when a winter storm in Texas disrupted supply and resulted in higher pricing for our U.S. NGL production.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $4.64/mcf for Q1/2022 compared to $3.03/mcf in Q1/2021. These realized prices were relatively consistent with the AECO benchmark price in both periods. In the U.S., our realized natural gas price was US$4.79/mcf for Q1/2022 compared to US$6.19/mcf for Q1/2021. Our realized natural gas price for Q1/2022 was lower relative to Q1/2021 due to fluctuations in the NYMEX daily index caused by severe events which disrupted supply and caused increased demand on the U.S. Gulf coast during 2021.

Baytex Energy Corp.

Q1 2022 MD&A 6

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended March 31
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	180,156	$	180,820	$	360,976	$	111,546	$	105,596	$	217,142
Heavy oil	244,439		—		244,439		109,038		—		109,038
NGL	7,483		22,007		29,490		4,364		13,142		17,506
Total oil sales	432,078		202,827		634,905		224,948		118,738		343,686
Natural gas sales	21,626		17,294		38,920		14,475		26,541		41,016
Total petroleum and natural gas sales	453,704		220,121		673,825		239,423		145,279		384,702
Blending and other expense	(41,440)		—		(41,440)		(17,120)		—		(17,120)
Total sales, net of blending and other expense(1)	$	412,264	$	220,121	$	632,385	$	222,303	$	145,279	$	367,582

Total sales, net of blending and other expense, of $632.4 million for Q1/2022 increased $264.8 million from $367.6 million reported for Q1/2021. The increase in total sales is a primarily a result of higher realized pricing due to the increase in benchmark pricing along with a modest increase in production due to our successful development programs in the U.S. and Canada.

In Canada, total sales, net of blending and other expense, was $412.3 million for Q1/2022 which is an increase of $190.0 million from $222.3 million reported for Q1/2021. The increase in total petroleum and natural gas sales was primarily due to higher realized pricing for Q1/2022 relative to Q1/2021. Our increased realized price resulted in a $184.2 million increase in total sales, net of blending and other expense, while a modest increase in production resulted in a $5.8 million increase in total sales, net of blending and other expense, relative to Q1/2021.

In the U.S., petroleum and natural gas sales were $220.1 million for Q1/2022 which is an increase of $74.8 million from $145.3 million reported for Q1/2021. Total petroleum and natural gas sales increased $70.8 million due to higher realized pricing for Q1/2022 relative to Q1/2021 while higher production resulted in a $4.0 million increase in total sales, net of blending and other expense relative to Q1/2021.

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
	2022									2021
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	57,676		$	65,044		$	122,720		$	24,664		$	42,286		$	66,950
Average royalty rate(1)(2)	14.0		%	29.5		%	19.4		%	11.1		%	29.1		%	18.2		%
Royalties per boe(3)	$	12.00		$	26.30		$	16.86		$	5.27		$	17.57		$	9.44

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

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

Royalties for Q1/2022 were $122.7 million or 19.4% of total sales, net of blending and other expense compared to $67.0 million or 18.2% for Q1/2021. Total royalty expense was higher for Q1/2022 due to higher total sales, net of blending and other expense, relative to Q1/2021. Our royalty rate of 19.4% for Q1/2022 was also higher than 18.2% for Q1/2021 due to a higher royalty rate on our Canadian properties as a result of higher commodity prices. Our average royalty rate of 19.4% for Q1/2022 is slightly below our revised annual guidance range of 20.0% - 20.5% for 2022 as we expect higher commodity pricing during the remainder of the year.

Our Canadian royalty rate of 14.0% for Q1/2022 was higher than 11.1% for Q1/2021 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in 2022 relative to 2021. In the U.S., royalties averaged 29.5% of total sales for Q1/2022, which is consistent with 29.1% for Q1/2021 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

OPERATING EXPENSE


	Three Months Ended March 31
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	78,540	$	22,226	$	100,766	$	61,361	$	19,187	$	80,548
Operating expense per boe(1)	$	16.35	$	8.99	$	13.85	$	13.10	$	7.97	$	11.36

(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 $100.8 million ($13.85/boe) for Q1/2022 compared to $80.5 million ($11.36/boe) for Q1/2021. Total operating expense for Q1/2022 increased with production relative to Q1/2021. Operating expense of $13.85/boe for Q1/2022 was above our revised annual guidance range of $13.00 - $13.50/boe largely due to higher fuel, electricity and hauling costs as these costs are tied to the price of oil and gas which have increased above our original budget.

In Canada, operating expense was $78.5 million ($16.35/boe) for Q1/2022 compared to $61.4 million ($13.10/boe) for Q1/2021. Operating expense in Canada has increased for Q1/2022 relative to Q1/2021 due to higher production along with an increase in per unit operating expenses. U.S. operating expense was $22.2 million ($8.99/boe) for Q1/2022 compared to $19.2 million ($7.97/boe) for Q1/2021. Higher operating expense in Q1/2022 is a result of higher production along with an increase in per unit operating expenses relative to Q1/2021. Expressed in U.S. dollars, per unit operating expense was US$7.10/boe in Q1/2022 which was higher than US$6.29/boe for Q1/2021. The increase in per unit operating expense in Canada and the U.S. was primarily a result of higher fuel, electricity and hauling costs in Q1/2022 relative to Q1/2021.

TRANSPORTATION EXPENSE

Transportation expense includes the costs to move production from the field to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary from period to period depending on hauling distances as we seek to optimize sales prices and trucking rates.

The following table compares our transportation expense for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	9,215	$	—	$	9,215	$	8,788	$	—	$	8,788
Transportation expense per boe(1)	$	1.92	$	—	$	1.27	$	1.88	$	—	$	1.24

(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 $9.2 million ($1.27/boe) for Q1/2022 which is consistent with $8.8 million ($1.24/boe) for Q1/2021. Per unit transportation expense of $1.27/boe for Q1/2022 is consistent with expectations and our revised annual guidance of $1.30 - $1.40/boe.

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 $41.4 million for Q1/2022 compared to $17.1 million for Q1/2021. Higher blending and other expense reflects an increase in the price of condensate purchased as diluent along with an increase in heavy oil pipeline shipments in Q1/2022 due to higher heavy oil production and lower rail deliveries relative to Q1/2021.

Baytex Energy Corp.

Q1 2022 MD&A 7

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 adjusted funds 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 for commodities and currencies fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
($ thousands)	2022		2021		Change
Realized financial derivatives loss
Crude oil	$	(79,526)	$	(20,041)	$	(59,485)
Natural gas	(4,840)		(727)		(4,113)

Total	$	(84,366)	$	(20,768)	$	(63,598)
Unrealized financial derivatives (loss) gain
Crude oil	$	(139,318)	$	(85,470)	$	(53,848)
Natural gas	(16,634)		(1,387)		(15,247)

Equity total return swap ("Equity TRS")	(309)		873		(1,182)
Total	$	(156,261)	$	(85,984)	$	(70,277)
Total financial derivatives (loss) gain
Crude oil	$	(218,844)	$	(105,511)	$	(113,333)
Natural gas	(21,474)		(2,114)		(19,360)

Equity TRS	(309)		873		(1,182)
Total	$	(240,627)	$	(106,752)	$	(133,875)

We recorded total financial derivative loss of $240.6 million for Q1/2022 compared to a loss of $106.8 million for Q1/2021. The realized financial derivatives loss of $84.4 million for Q1/2022 was a result of the market prices for crude oil and natural gas settling at levels above those set in our derivative contracts. The unrealized loss of $156.3 million for Q1/2022 was primarily a result of the increase in forecasted crude oil pricing used to revalue our crude oil contracts in place at March 31, 2022 relative to December 31, 2021 along with the valuation of new contracts entered during the period. The fair value of our financial derivative contracts resulted in a net liability of $281.6 million at March 31, 2022 compared to a net liability of $125.4 million at December 31, 2021.

Baytex Energy Corp.

Q1 2022 MD&A 8

We had the following commodity financial derivative contracts as at April 28, 2022.

Period

Volume

Price/Unit(1)

Index

Oil

Basis Swap

Apr 2022 to Dec 2022

12,000 bbl/d

WTI less US$12.40/bbl

WCS

Basis Swap

Apr 2022 to Jun 2022

1,000 bbl/d

WTI less US$3.00/bbl

MSW

Basis Swap

Apr 2022 to Dec 2022

6,000 bbl/d

WTI less US$3.91/bbl

MSW

Basis Swap

Jul 2022 to Dec 2022

750 bbl/d

WTI less US$2.30/bbl

MSW

Fixed Sell

Apr 2022 to Dec 2022

10,000 bbl/d

US$53.50/bbl

WTI

3-way option(2)

Apr 2022 to Dec 2022

1,500 bbl/d

US$40.00/US$50.00/US$58.10

WTI

3-way option(2)

Apr 2022 to Dec 2022

2,000 bbl/d

US$46.00/US$56.00/US$66.72

WTI

3-way option(2)

Apr 2022 to Dec 2022

2,500 bbl/d

US$47.00/US$57.00/US$67.00

WTI

3-way option(2)

Apr 2022 to Dec 2022

2,500 bbl/d

US$50.00/US$60.00/US$70.00

WTI

3-way option(2)

Apr 2022 to Dec 2022

2,000 bbl/d

US$53.00/US$63.50/US$72.90

WTI

3-way option(2)

Jan 2023 to Dec 2023

2,000 bbl/d

US$55.00/US$66.00/US$84.00

WTI

3-way option(2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$60.00/US$75.00/US$91.54

WTI

3-way option(2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$65.00/US$85.00/US$100.00

WTI

3-way option(2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$65.00/US$85.00/US$106.50

WTI

Natural Gas

Fixed Sell

Apr 2022 to Dec 2022

5,000 GJ/d

$2.53/GJ

AECO 7A

Fixed Sell

Apr 2022 to Dec 2022

14,250 GJ/d

$2.84/GJ

AECO 5A

Fixed Sell

Apr 2022 to Dec 2022

1,000 mmbtu/d

US$2.94/mmbtu

NYMEX

3-way option(2)

Apr 2022 to Dec 2022

2,500 mmbtu/d

US$2.25/US$2.75/US$3.06

NYMEX

3-way option(2)

Apr 2022 to Dec 2022

1,500 mmbtu/d

US$2.60/US$2.91/US$3.56

NYMEX

3-way option(2)

Apr 2022 to Dec 2022

2,500 mmbtu/d

US$2.60/US$3.00/US$3.83

NYMEX

3-way option(2)

Apr 2022 to Dec 2022

2,500 mmbtu/d

US$2.65/US$2.90/US$3.40

NYMEX

3-way option(2)

Apr 2022 to Dec 2022

2,500 mmbtu/d

US$3.00/US$3.75/US$4.40

NYMEX

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

(2)Producer 3-way option consists of a sold put, a bought put and a sold call. To illustrate, in a US$50.00/US$60.00/US$70.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$60.00/bbl when WTI is between US$50.00/bbl and US$60.00/bbl; Baytex receives the market price when WTI is between US$60.00/bbl and US$70.00/bbl; and Baytex receives US$70.00/bbl when WTI is above US$70.00/bbl.

Baytex Energy Corp.

Q1 2022 MD&A 9

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
	2022						2021
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	53,385		27,482		80,867		52,039		26,741		78,780
Operating netback:
Total sales, net of blending and other expense(1)	$	85.81	$	89.00	$	86.89	$	47.47	$	60.36	$	51.84
Less:
Royalties(2)	(12.00)		(26.30)		(16.86)		(5.27)		(17.57)		(9.44)
Operating expense(2)	(16.35)		(8.99)		(13.85)		(13.10)		(7.97)		(11.36)
Transportation expense(2)	(1.92)		—		(1.27)		(1.88)		—		(1.24)
Operating netback(1)	$	55.54	$	53.71	$	54.91	$	27.22	$	34.82	$	29.80
Realized financial derivatives (loss) gain(3)	—		—		(11.59)		—		—		(2.93)
Operating netback after financial derivatives(1)	$	55.54	$	53.71	$	43.32	$	27.22	$	34.82	$	26.87

(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 (loss) expense divided by barrels of oil equivalent production volume for the applicable period.

Our operating netback of $54.91/boe for Q1/2022 was higher than $29.80/boe for Q1/2021 due to the increase in benchmark pricing in Canada and the U.S. which resulted in higher per unit sales net of royalties. Total operating and transportation expense of $15.12/boe for Q1/2022 was higher than $12.60/boe for Q1/2021 due to higher fuel, electricity and hauling costs. Including realized gains and losses on financial derivatives our operating netback was $43.32/boe for Q1/2022 compared to $26.87/boe for Q1/2021.

GENERAL AND ADMINISTRATIVE EXPENSE

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

The following table summarizes our G&A expense for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
($ thousands except for per boe)	2022		2021		Change
Gross general and administrative expense	$	13,507	$	9,462	$	4,045
Overhead recoveries	(1,825)		(729)		(1,096)
General and administrative expense	$	11,682	$	8,733	$	2,949
General and administrative expense per boe(1)	$	1.61	$	1.23	$	0.38

(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 $11.7 million ($1.61/boe) for Q1/2022 compared to $8.7 million ($1.23/boe) for Q1/2021. G&A expense for Q1/2022 was higher relative to Q1/2021 due to higher staffing costs associated with increased exploration and development expenditures in Canada during Q1/2022.

G&A expense of $1.61/boe for Q1/2022 is consistent with expectations and is above our revised annual guidance of $1.40/boe for 2022 as a higher proportion of annual costs are incurred in the first quarter and we are forecasting production to increase over the remainder of 2022.

Baytex Energy Corp.

Q1 2022 MD&A 10

FINANCING AND INTEREST EXPENSE

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

The following table summarizes our financing and interest expense for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
($ thousands except for per boe)	2022		2021		Change
Interest on credit facilities	$	3,039	$	3,336	$	(297)
Interest on long-term notes	17,344		21,007		(3,663)
Interest on lease obligations	44		60		(16)
Cash interest	$	20,427	$	24,403	$	(3,976)
Accretion of debt issue costs	695		749		(54)
Accretion of asset retirement obligations	3,122		2,298		824


Financing and interest expense	$	24,244	$	27,450	$	(3,206)
Cash interest per boe(1)	$	2.81	$	3.44	$	(0.63)
Financing and interest expense per boe(1)	$	3.33	$	3.87	$	(0.54)

(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 $24.2 million ($3.33/boe) for Q1/2022 compared to $27.5 million ($3.87/boe) for Q1/2021. Lower debt levels have resulted in reduced financing and interest expense in Q1/2022 relative to Q1/2021.

Cash interest of $20.4 million ($2.81/boe) for Q1/2022 is lower than $24.4 million ($3.44/boe) for Q1/2021 as we had less debt outstanding during 2022. The interest on our U.S. dollar denominated long-term notes was lower as the average principal amount outstanding was lower during Q1/2022 due to the repurchase and redemption of US$200.0 million of long-term notes in 2021. Interest on our credit facilities in Q1/2022 was relatively consistent with the same period of 2021. The weighted average interest rate applicable to our credit facilities was 2.4% Q1/2022 compared to 2.1% for Q1/2021.

Financing and interest expense for Q1/2022 was lower than Q1/2021 which was primarily the result of the repurchase and redemption of long-term notes in 2021 and also reflects a higher discount rate used to accrete our asset retirement obligations in Q1/2022.

Cash interest expense of $2.81/boe for Q1/2022 is above our revised annual guidance of $2.45/boe for 2022 as we expect a reduction in our net debt during the remainder of the year along with higher production.

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 $3.6 million for Q1/2022 compared to $0.9 million for Q1/2021.

Baytex Energy Corp.

Q1 2022 MD&A 11

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three months ended March 31, 2022 and 2021.


	Three Months Ended March 31
($ thousands except for per boe)	2022		2021		Change
Depletion	$	139,446	$	100,739	$	38,707
Depreciation	1,345		1,273		72
Depletion and depreciation	$	140,791	$	102,012	$	38,779
Depletion and depreciation per boe(1)	$	19.34	$	14.39	$	4.95

(1)Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production volume for the applicable period.

Depletion and depreciation expense was $140.8 million ($19.34/boe) for Q1/2022 compared to $102.0 million ($14.39/boe) for Q1/2021. Total depletion and depreciation expense as well as the depletion rate per boe were higher in Q1/2022 relative to Q1/2021 as a result of $1.5 billion of impairment reversals recorded during 2021 which increased the depletable base of our U.S and Canadian assets.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at March 31, 2022.

2021 Impairment Reversals

We identified indicators of impairment reversal at June 30, 2021 and December 31, 2021 due to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves and we recorded a total impairment reversal of $1.5 billion. At June 30, 2021 we recorded a $1.1 billion impairment reversal as the estimated recoverable amount of our six CGUs exceeded their carrying values. At December 31, 2021 we recorded a $0.4 billion impairment reversal as the estimated recoverable amount of three CGUs exceeded their carrying amounts.

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 our Share Award Incentive Plan 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 our Incentive Award Plan is recognized in net income or loss over the vesting period of the awards with a corresponding financial liability and includes gains or losses on equity total return swaps used to fix the aggregate cost of new grants made under the plan. SBC expense associated with the Deferred Share Unit Plan is recognized in net income or loss on the grant date with a corresponding financial liability and includes gains or losses on equity total return swaps used to fix the aggregate cost of new grants made under the plan. SBC expense varies with the quantity of unvested share awards outstanding and the grant date fair value assigned to the share awards.

We recorded SBC expense of $3.9 million for Q1/2022 which is consistent with $3.0 million for Q1/2021. The total expense for Q1/2022 is comprised of non-cash compensation expense of $1.7 million related to the Share Award Incentive Plan and cash compensation expense of $2.2 million related to the Incentive Award Plan and the Deferred Share Unit Plan.

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

Baytex Energy Corp.

Q1 2022 MD&A 12


	Three Months Ended March 31
($ thousands except for exchange rates)	2022		2021		Change
Unrealized foreign exchange gain	$	(14,548)	$	(2,530)	$	(12,018)
Realized foreign exchange loss (gain)	203		(275)		478
Foreign exchange gain	$	(14,345)	$	(2,805)	$	(11,540)
CAD/USD exchange rates:
At beginning of period	1.2656		1.2755
At end of period	1.2484		1.2572

We recorded a foreign exchange gain of $14.3 million for Q1/2022 compared to a gain of $2.8 million for Q1/2021.

The unrealized foreign exchange gain of $14.5 million for Q1/2022 is primarily related to changes in the reported amount of our long-term notes due to a strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2022 compared to December 31, 2021. The unrealized foreign exchange gain for Q1/2021 relates to changes in the reported amount of our long-term notes and intercompany notes outstanding at March 31, 2021 compared to December 31, 2020.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $0.2 million for Q1/2022 compared to a gain of $0.3 million for Q1/2021.

INCOME TAXES


	Three Months Ended March 31
($ thousands)	2022		2021		Change
Current income tax expense (recovery)	$	910	$	(160)	$	1,070
Deferred income tax (recovery) expense	(67,332)		5,664		(72,996)
Total income tax (recovery) expense	$	(66,422)	$	5,504	$	(71,926)

Current income tax expense was $0.9 million for Q1/2022 compared to a recovery of $0.2 million for Q1/2021.

We recorded a deferred tax recovery of $67.3 million for Q1/2022 compared to an expense of $5.7 million for Q1/2021. The deferred tax recovery recorded in Q1/2022 is primarily related to the effect of an internal debt restructuring offset by the income generated in our U.S. operations for the period. The deferred tax expense for Q1/2021 reflects income generated in our U.S. operations for the period.

As disclosed in the 2021 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591.0 million of non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. In September 2016, we filed notices of objection with the CRA appealing each reassessment received. There has been no change in the status of these reassessments since an Appeals Officer was assigned to our file in July 2018. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals process.

Baytex Energy Corp.

Q1 2022 MD&A 13

NET INCOME (LOSS) AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three months ended March 31, 2022 and 2021 are set forth in the following table.


	Three Months Ended March 31
($ thousands)	2022		2021		Change
Petroleum and natural gas sales	$	673,825	$	384,702	$	289,123
Royalties	(122,720)		(66,950)		(55,770)
Revenue, net of royalties	551,105		317,752		233,353

Expenses
Operating	(100,766)		(80,548)		(20,218)
Transportation	(9,215)		(8,788)		(427)
Blending and other	(41,440)		(17,120)		(24,320)
Operating netback(1)	$	399,684	$	211,296	$	188,388
General and administrative	(11,682)		(8,733)		(2,949)
Cash interest	(20,427)		(24,403)		3,976
Realized financial derivatives loss	(84,366)		(20,768)		(63,598)
Realized foreign exchange (loss) gain	(203)		275		(478)
Other (expense) income	(250)		232		(482)
Current income tax (expense) recovery	(910)		160		(1,070)
Share-based compensation - cash	(2,239)		(1,477)		(762)

Adjusted funds flow(2)	$	279,607	$	156,582	$	123,025

Exploration and evaluation	(3,570)		(947)		(2,623)
Depletion and depreciation	(140,791)		(102,012)		(38,779)
Share-based compensation - non-cash	(1,706)		(1,504)		(202)
Non-cash financing and accretion	(3,817)		(3,047)		(770)
Non-cash other income	1,282		988		294
Unrealized financial derivatives loss	(156,261)		(85,984)		(70,277)
Unrealized foreign exchange gain	14,548		2,530		12,018
Gain on dispositions	234		3,706		(3,472)

Deferred income tax recovery (expense)	67,332		(5,664)		72,996

Net income (loss) for the period	$	56,858	$	(35,352)	$	92,210

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

We generated adjusted funds flow of $279.6 million for Q1/2022 compared to $156.6 million for Q1/2021. The increase in adjusted funds flow for Q1/2022 was primarily due to higher operating netback which increased $188.4 million from Q1/2021 as a result of higher commodity prices that increased revenue, net of royalties. The increase in operating netback was partially offset by realized losses on financial derivatives of $84.4 million for Q1/2022 due to the increase in oil and natural gas benchmark prices relative to Q1/2021 when we recorded $20.8 million of losses on financial derivatives.

We reported net income of $56.9 million for Q1/2022 compared to a net loss of $35.4 million reported for Q1/2021.

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation loss of $28.1 million for Q1/2022 relates to the change in value of our U.S. net assets and is due to a strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2022 compared to December 31, 2021. The CAD/USD exchange rate was 1.2484 CAD/USD as at March 31, 2022 compared to 1.2656 CAD/USD at December 31, 2021.

Baytex Energy Corp.

Q1 2022 MD&A 14

CAPITAL EXPENDITURES

Capital expenditures for the three months ended March 31, 2022 and 2021 are summarized as follows.


	Three Months Ended March 31
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	107,000	$	27,138	$	134,138	$	39,034	$	40,724	$	79,758
Facilities	7,764		386		8,150		2,515		—		2,515
Land, seismic and other	11,366		168		11,534		954		361		1,315
Exploration and development expenditures	$	126,130	$	27,692	$	153,822	$	42,503	$	41,085	$	83,588
Property acquisitions	$	59	$	—	$	59	$	25	$	—	$	25
Proceeds from dispositions	$	(27)	$	—	$	(27)	$	(228)	$	—	$	(228)

Exploration and development expenditures were $153.8 million for Q1/2022 compared to $83.6 million for Q1/2021. Expenditures in Q1/2022 were higher compared to Q1/2021 as development increased throughout 2021 with the strengthening of commodity prices that continued into 2022.

In Canada, exploration and development expenditures were $126.1 million in Q1/2022 which is $83.6 million higher than $42.5 million in Q1/2021. Drilling and completion spending of $107.0 million in Q1/2022 reflects additional light and heavy oil development activity relative to Q1/2021 when we spent $39.0 million. Drilling and completion activity includes 6 (6.0 net) Clearwater wells brought on production during Q1/2022. We also invested $7.8 million on facilities and $11.4 million on land, seismic and workover expenditures during Q1/2022.

Total U.S. exploration and development expenditures were $27.7 million for Q1/2022 which is $13.4 million lower than Q1/2021 when exploration and development expenditures totaled $41.1 million. Exploration and development expenditures for Q1/2022 included costs associated with drilling 14 (2.3 net) wells along with 15 (4.7 net) wells that were brought on production compared to drilling 25 (7.5 net) wells along with 24 (7.0 net) wells brought on production during Q1/2021.

Our exploration and development expenditures for Q1/2022 are consistent with expectations. Due to inflationary pressures and our successful Clearwater development program we have increased our exploration and development expenditure guidance to $450 - $500 million for 2022.

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management is to maintain a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At March 31, 2022, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables and the credit facilities.

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

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

Management of debt levels is a priority for Baytex in order to sustain operations and support our long-term plans. At March 31, 2022, net debt(1) of $1.28 billion was $134.0 million lower than $1.41 billion at December 31, 2021. The decrease in net debt during 2022 is primarily a result of the free cash flow(2) of $121.3 million being allocated to debt repayment.

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a trailing twelve month basis. At March 31, 2022, our net debt to adjusted funds flow ratio(1) was 1.5 compared to a ratio of 1.9 as at December 31, 2021. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2021 is attributed to higher adjusted funds flow for the trailing twelve months ended March 31, 2022 and lower net debt at March 31, 2022.

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

Credit Facilities

At March 31, 2022, the principal amount of borrowings and letters of credit outstanding was $441.7 million under our credit facilities. At March 31, 2022, the credit facilities consisted of a US$575.0 million revolving facility and a $300 million term loan set to mature on April 2, 2024 (the "Credit Facilities"). On April 1, 2022, we amended the Credit Facilities to eliminate the term loan and increase total revolving capacity to US$850.0 million while extending maturity to April 1, 2026.

The Credit Facilities are not borrowing base facilities and do not require annual or semi-annual reviews. The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended upon our request. Advances (including letters of credit) 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 agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR website at www.sedar.com.

The weighted average interest rate on the Credit Facilities was 2.4% for Q1/2022 compared to 2.1% for Q1/2021.

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2022.


Covenant Description	Position as at March 31, 2022	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.5:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	10.9:1.0	2.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit agreement. As at March 31, 2022, the Company's Senior Secured Debt totaled $441.7 million which includes $426.9 million of principal amounts outstanding and $14.8 million of letters of credit.

(2)Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 2022 was $957.0 million.

(3)"Interest coverage" is calculated in accordance with the credit 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 March 31, 2022 were $87.9 million.

Long-Term Notes

We have two series of long-term notes outstanding that total $873.9 million as at March 31, 2022. The long-term notes do not contain any financial maintenance covenants.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes which were redeemed February 20, 2020, and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"). The 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. The 5.625% Notes are redeemable at our option, in whole or in part, at 100.938% and will be redeemable at par from June 1, 2022 to maturity. During 2021, Baytex repurchased and cancelled a total of US$200.0 million of the 5.625% Notes. At March 31, 2022, there was US$200.0 million of the 5.625% Notes outstanding.

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.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2022, we issued 5.0 million common shares pursuant to our share-based compensation program. As at April 28, 2022, we had 569.2 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 March 31, 2022 and the expected timing for funding these obligations are noted in the table below.


($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	257,683	$	257,683	$	—	$	—	$	—
Financial derivatives	289,027		276,823		12,204		—		—
Credit facilities - principal(1)(2)	426,858		—		426,858		—		—
Long-term notes - principal(2)	873,880		—		249,680		—		624,200
Interest on long-term notes(3)	303,823		68,662		125,627		109,235		299
Lease obligations(2)	7,565		3,015		3,871		563		116
Processing agreements	7,654		1,308		1,536		953		3,857
Transportation agreements	74,892		18,905		35,014		14,673		6,300
Total	$	2,241,382	$	626,396	$	854,790	$	125,424	$	634,772

(1)As of March 31, 2022 the credit facilities were set to mature on April 2, 2024. On April 1, 2022 we extended the maturity of our credit facilities to April 1, 2026.

(2)Principal amount of instruments.

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

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

Baytex Energy Corp.

Q1 2022 MD&A 15

QUARTERLY FINANCIAL INFORMATION


	2022	2021				2020
($ thousands, except per common share amounts)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Petroleum and natural gas sales	673,825	552,403	488,736	442,354	384,702	233,636	252,538	152,689
Net income (loss)	56,858	563,239	32,714	1,052,999	(35,352)	221,160	(23,444)	(138,463)
Per common share - basic	0.10	1.00	0.06	1.87	(0.06)	0.39	(0.04)	(0.25)
Per common share - diluted	0.10	0.98	0.06	1.85	(0.06)	0.39	(0.04)	(0.25)
Adjusted funds flow(1)	279,607	214,766	198,397	175,883	156,582	82,176	78,508	17,887
Per common share - basic	0.49	0.38	0.35	0.31	0.28	0.15	0.14	0.03
Per common share - diluted	0.49	0.37	0.35	0.31	0.28	0.15	0.14	0.03
Free cash flow(2)	121,318	137,133	101,215	112,486	70,495	1,794	59,939	5,939
Per common share - basic	0.21	0.24	0.18	0.20	0.13	—	0.11	0.01
Per common share - diluted	0.21	0.24	0.18	0.20	0.13	—	0.11	0.01
Cash flows from operating activities	198,974	240,567	178,961	171,876	120,980	51,017	93,688	25,824
Per common share - basic	0.35	0.43	0.32	0.30	0.22	0.09	0.17	0.05
Per common share - diluted	0.35	0.42	0.31	0.30	0.22	0.09	0.17	0.05
Exploration and development	153,822	73,995	94,235	61,485	83,588	77,809	15,902	9,852
Canada	126,130	59,821	75,499	30,387	42,503	45,030	3,882	2,929
U.S.	27,692	14,174	18,736	31,098	41,085	32,779	12,020	6,923
Property acquisitions	59	1,443	89	—	25	—	—	—
Proceeds from dispositions	(27)	(6,857)	(701)	(18)	(228)	(33)	(98)	(11)
Net debt(1)	1,275,680	1,409,717	1,564,658	1,629,629	1,758,894	1,847,601	1,906,079	1,994,953
Total assets	4,836,189	4,834,643	4,453,971	4,438,162	3,338,408	3,408,096	3,156,414	3,267,820
Common shares outstanding	569,214	564,213	564,213	564,182	564,111	561,227	561,163	560,545

Daily production
Total production (boe/d)	80,867	80,789	79,872	81,162	78,780	70,475	77,814	72,508
Canada (boe/d)	53,385	50,362	48,124	47,205	52,039	45,321	49,164	37,691
U.S. (boe/d)	27,482	30,428	31,748	33,957	26,741	25,154	28,650	34,817

Benchmark prices
WTI oil (US$/bbl)	94.29	77.19	70.56	66.07	57.84	42.66	40.93	27.85
WCS heavy ($/bbl)	100.99	78.82	71.81	67.03	57.46	43.46	42.40	22.70
Edmonton Light ($/bbl)	115.66	93.29	83.78	77.28	66.58	50.24	49.83	29.85
CAD/USD avg exchange rate	1.2661	1.2600	1.2601	1.2279	1.2663	1.3031	1.3316	1.3860
AECO gas ($/mcf)	4.59	4.94	3.54	2.85	2.93	2.77	2.18	1.91
NYMEX gas (US$/mmbtu)	4.95	5.83	4.01	2.83	2.69	2.66	1.98	1.72

Total sales, net of blending and other expense ($/boe)(2)	86.89	70.42	63.85	57.19	51.84	34.35	33.79	22.31
Royalties ($/boe)(3)	(16.86)	(13.47)	(12.32)	(11.04)	(9.44)	(5.83)	(5.59)	(4.42)
Operating expense ($/boe)(3)	(13.85)	(12.83)	(11.46)	(11.22)	(11.36)	(12.30)	(10.26)	(11.17)
Transportation expense ($/boe)(3)	(1.27)	(1.10)	(1.06)	(1.01)	(1.24)	(1.03)	(0.89)	(0.76)
Operating netback ($/boe)(2)	54.91	43.02	39.01	33.92	29.80	15.19	17.05	5.96
Financial derivatives gain (loss) ($/boe)(3)	(11.59)	(9.49)	(7.34)	(5.28)	(2.93)	2.64	(1.36)	2.06
Operating netback after financial derivatives ($/boe)(2)	43.32	33.53	31.67	28.64	26.87	17.83	15.69	8.02

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

Baytex Energy Corp.

Q1 2022 MD&A 16

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

Our results for the previous eight quarters reflect the disciplined execution of our development programs and management of production in response to fluctuations in the prices for the commodities we produce. Production of 72,508 boe/d in Q2/2020 reflects our response to shut-in production as commodity prices collapsed due to the initial spread of COVID-19. Development activity was restarted as commodity prices stabilized during Q4/2020 and we maintained the pace of activity as commodity prices continued to improve throughout 2021. Strong well performance and our successful development programs have resulted in production of 80,867 boe/d for Q1/2022.

Decisions made by Saudi Arabia and Russia to increase production of crude oil as demand was decreasing due to the spread of COVID-19 resulted in a sharp decline in global crude oil prices with WTI averaging US$27.85/bbl in Q2/2020. Prices improved and were relatively stable through the second half of 2020 as OPEC+ agreed to reinstate production curtailments and measures to control the spread of COVID-19 were relaxed. Commodity prices strengthened to multi-year highs in Q1/2022 with WTI averaging US$94.29/bbl due to elevated uncertainty for the supply of oil following Russia's invasion of Ukraine in addition to limited production growth from large independent producers. The impact of increased commodity prices is reflected in our realized sales price of $86.89/boe for Q1/2022 which is our strongest realized pricing in the previous eight quarters.

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 improved for Q1/2022 compared to the lows in 2020 due to strong price realizations which reflects the increase in benchmark commodity prices over the previous eight quarters.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt(1) has decreased from $2.0 billion at Q2/2020 to $1.3 billion at Q1/2022 as free cash flow(2) of $610.3 million generated over the last eight quarters has been directed towards debt repayment. Our net debt has also been reduced by a decrease in the CAD/USD exchange rate used to translate our U.S. dollar denominated debt from 1.3616 CAD/USD at Q2/2020 to 1.2484 CAD/USD at Q1/2022.

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

ENVIRONMENTAL REGULATIONS

As a result of our involvement in the exploration and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2021 for a full description of the risks associated with these regulations and how they may impact our business in the future. In addition to the Risk Factors discussed in the AIF for the year ended December 31, 2021, additional information related to our emissions and sustainability initiatives is available on our website.

Reporting Regulations

Environmental reporting for public enterprises continues to evolve and we may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. We continue to monitor developments on these reporting requirements and have not yet quantified the cost to comply with these regulations.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2022, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the three months ended March 31, 2022. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2021.

Baytex Energy Corp.

Q1 2022 MD&A 17

NYSE LISTING

On March 24, 2020 we received notice from the New York Stock Exchange (“NYSE”) that Baytex was no longer in compliance with one of the NYSE’s continued listing standards because the average closing price of Baytex’s common shares was less than US$1.00 per share over a consecutive 30-day trading period. Baytex did not regain compliance and its common shares were delisted from the NYSE on December 3, 2020.

Baytex's common shares remain registered with the U.S. Securities and Exchange Commission. Given that Baytex remains listed on the TSX and the average daily trading volume of Baytex’s common shares in the U.S. is greater than 5% of Baytex’s worldwide average daily trading volume over a 12-month period following the delisting, Baytex is not eligible to deregister its common shares and must continue to follow the reporting guidelines of the Securities Exchange Act of 1934, as amended.

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", "net debt" and "net debt to adjusted funds flow ratio" 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

Total sales, net of blending and other expense represents the revenues realized from produced volumes during a period. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for 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.

Operating netback

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

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


	Three Months Ended March 31
($ thousands)	2022		2021
Petroleum and natural gas sales	$	673,825	$	384,702
Blending and other expense	(41,440)		(17,120)
Total sales, net of blending and other expense	632,385		367,582
Royalties	(122,720)		(66,950)
Operating expense	(100,766)		(80,548)
Transportation expense	(9,215)		(8,788)
Operating netback	399,684		211,296
Realized financial derivatives gain (loss)(1)	(84,366)		(20,768)
Operating netback after realized financial derivatives	$	315,318	$	190,528

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss; see Note 16 Financial Instruments and Risk Management in the Consolidated Financial Statements for the three months ended March 31, 2022 for further information.

Baytex Energy Corp.

Q1 2022 MD&A 18

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 and payments on lease obligations.

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


	Three Months Ended March 31
($ thousands)	2022		2021
Cash flows from operating activities	$	198,974	$	120,980
Change in non-cash working capital	77,340		34,185
Additions to exploration and evaluation assets	(3,559)		(216)
Additions to oil and gas properties	(150,263)		(83,372)
Payments on lease obligations	(1,174)		(1,082)
Free cash flow	$	121,318	$	70,495

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

Total sales, net of blending and other expense per boe

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

Average royalty rate

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

Operating netback per boe

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

Capital Management Measures

Net debt

We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade and other payables, cash, and trade and other receivables. We also use a net debt to adjusted funds flow ratio calculated on a twelve-month trailing basis to monitor our existing capital structure and future liquidity requirements. Net debt to adjusted funds flow is comprised of net debt divided by twelve-month trailing adjusted funds flow.

Baytex Energy Corp.

Q1 2022 MD&A 19

The following table summarizes our calculation of net debt.


($ thousands)	March 31, 2022		December 31, 2021
Credit facilities	$	425,675	$	505,171
Unamortized debt issuance costs - Credit facilities (1)	1,183		1,343
Long-term notes	863,180		874,527
Unamortized debt issuance costs - Long-term notes (1)	10,700		11,393
Trade and other payables	257,683		190,692
Trade and other receivables	(282,741)		(173,409)
Net debt	$	1,275,680	$	1,409,717
Net debt to adjusted funds flow	1.5		1.9

(1)Unamortized debt issuance costs were obtained from Note 6 Credit Facilities and Note 7 Long-term Notes from the Consolidated Financial Statements for the three months ended March 31, 2022. These amounts represent the remaining balance of costs that were paid by Baytex at the inception of the contract.

Adjusted funds flow

Adjusted funds flow is used to monitor operating performance and our ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital and asset retirements obligations settled during the applicable period.

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


	Three Months Ended March 31
($ thousands)	2022		2021
Cash flow from operating activities	$	198,974	$	120,980
Change in non-cash working capital	77,340		34,185
Asset retirement obligations settled	3,293		1,417

Adjusted funds flow	$	279,607	$	156,582

INTERNAL CONTROL OVER FINANCIAL REPORTING

We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended March 31, 2022.

Baytex Energy Corp.

Q1 2022 MD&A 20

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: our business strategies, plans and objectives; our 2022 guidance with respect to exploration and development expenditures, average daily production, royalty rate and operating, transportation, general and administrative and interest expenses; the existence, operation and strategy of our risk management program; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; and the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; we may issued debt or equity securities, sell assets or adjust capital spending.

These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices (well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; 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; 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 volatility of oil and natural gas prices and price differentials (including the impacts of Covid-19); restrictions or costs imposed by climate change initiatives and the physical risks of climate change; risks associated with our ability to develop our properties and add reserves; the impact of an energy transition on demand for petroleum productions; changes in income tax or other laws or government incentive programs; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; the availability and cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; risks associated with large projects; costs to develop and operate our properties; public perception and its influence on the regulatory regime; current or future control, legislation or regulations; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; results of litigation; that our credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks of counterparty default; the impact of Indigenous claims; risks associated with expansion into new activities; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2021, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.

There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.