EX-99.2 3 a992-q12021mda.htm EX-99.2

Document

Baytex Energy Corp.                                            

Q1 2021 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three months ended March 31, 2021 and 2020

Dated April 29, 2021

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, 2021. This information is provided as of April 29, 2021. 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, 2021 ("Q1/2021") have been compared with the results for the three months ended March 31, 2020 ("Q1/2020"). 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, 2021, its audited comparative consolidated financial statements for the years ended December 31, 2020 and 2019, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2020. 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 prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). The terms "adjusted funds flow", "operating netback", "exploration and development expenditures", "free cash flow", "net debt", and "Bank EBITDA" do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of the MD&A.

BAYTEX ENERGY CORP.

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

FIRST QUARTER HIGHLIGHTS

During Q1/2021, the global economy continued to show signs of recovery from the impacts of the COVID-19 pandemic. The outlook for crude oil demand has improved due to the easing of restrictions combined with the distribution of vaccines in developed countries and supply concerns have eased due to ongoing OPEC production curtailments. As a result, the average WTI benchmark price for Q1/2021 was US$57.84/bbl which was 25% higher relative to Q1/2020 when WTI averaged US$46.17/bbl. Our disciplined approach to capital allocation and continued focus on reducing our cost structure has improved the results we have achieved as commodity prices have increased.

We delivered strong operating and financial results for Q1/2021. Production of 78,780 boe/d was 8,305 boe/d higher than 70,475 boe/d for Q4/2020. This increase in production reflects $83.6 million invested on exploration and development which represents 53% of adjusted funds flow and generated free cash flow of $70.5 million for Q1/2021.

In Canada, exploration and development expenditures of $42.5 million for Q1/2021 were focused on our light oil properties. We generated production of 52,039 boe/d for Q1/2021 which was 6,718 boe/d higher than 45,321 boe/d during Q4/2020 and reflects the resumption of drilling activity which began in Q4/2020.

In the U.S., we invested $41.1 million on development activity during Q1/2021 and continued with the pace of development after drilling activity resumed during Q4/2020. Production of 26,741 boe/d was up 1,587 boe/d from 25,154 boe/d during Q4/2020 despite the winter storm in Texas which temporarily disrupted operations during February.

Adjusted funds flow was $156.6 million in Q1/2021 which is higher than $132.9 million reported for Q1/2020 as a result of the improvement in benchmark prices for Q1/2021 relative to Q1/2020. The increase in crude oil prices and our cost saving initiatives increased operating netback by $67.6 million in Q1/2021 relative to Q1/2020 despite lower production. We recorded a net loss of $35.4 million for Q1/2021 compared to a net loss of $2.5 billion in Q1/2020 which included impairments of $2.7 billion.

Baytex Energy Corp.                                            

Q1 2021 MD&A    2

Net debt was $1.76 billion at March 31, 2021 compared to $1.85 billion at December 31, 2020 representing a reduction of $88.7 million. The reduction in net debt was primarily due to free cash flow of $70.5 million combined with a $18.1 million decrease in the reported amount of our U.S. dollar denominated net debt due to the strengthening of the Canadian dollar relative to the U.S. dollar during Q1/2021.

2021 GUIDANCE

The following table compares our revised 2021 annual guidance to our previously announced guidance and our Q1/2021 results. As a result of our strong operational performance combined with the improved outlook for commodity prices for the remainder of 2021 we have increased our annual production guidance to 77,000 - 79,000 boe/d with budgeted exploration and development expenditures of $285 - $315 million.

We have also adjusted several of our cost assumptions to reflect higher production volumes and increased activity. Our interest expense guidance is 7% lower due to reduced net debt and the Canadian dollar strengthening relative to the U.S. dollar.

			2021 Guidance (1)			2021 Revised Guidance			Q1/2021 Results
Exploration and development expenditures			$225 - $275 million			$285 - $315 million			$83.6 million
Production (boe/d)			73,000 - 77,000			77,000 - 79,000			78,780
Expenses:
Royalty rate			18.0% - 18.5%			no change			18.2%
Operating			$11.50 - $12.25/boe			$11.25 - $12.00/boe			$11.36/boe
Transportation			$1.00 - $1.10/boe			$1.15 - $1.25/boe			$1.24/boe
General and administrative			$42 million ($1.53/boe)			$42 million ($1.48/boe)			$8.7 million ($1.23/boe)
Interest			$105 million ($3.84/boe)			$98 million ($3.46/boe)			$24.4 million ($3.44/boe)
Leasing expenditures			$4 million			no change			$1.1 million
Asset retirement obligations			$6 million			no change			$1.4 million

(1)As announced on December 2, 2020.

Baytex Energy Corp.                                            

Q1 2021 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
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate			19,228			16,202			35,430			24,241			21,476			45,717
Heavy oil			21,989			—			21,989			28,854			—			28,854
Natural Gas Liquids (NGL)			1,970			4,268			6,238			1,317			6,505			7,822
Total liquids (bbl/d)			43,187			20,470			63,657			54,412			27,981			82,393
Natural gas (mcf/d)			53,109			37,630			90,739			47,100			49,256			96,356
Total production (boe/d)			52,039			26,741			78,780			62,262			36,190			98,452
Production Mix
Segment as a percent of total			66		%	34		%	100		%	63		%	37		%	100		%
Light oil and condensate			37		%	61		%	45		%	39		%	59		%	46		%
Heavy oil			42		%	—		%	28		%	46		%	—		%	29		%
NGL			4		%	16		%	8		%	2		%	18		%	8		%
Natural gas			17		%	23		%	19		%	13		%	23		%	17		%

Production was 78,780 boe/d for Q1/2021 compared to 98,452 boe/d for Q1/2020. Total production was lower in Q1/2021 compared to Q1/2020 as we reduced exploration and development activity following the sharp decline in commodity prices in March 2020. We restarted activity in Canada and the U.S. late in 2020 as commodity prices began to recover resulting in production of 78,780 boe/d for Q1/2021. As a result of our strong operational performance and an improved outlook for commodity prices for the remainder of 2021 we have increased our annual production guidance to 77,000 - 79,000 boe/d with a modest increase in planned capital spending for the second half of 2021.

In Canada, production was 52,039 boe/d for Q1/2021 compared to 62,262 boe/d for Q1/2020. Production for Q1/2021 was lower than Q1/2020 as we limited development spending following the decline in crude oil prices in March 2020. Activity resumed in the second half of 2020 and the pace of development continued during Q1/2021 and resulted in production increasing 6,718 boe/d relative to 45,321 boe/d during Q4/2020.

In the U.S., production was 26,741 boe/d for Q1/2021 compared to 36,190 boe/d for Q1/2020. The decrease reflects limited development activity during 2020 along with the impact of the Texas storm that disrupted operations in February 2021. Development activity on our U.S. land resumed in the second half of 2020 and we initiated production from 24 (7.0 net) wells during Q1/2021 which resulted in production increasing 1,587 boe/d relative to 25,154 boe/d during Q4/2020.

Commodity Prices

The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and our financial position.

Crude Oil

Global benchmark prices for crude oil continued to strengthen during Q1/2021 as the outlook for oil demand improved due to the forecasted increase in global economic activity and OPEC has maintained production curtailments that restrict supply. These factors resulted in the WTI benchmark price averaging US$57.84/bbl for Q1/2021 which was 25% higher relative to Q1/2020 when WTI averaged US$46.17/bbl.

Baytex Energy Corp.                                            

Q1 2021 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$59.36/bbl during Q1/2021 compared to US$49.54/bbl during Q1/2020. The MEH benchmark was at a US$1.52/bbl premium to WTI in Q1/2021 compared to a US$3.37/bbl premium to WTI during Q1/2020. The decrease in the MEH benchmark premium to WTI in Q1/2021 was a result of lower refinery demand on the U.S. Gulf coast due to the Texas storm in February 2021.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Canadian light and heavy oil differentials to WTI were narrower in Q1/2021 relative to Q1/2020 as a result of lower Canadian oil production.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price while pricing for our heavy oil production is based on the WCS benchmark price. The Edmonton par price averaged $66.58/bbl during Q1/2021 compared to $51.43/bbl during Q1/2020 and traded at a discount to WTI of US$5.27/bbl for Q1/2021 compared to a discount of US$7.92/bbl for Q1/2020. The WCS heavy oil price was also stronger in Q1/2021 and averaged $57.46/bbl compared to $34.48/bbl for Q1/2020. The WCS heavy oil differential was US$12.46/bbl in Q1/2021 compared to US$20.53/bbl for Q1/2020.

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$2.69/mmbtu in Q1/2021 which is higher than US$1.95/mmbtu in Q1/2020. The winter storm in Texas resulted in lower U.S. natural gas production and increased demand which resulted in higher natural gas prices in Q1/2021 relative to Q1/2020.

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 increasing supply and limited market access for Canadian natural gas production. The AECO benchmark averaged $2.93/mcf during Q1/2021 which is higher than $2.14/mcf for Q1/2020. The AECO gas benchmark was higher in Q1/2021 relative to Q1/2020 as a result of increased North American demand during the winter season.

The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2021 and 2020.

			Three Months Ended March 31
			2021			2020			Change
Benchmark Averages
WTI oil (US$/bbl) (1)			57.84			46.17			11.67
MEH oil (US$/bbl) (2)			59.36			49.54			9.82
MEH oil differential to WTI (US$/bbl)			1.52			3.37			(1.85)
Edmonton par oil ($/bbl) (3)			66.58			51.43			15.15
Edmonton par oil differential to WTI (US$/bbl)			(5.27)			(7.92)			2.65
WCS heavy oil ($/bbl) (4)			57.46			34.48			22.98
WCS heavy oil differential to WTI (US$/bbl)			(12.46)			(20.53)			8.07
AECO natural gas price ($/mcf) (5)			2.93			2.14			0.79
NYMEX natural gas price (US$/mmbtu) (6)			2.69			1.95			0.74
CAD/USD average exchange rate			1.2663			1.3445			(0.0782)

(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 2021 MD&A    5

			Three Months Ended March 31
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)			$	64.46		$	72.42		$	68.10		$	49.45		$	61.99		$	55.34
Heavy oil ($/bbl) (1)			46.45			—			46.45			20.75			—			20.75
NGL ($/bbl)			24.61			34.21			31.18			11.25			14.94			14.31
Natural gas ($/mcf)			3.03			7.84			5.02			2.00			2.63			2.32
Weighted average ($/boe) (1)			$	47.47		$	60.36		$	51.84		$	30.62		$	43.05		$	35.19

(1)Realized heavy oil prices are calculated based on sales volumes and sales dollars, net of blending and other expense.

Average Realized Sales Prices

Our weighted average sales price was $51.84/boe for Q1/2021 compared to $35.19/boe for Q1/2020. Our realized price in the U.S. was $60.36/boe in Q1/2021 which is $17.31/boe higher than $43.05/boe in Q1/2020. In Canada, our realized price of $47.47/boe for Q1/2021 was $16.85/boe higher than $30.62/boe for Q1/2020. The increase in our realized price in Canada and the U.S. for Q1/2021 was a result of higher North American benchmark prices relative to Q1/2020.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $64.46/bbl in Q1/2021 compared to $49.45/bbl in Q1/2020. Our realized light oil and condensate price for Q1/2021 increased with the improvement in the benchmark price and represents a discount of $2.12/bbl to the Edmonton par price which is relatively consistent with the discount of $1.98/bbl experienced in Q1/2020.

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 $72.42/bbl for Q1/2021 compared to $61.99/bbl for Q1/2020. Expressed in U.S. dollars, our realized light oil and condensate price of US$57.19/bbl for Q1/2021 represents a US$2.17/bbl discount to MEH which is narrower than a discount of US$3.43/bbl for Q1/2020 and reflects strong price realizations on our marketing contracts in place during Q1/2021.

Our realized heavy oil price, net of blending and other expense averaged $46.45/bbl in Q1/2021 compared to $20.75/bbl in Q1/2020. Our realized heavy oil price for Q1/2021 was $25.70/bbl higher relative to Q1/2020 compared to a $22.98/bbl increase in the WCS benchmark price over the same period. Our realized heavy oil price increased more than the WCS benchmark as a result of stronger price realizations on our marketing contracts in place for 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 $31.18/bbl in Q1/2021 or 43% of WTI (expressed in Canadian dollars) compared to $14.31/bbl or 23% of WTI (expressed in Canadian dollars) in Q1/2020. Our realized NGL price was higher as a percentage of WTI in Q1/2021 relative to Q1/2020 as strong demand along with reduced supply due to the Texas storm combined to increase NGL pricing in Q1/2021.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $3.03/mcf for Q1/2021 compared to $2.00/mcf in Q1/2020 and was relatively consistent with the AECO benchmark price in both periods. In the U.S., our realized natural gas price was US$6.19/mcf for Q1/2021 compared to US$1.96/mcf in Q1/2020. A portion of our natural gas production is based on the NYMEX daily index which resulted in a US$3.50/mcf premium to the NYMEX monthly benchmark for Q1/2021 due to the fluctuations in the daily index caused by the winter storm in Texas.

Baytex Energy Corp.                                            

Q1 2021 MD&A    6

Petroleum and Natural Gas Sales

			Three Months Ended March 31
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Oil sales
Light oil and condensate			$	111,546		$	105,596		$	217,142		$	109,084		$	121,155		$	230,239
Heavy oil			109,038			—			109,038			75,843			—			75,843
NGL			4,364			13,142			17,506			1,348			8,842			10,190
Total oil sales			224,948			118,738			343,686			186,275			129,997			316,272
Natural gas sales			14,475			26,541			41,016			8,569			11,773			20,342
Total petroleum and natural gas sales			239,423			145,279			384,702			194,844			141,770			336,614
Blending and other expense			(17,120)			—			(17,120)			(21,357)			—			(21,357)
Total sales, net of blending and other expense			$	222,303		$	145,279		$	367,582		$	173,487		$	141,770		$	315,257

Total sales, net of blending and other expense, of $367.6 million for Q1/2021 increased $52.3 million from $315.3 million reported for Q1/2020. The increase in total sales in Q1/2021 relative to Q1/2020 is a result of higher realized pricing due to the increase in benchmark pricing which more than offset the impact of lower sales volumes.

In Canada, total sales, net of blending and other expense, was $222.3 million for Q1/2021 which is an increase of $48.8 million from $173.5 million reported for Q1/2020. Total petroleum and natural gas sales increased due to higher realized pricing for Q1/2021 relative to Q1/2020. Our average realized price of $47.47/boe for Q1/2021 was higher than the realized price of $30.62/boe for Q1/2020 due to the increase in benchmark pricing resulting in a $78.9 million increase in total sales, net of blending and other expense. Production in Canada was 10,223 boe/d lower in Q1/2021 which resulted in a $30.1 million decrease in total sales, net of blending and other expense relative to Q1/2020.

In the U.S., petroleum and natural gas sales were $145.3 million for Q1/2021 which is an increase of $3.5 million from $141.8 million reported for Q1/2020. Total petroleum and natural gas sales increased due to higher realized pricing for Q1/2021 relative to Q1/2020. Our average realized price of $60.36/boe for Q1/2021 was higher than $43.05/boe for Q1/2020 due to the increase in benchmark pricing and resulted in a $41.7 million increase in total sales, net of blending and other expense. Production in the U.S. was 9,449 boe/d lower in Q1/2021 which resulted in a $38.2 million decrease in total sales, net of blending and other expense relative to Q1/2020.

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, 2021 and 2020.

			Three Months Ended March 31
			2021									2020
($ thousands except for % and per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Royalties			$	24,664		$	42,286		$	66,950		$	15,518		$	41,202		$	56,720
Average royalty rate (1)			11.1		%	29.1		%	18.2		%	8.9		%	29.1		%	18.0		%
Royalties per boe			$	5.27		$	17.57		$	9.44		$	2.74		$	12.51		$	6.33

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

Royalties for Q1/2021 were $67.0 million or 18.2% of total sales, net of blending and other expense compared to $56.7 million or 18.0% in Q1/2020. Total royalty expense was higher for Q1/2021 due to the increase in total sales, net of blending and other expense, relative to Q1/2020. Our royalty rate of 18.2% for Q1/2021 was consistent with 18.0% for Q1/2020. Our average royalty rate of 18.2% for Q1/2021 is consistent with expectations and our annual guidance range of 18.0% - 18.5% for 2021.

Our Canadian royalty rate of 11.1% for Q1/2021 was higher than 8.9% for Q1/2020 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in Q1/2021 relative to Q1/2020. In the U.S., royalties averaged 29.1% of total sales for Q1/2021 which is consistent with 29.1% for Q1/2020 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

Baytex Energy Corp.                                            

Q1 2021 MD&A    7

Operating Expense

			Three Months Ended March 31
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Operating expense			$	61,361		$	19,187		$	80,548		$	78,922		$	25,548		$	104,470
Operating expense per boe			$	13.10		$	7.97		$	11.36		$	13.93		$	7.76		$	11.66

Total operating expense was $80.5 million ($11.36/boe) for Q1/2021 compared to $104.5 million ($11.66/boe) in Q1/2020. The decrease in total operating expense for Q1/2021 compared to Q1/2020 can be attributed to lower production in addition to our cost savings initiatives which resulted in lower per boe operating expense for Q1/2021. Operating expense of $11.36/boe for Q1/2021 is consistent with expectations and our revised annual guidance range of $11.25 - $12.00/boe.

In Canada, operating expense was $61.4 million ($13.10/boe) for Q1/2021 compared to $78.9 million ($13.93/boe) for Q1/2020. Operating expense in Canada has decreased with lower production and our cost savings initiatives which resulted in per unit operating expense of $13.10/boe for Q1/2021 which was lower than $13.93/boe for Q1/2020.

U.S. operating expense was $19.2 million ($7.97/boe) for Q1/2021 compared to $25.5 million ($7.76/boe) for Q1/2020. Lower operating expense is primarily a result of lower U.S. production in Q1/2021 relative to Q1/2020. Expressed in U.S. dollars, per unit operating expense was US$6.29/boe in Q1/2021 which was slightly higher than US$5.77/boe for Q1/2020. The increase in per unit operating expense in the U.S. was a result of lower production along with additional costs incurred due to the winter storm in Texas during 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, 2021 and 2020.

			Three Months Ended March 31
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Transportation expense			$	8,788		$	—		$	8,788		$	10,342		$	—		$	10,342
Transportation expense per boe			$	1.88		$	—		$	1.24		$	1.83		$	—		$	1.15

Transportation expense was $8.8 million ($1.24/boe) for Q1/2021 compared to $10.3 million ($1.15/boe) in Q1/2020. The decrease in total transportation expense is primarily the result of lower production in Canada. Per unit transportation expense in Canada of $1.88/boe for Q1/2021 is relatively consistent with $1.83/boe for Q1/2020. Per unit transportation expense of $1.24/boe for Q1/2021 is consistent with expectations and our revised annual guidance of $1.15 - $1.25/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 $17.1 million for Q1/2021 compared to $21.4 million for Q1/2020. Lower blending and other expense reflects lower heavy oil sales in Q1/2021 relative to Q1/2020.

Baytex Energy Corp.                                            

Q1 2021 MD&A    8

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, 2021 and 2020.

			Three Months Ended March 31
($ thousands)			2021			2020			Change
Realized financial derivatives gain (loss)
Crude oil			$	(20,041)		$	26,645		$	(46,686)
Natural gas			(727)			210			(937)
Interest and financing			—			(5)			5
Total			$	(20,768)		$	26,850		$	(47,618)
Unrealized financial derivatives gain (loss)
Crude oil			$	(85,470)		$	99,809		$	(185,279)
Natural gas			(1,387)			(122)			(1,265)
Interest and financing			—			(678)			678
Equity total return swap ("Equity TRS")			873			(3,014)			3,887
Total			$	(85,984)		$	95,995		$	(181,979)
Total financial derivatives gain (loss)
Crude oil			$	(105,511)		$	126,454		$	(231,965)
Natural gas			(2,114)			88			(2,202)
Interest and financing			—			(683)			683
Equity TRS			873			(3,014)			3,887
Total			$	(106,752)		$	122,845		$	(229,597)

We recorded total financial derivative losses of $106.8 million for Q1/2021 compared to total financial derivative gains of $122.8 million in Q1/2020. Realized financial derivative losses of $20.8 million for Q1/2021 were primarily a result of the market prices for WTI settling at levels above those set in our derivative contracts. Unrealized losses of $86.0 million for Q1/2021 is primarily a result of the increase in forecasted crude oil pricing used to revalue our WTI and WCS contracts in place at March 31, 2021 relative to December 31, 2020 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 $107.7 million at March 31, 2021 compared to a net liability of $21.7 million at December 31, 2020.

Baytex Energy Corp.                                            

Q1 2021 MD&A    9

We had the following commodity financial derivative contracts as at April 29, 2021.

Period

Volume

Price/Unit (1)

Index

Oil

Basis Swap

Apr 2021 to Jun 2021

2,000 bbl/d

WTI less US$13.75/bbl

WCS

Basis Swap

Apr 2021 to Dec 2021

8,000 bbl/d

WTI less US$13.41/bbl

WCS

Basis Swap

Jan 2022 to Dec 2022

8,000 bbl/d

WTI less US$12.57/bbl

WCS

Basis Swap (4)

Jan 2022 to Dec 2022

1,000 bbl/d

WTI less US$11.70/bbl

WCS

Basis Swap

Apr 2021 to Dec 2021

7,500 bbl/d

WTI less US$5.03/bbl

MSW

Fixed Sell

Apr 2021 to Dec 2021

4,000 bbl/d

US$45.00/bbl

WTI

3-way option (2)

Apr 2021 to Dec 2021

500 bbl/d

US$35.00/US$45.00/US$49.03

WTI

3-way option (2)

Apr 2021 to Dec 2021

1,500 bbl/d

US$35.00/US$45.00/US$49.10

WTI

3-way option (2)

Apr 2021 to Dec 2021

3,500 bbl/d

US$35.00/US$45.00/US$49.50

WTI

3-way option (2)

Apr 2021 to Dec 2021

10,000 bbl/d

US$35.00/US$45.00/US$55.00

WTI

3-way option (2)

Apr 2021 to Dec 2021

2,000 bbl/d

US$37.00/US$42.50/US$48.00

WTI

3-way option (2)

Jan 2022 to Dec 2022

1,500 bbl/d

US$40.00/US$50.00/US$58.10

WTI

3-way option (2)

Jan 2022 to Dec 2022

2,000 bbl/d

US$46.00/US$56.00/US$66.72

WTI

3-way option (2)(4)

Jan 2022 to Dec 2022

2,500 bbl/d

US$47.00/US$57.00/US$67.00

WTI

Swaption (3)

Jan 2022 to Dec 2022

5,000 bbl/d

US$53.00/bbl

WTI

Swaption (3)

Jan 2022 to Dec 2022

5,000 bbl/d

US$54.00/bbl

WTI

Natural Gas

Fixed Sell

Apr 2021 to Jun 2021

3,000 GJ/d

$2.71/GJ

AECO 7A

Fixed Sell

Apr 2021 to Dec 2021

16,000 GJ/d

$2.36/GJ

AECO 7A

Fixed Sell (4)

Jan 2022 to Dec 2022

2,500 GJ/d

$2.40/GJ

AECO 7A

Fixed Sell

Apr 2021 to Dec 2021

2,500 GJ/d

$2.40/GJ

AECO 5A

Fixed Sell

Apr 2021 to Dec 2021

12,000 mmbtu/d

US$2.70/mmbtu

NYMEX

3-way option (2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.25/US$2.75/US$3.06

NYMEX

3-way option (2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.65/US$2.90/US$3.40

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$35.00/US$45.00/US$55.00 contract, Baytex receives WTI plus US$10.00/bbl when WTI is at or below US$35.00/bbl; Baytex receives US$45.00/bbl when WTI is between US$35.00/bbl and US$45.00/bbl; Baytex receives the market price when WTI is between US$45.00/bbl and US$55.00/bbl; and Baytex receives US$55.00/bbl when WTI is above US$55.00/bbl.

(3)For these contracts, the counterparty has the right, if exercised on December 31, 2021, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

(4)Contracts entered subsequent to March 31, 2021.

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, 2021 and 2020.

			Three Months Ended March 31
			2021									2020
($ per boe except for volume)			Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)			52,039			26,741			78,780			62,262			36,190			98,452
Operating netback:
Total sales, net of blending and other expense			$	47.47		$	60.36		$	51.84		$	30.62		$	43.05		$	35.19
Less:
Royalties			(5.27)			(17.57)			(9.44)			(2.74)			(12.51)			(6.33)
Operating expense			(13.10)			(7.97)			(11.36)			(13.93)			(7.76)			(11.66)
Transportation expense			(1.88)			—			(1.24)			(1.83)			—			(1.15)
Operating netback			$	27.22		$	34.82		$	29.80		$	12.12		$	22.78		$	16.05
Realized financial derivatives (loss) gain			—			—			(2.93)			—			—			3.00
Operating netback after financial derivatives			$	27.22		$	34.82		$	26.87		$	12.12		$	22.78		$	19.05

Baytex Energy Corp.                                            

Q1 2021 MD&A    10

Operating netback of $29.80/boe for Q1/2021 was higher than $16.05/boe for Q1/2020 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 $12.60/boe for Q1/2021 reflects our cost savings initiatives which resulted in lower costs relative to $12.81/boe in Q1/2020. Including realized gains and losses on financial derivatives our operating netback was $26.87/boe for Q1/2021 which was $7.82/boe higher than $19.05/boe reported for Q1/2020.

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, 2021 and 2020.

			Three Months Ended March 31
($ thousands except for per boe)			2021			2020			Change
Gross general and administrative expense			$	9,462		$	11,888		$	(2,426)
Overhead recoveries			(729)			(2,113)			1,384
General and administrative expense			$	8,733		$	9,775		$	(1,042)
General and administrative expense per boe			$	1.23		$	1.09		$	0.14

G&A expense was $8.7 million ($1.23/boe) for Q1/2021 compared to $9.8 million ($1.09/boe) for Q1/2020. G&A expense of $8.7 million for Q1/2021 was lower than $9.8 million for Q1/2020 primarily due to reduced staffing levels along with our cost savings initiatives that resulted in lower gross G&A expense. G&A expense per boe was slightly higher in Q1/2021 due to lower production compared to Q1/2020.

G&A expense of $1.23/boe reflects our costs savings initiatives along with temporarily lower staffing levels and is slightly below our revised annual guidance of $1.42/boe for 2021.

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, 2021 and 2020.

			Three Months Ended March 31
($ thousands except for per boe)			2021			2020			Change
Interest on credit facilities			$	3,336		$	4,135		$	(799)
Interest on long-term notes			21,007			24,273			(3,266)
Interest on lease obligations			60			127			(67)
Cash interest			$	24,403		$	28,535		$	(4,132)
Accretion of debt issue costs			749			4,442			(3,693)
Accretion of asset retirement obligations			2,298			2,931			(633)
Early redemption expense			—			3,312			(3,312)
Financing and interest expense			$	27,450		$	39,220		$	(11,770)
Cash interest per boe			$	3.44		$	3.19		$	0.25
Financing and interest expense per boe			$	3.87		$	4.38		$	(0.51)

Financing and interest expense was $27.5 million ($3.87/boe) for Q1/2021 compared to $39.2 million ($4.38/boe) for Q1/2020.

Baytex Energy Corp.                                            

Q1 2021 MD&A    11

Cash interest of $24.4 million ($3.44/boe) for Q1/2021 is lower than $28.5 million ($3.19/boe) for Q1/2020 primarily due to lower interest on our long-term notes. The reported interest on our U.S. dollar denominated long-term notes was lower due to a stronger Canadian dollar in Q1/2021 relative to Q1/2020. The average principal amount of long-term notes outstanding was also lower in Q1/2021 as the refinancing transactions completed in Q1/2020 resulted in a temporary increase in principal amounts outstanding. Interest on our credit facilities was lower in Q1/2021 due to lower borrowings and interest rates on our credit facilities which resulted in a weighted average interest rate of 2.1% compared to 3.4% in Q1/2020.

Financing and interest expense for Q1/2021 was lower than Q1/2020 which included the accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the $300 million principal amount of 6.625% senior unsecured notes which were redeemed on March 5, 2020.

Cash interest expense of $3.44/boe for Q1/2021 is consistent with our revised annual guidance of $3.46/boe for 2021.

Exploration and Evaluation Expense

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $0.9 million for Q1/2021 which is higher than $0.3 million for Q1/2020 due to a higher amount of acreage expiring in 2021 relative to 2020.

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, 2021 and 2020.

			Three Months Ended March 31
($ thousands except for per boe)			2021			2020			Change
Depletion			$	100,739		$	179,418		$	(78,679)
Depreciation			1,273			1,968			(695)
Depletion and depreciation			$	102,012		$	181,386		$	(79,374)
Depletion and depreciation per boe			$	14.39		$	20.25		$	(5.86)

Depletion and depreciation expense was $102.0 million ($14.39/boe) for Q1/2021 compared to $181.4 million ($20.25/boe) for Q1/2020. Total depletion and depreciation expense and the depletion rate per boe were lower in Q1/2021 compared to Q1/2020 due to lower production in Q1/2021 combined with $2.2 billion of net impairments recorded in 2020 which reduced the depletable base of our oil and gas properties at Q1/2021.

Impairment

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at March 31, 2021.

At March 31, 2020, we identified indicators of impairment due to the sharp decline in forecasted commodity prices. We performed impairment tests on the E&E assets and oil and gas properties for our six CGUs. We recorded total impairments of $2.7 billion in Q1/2020 as the carrying value of the E&E assets and oil and gas properties exceeded the estimated recoverable amounts of the CGUs. The total impairment recorded at Q1/2020 included $2.6 billion related to oil and gas properties and $0.1 billion related to E&E assets.

At December 31, 2020, with updated development plans, including capital efficiencies and reduced well costs, reflected in our reserves along with changes in commodity prices, we estimated the recoverable amount for E&E assets and oil and gas properties in each of our six CGUs. We recorded an impairment reversal of $356.1 million at December 31, 2020 as the estimated recoverable amount of the Viking and Eagle Ford CGUs exceeded their carrying value. The total impairment reversal recorded at Q4/2020 includes $341.3 million related to oil and gas properties and $14.8 million related to E&E assets.

Baytex Energy Corp.                                            

Q1 2021 MD&A    12

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 $3.0 million for Q1/2021 compared to $2.8 million for Q1/2020. SBC expense is higher due to the issuance of Deferred Share Units in Q1/2021 which are expensed in full on the grant date. The total expense for Q1/2021 is comprised of non-cash compensation expense of $1.5 million related to the Share Award Incentive Plan and cash compensation expense of $1.5 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 and our U.S. dollar denominated intercompany notes. The long-term notes and intercompany 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.

			Three Months Ended March 31
($ thousands except for exchange rates)			2021			2020			Change
Unrealized foreign exchange loss - intercompany notes (1)			$	13,741		$	—		$	13,741
Unrealized foreign exchange (gain) loss - long-term notes			(16,271)			99,521			(115,792)
Realized foreign exchange (gain) loss			(275)			371			(646)
Foreign exchange (gain) loss			$	(2,805)		$	99,892		$	(102,697)
CAD/USD exchange rates:
At beginning of period			1.2755			1.2965
At end of period			1.2572			1.4120

(1)During 2020, a series of intercompany notes totaling US$751.0 million were issued from a Canadian subsidiary to a U.S. subsidiary. These notes are eliminated upon consolidation within the Condensed Consolidated Statement of Financial Position and are revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian subsidiary are recognized in unrealized foreign exchange gain or loss whereas those within the U.S. subsidiary are recognized in other comprehensive income.

We recorded an unrealized foreign exchange gain on our long-term notes of $16.3 million for Q1/2021 due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. This compares to an unrealized foreign exchange loss of $99.5 million for Q1/2020 due to the weakening of the Canadian dollar relative to the U.S. dollar at March 31, 2020 compared to December 31, 2019.

We recorded an unrealized foreign exchange loss of $13.7 million for Q1/2021 on our intercompany notes issued by our Canadian subsidiary due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. There was no unrealized foreign exchange gain or loss on our intercompany notes recorded in Q1/2020 as the notes were issued in September 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 gain of $0.3 million for Q1/2021 compared to a loss of $0.4 million for Q1/2020.

Income Taxes

			Three Months Ended March 31
($ thousands)			2021			2020			Change
Current income tax (recovery) expense			$	(160)		$	469		$	(629)
Deferred income tax expense (recovery)			5,664			(283,179)			288,843
Total income tax expense (recovery)			$	5,504		$	(282,710)		$	288,214

Baytex Energy Corp.                                            

Q1 2021 MD&A    13

The current income tax recovery was $0.2 million for Q1/2021 compared to an expense of $0.5 million for Q1/2020.

We recorded deferred tax expense of $5.7 million for Q1/2021 compared to a $283.2 million recovery for Q1/2020 as the loss before tax was lower in Q1/2021 due to the impairment recorded in Q1/2020.

As disclosed in the 2020 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.

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, 2021 and 2020 are set forth in the following table.

			Three Months Ended March 31
($ thousands)			2021			2020			Change
Petroleum and natural gas sales			$	384,702		$	336,614		$	48,088
Royalties			(66,950)			(56,720)			(10,230)
Revenue, net of royalties			317,752			279,894			37,858
Expenses
Operating			(80,548)			(104,470)			23,922
Transportation			(8,788)			(10,342)			1,554
Blending and other			(17,120)			(21,357)			4,237
Operating netback			$	211,296		$	143,725		$	67,571
General and administrative			(8,733)			(9,775)			1,042
Cash financing and interest			(24,403)			(28,535)			4,132
Realized financial derivatives (loss) gain			(20,768)			26,850			(47,618)
Realized foreign exchange gain (loss)			275			(371)			646
Other income			232			2,031			(1,799)
Current income tax expense (recovery)			160			(469)			629
Cash share-based compensation			(1,477)			(521)			(956)
Adjusted funds flow			$	156,582		$	132,935		$	23,647
Exploration and evaluation			(947)			(260)			(687)
Depletion and depreciation			(102,012)			(181,386)			79,374
Non-cash share-based compensation			(1,504)			(2,262)			758
Non-cash financing and accretion			(3,047)			(10,685)			7,638
Non-cash other income			988			—			988
Unrealized financial derivatives (loss) gain			(85,984)			95,995			(181,979)
Unrealized foreign exchange gain (loss)			2,530			(99,521)			102,051
Gain on dispositions			3,706			137			3,569
Impairment			—			(2,716,349)			2,716,349
Deferred income tax (expense) recovery			(5,664)			283,179			(288,843)
Net loss for the period			$	(35,352)		$	(2,498,217)		$	2,462,865

We generated adjusted funds flow of $156.6 million for Q1/2021 compared to $132.9 million reported for Q1/2020. The increase in adjusted funds flow was primarily due to higher operating netback which increased $67.6 million from Q1/2020 as a result of higher commodity prices which increased revenue, net of royalties which more than offset lower production. The increase in operating netback was partially offset by realized losses on financial derivatives of $20.8 million for Q1/2021 due to the increase in oil and natural gas benchmark prices relative to Q1/2020 when we recorded realized gains on financial derivatives of $26.9 million.

Baytex Energy Corp.                                            

Q1 2021 MD&A    14

We reported a net loss of $35.4 million for Q1/2021 compared to a net loss of $2.5 billion for Q1/2020 which included $2.7 billion of impairment expense.

Other Comprehensive Income (Loss)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which includes a series of intercompany debt instruments outstanding between our Canadian and U.S. subsidiaries. Foreign exchange gains or losses on the debt owing from the U.S. subsidiary is recorded in other comprehensive income and the offsetting foreign exchange gain or loss on debt owed to the Canadian subsidiary is included in profit and loss for the period.

The $7.1 million foreign currency translation loss for Q1/2021 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the Canadian dollar strengthening relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020. The CAD/USD exchange rate was 1.2572 CAD/USD as at March 31, 2021 compared to 1.2755 CAD/USD at December 31, 2020.

Capital Expenditures

Capital expenditures for the three months ended March 31, 2021 and 2020 are summarized as follows.

			Three Months Ended March 31
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Drilling, completion and equipping			$	39,034		$	40,724		$	79,758		$	99,537		$	53,072		$	152,609
Facilities			2,515			—			2,515			19,003			300			19,303
Land, seismic and other			954			361			1,315			4,570			295			4,865
Total exploration and development			$	42,503		$	41,085		$	83,588		$	123,110		$	53,667		$	176,777
Total acquisitions, net of proceeds from divestitures			$	(203)		$	—		$	(203)		$	(40)		$	—		$	(40)

Exploration and development expenditures were $83.6 million for Q1/2021 compared to $176.8 million for Q1/2020. Expenditures in Q1/2021 were lower compared to Q1/2020 primarily due to reduced development activity in Canada in addition to a reduction in well costs for our U.S. properties.

In Canada, we invested $42.5 million on exploration and development activities in Q1/2021 which is $80.6 million lower than $123.1 million in Q1/2020. Exploration and development expenditures of $42.5 million for Q1/2021 included costs associated with drilling 37 (36.2 net) light oil wells, 5 (1.9 net) heavy oil wells, 1 (1.0 net) natural gas well and investing $2.5 million on facilities. Exploration and development expenditures of $123.1 million for Q1/2020 included costs associated with drilling 74 (71.2 net) light oil wells, 33 (33.0 net) heavy oil wells, 6 (6.0 net) stratigraphic exploration wells and investing $19.0 million on facilities.

Total U.S. exploration and development expenditures were $41.1 million for Q1/2021 which is $12.6 million lower than $53.7 million for Q1/2020. Exploration and development expenditures included costs associated with drilling 25 (7.4 net) wells along with 24 (7.0 net) wells that were brought on production. Exploration and development expenditures of $53.7 million for Q1/2020 included costs associated with drilling 17 (3.8 net) wells along with 30 (6.1 net) wells that were brought on production. Expenditures for Q1/2021 were lower than Q1/2020 due to the timing of development activity along with a reduction in drilling and completion costs.

Our 2021 revised annual guidance range of $285 - $315 million reflects additional capital spending on our light and heavy oil assets during the fourth quarter.

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management involves maintaining 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, 2021, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables and the credit facilities.

The capital-intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing capital programs. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties. We believe that internally generated adjusted funds flow and availability under our credit facilities will provide sufficient liquidity to fund our planned capital expenditures. Adjusted funds flow depends on a number of factors, including commodity prices, production and sales volumes, royalties, operating expenses, taxes and foreign exchange rates. In order to manage our capital structure and liquidity, we may from time-to-time issue or repurchase equity or debt securities,

enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.

Management of debt levels is a priority for Baytex in order to sustain operations and support our long-term plans. At March 31, 2021, net debt of $1.76 billion was $88.7 million lower than $1.85 billion at December 31, 2020. The decrease in net debt is primarily a result of free cash flow of $70.5 million generated during Q1/2021 along with an $18.1 million decrease in the reported amount of our U.S. dollar denominated net debt due to the strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2021 compared to December 31, 2020.

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, 2021, our net debt to adjusted funds flow ratio was 5.2 compared to a ratio of 5.9 as at December 31, 2020. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2020 is attributed to a $88.7 million decrease in net debt as at March 31, 2021 combined with higher adjusted funds flow for the twelve months ended March 31, 2021.

Credit Facilities

At March 31, 2021, the principal amount of credit facilities and letters of credit outstanding was $621.5 million under our credit facilities that total approximately $1.0 billion. Our credit facilities include US$575 million of revolving credit facilities and a $300 million non-revolving term loan (collectively, the "Credit Facilities"). Our Credit Facilities mature on April 2, 2024 and will automatically be extended to June 4, 2024 providing we have either refinanced, or have the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

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 London Interbank Offered Rates ("LIBOR"), plus applicable margins.

The LIBOR benchmark transition begins on December 31, 2021. Certain tenors of the U.S. dollar LIBOR benchmark will no longer be published as of December 31, 2021 while some tenors will continue to be published through mid-2023. We expect the U.S. dollar LIBOR benchmarks to be replaced with an alternative that will apply to our U.S. dollar borrowing at our option. We do not expect this change to have a material impact to Baytex as U.S. dollar borrowings under the credit facilities can also bear interest at the U.S. base loan rate.

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 2.1% for Q1/2021 compared to 3.4% for Q1/2020.

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at March 31, 2021.

Covenant Description			Position as at March 31, 2021			Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)			1.4:1.0			3.5:1.0
Interest Coverage (3) (Minimum Ratio)			4.3:1.0			2.0:1.0

(1)"Senior Secured Debt" is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at March 31, 2021, the Company's Senior Secured Debt totaled $621.5 million which includes $606.6 million of principal amounts outstanding and $14.9 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 (including depletion, depreciation, exploration and evaluation expenses, impairment, deferred income tax expense and recovery, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) 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, 2021 was $437.1 million.

(3)"Interest coverage" is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve-month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended March 31, 2021 were $102.0 million.

Long-Term Notes

We have two series of long-term notes outstanding that total $1.1 billion as at March 31, 2021. The long-term notes do not contain any financial maintenance covenants but contain a debt incurrence covenant that restricts our ability to raise additional debt beyond our existing Credit Facilities and long-term notes.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "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"), which remain outstanding. The 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at par from June 1, 2022 to maturity.

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. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million.

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, 2021, we issued 2.9 million common shares pursuant to our share-based compensation program. As at April 29, 2021, we had 564.1 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. These obligations are of a recurring nature and impact our adjusted funds flow in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of March 31, 2021 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			$	178,207		$	178,207		$	—		$	—		$	—
Credit facilities (1) (2)			606,637			—			—			606,637			—
Long-term notes (2)			1,131,480			—			—			502,880			628,600
Interest on long-term notes (3)			419,905			83,290			166,579			114,732			55,304
Lease agreements (2)			10,473			4,521			3,715			2,237			—
Processing agreements			6,153			836			1,171			473			3,673
Transportation agreements			93,957			18,214			39,710			21,952			14,081
Total			$	2,446,812		$	285,068		$	211,175		$	1,248,911		$	701,658

(1)The credit facilities mature on April 2, 2024. Maturity will automatically be extended to June 4, 2024 providing Baytex has either refinanced, or has the ability to repay, the outstanding 2024 long-term notes with existing credit capacity as of April 1, 2024.

(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 2021 MD&A    15

QUARTERLY FINANCIAL INFORMATION

			2021			2020												2019
($ thousands, except per common share amounts)			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Petroleum and natural gas sales			384,702			233,636			252,538			152,689			336,614			445,895			424,600			482,000
Net income (loss)			(35,352)			221,160			(23,444)			(138,463)			(2,498,217)			(117,772)			15,151			78,826
Per common share - basic			(0.06)			0.39			(0.04)			(0.25)			(4.46)			(0.21)			0.03			0.14
Per common share - diluted			(0.06)			0.39			(0.04)			(0.25)			(4.46)			(0.21)			0.03			0.14
Adjusted funds flow			156,582			82,176			78,508			17,887			132,935			232,147			213,379			236,130
Per common share - basic			0.28			0.15			0.14			0.03			0.24			0.42			0.38			0.42
Per common share - diluted			0.28			0.15			0.14			0.03			0.24			0.42			0.38			0.42
Exploration and development			83,588			77,809			15,902			9,852			176,777			153,117			139,085			106,246
Canada			42,503			45,030			3,882			2,929			123,110			104,460			96,774			68,259
U.S.			41,085			32,779			12,020			6,923			53,667			48,657			42,311			37,987
Acquisitions, net of divestitures			(203)			(33)			(98)			(11)			(40)			563			(30)			1,647
Net debt			1,758,894			1,847,601			1,906,079			1,994,953			2,051,617			1,871,791			1,971,339			2,028,686
Total assets			3,338,408			3,408,096			3,156,414			3,267,820			3,441,040			5,914,083			6,233,875			6,222,190
Common shares outstanding			564,111			561,227			561,163			560,545			560,483			558,305			557,972			556,798
Daily production
Total production (boe/d)			78,780			70,475			77,814			72,508			98,452			96,360			94,927			98,402
Canada (boe/d)			52,039			45,321			49,164			37,691			62,262			57,794			58,134			58,580
U.S. (boe/d)			26,741			25,154			28,650			34,817			36,190			38,566			36,793			39,822
Benchmark prices
WTI oil (US$/bbl)			57.84			42.66			40.93			27.85			46.17			56.96			56.45			59.81
WCS heavy ($/bbl)			57.46			43.46			42.40			22.70			34.48			54.29			58.39			65.73
Edmonton Light ($/bbl)			66.58			50.24			49.83			29.85			51.43			58.10			68.41			73.84
CAD/USD avg exchange rate			1.2663			1.3031			1.3316			1.3860			1.3445			1.3201			1.3207			1.3376
AECO gas ($/mcf)			2.93			2.77			2.18			1.91			2.14			2.34			1.04			1.17
NYMEX gas (US$/mmbtu)			2.69			2.66			1.98			1.72			1.95			2.50			2.23			2.64
Sales price ($/boe)			51.84			34.35			33.79			22.31			35.19			48.25			47.14			51.49
Royalties ($/boe)			(9.44)			(5.83)			(5.59)			(4.42)			(6.33)			(8.72)			(8.59)			(9.67)
Operating expense ($/boe)			(11.36)			(12.30)			(10.26)			(11.17)			(11.66)			(11.23)			(11.15)			(11.22)
Transportation expense ($/boe)			(1.24)			(1.03)			(0.89)			(0.76)			(1.15)			(1.00)			(1.13)			(1.33)
Operating netback ($/boe)			29.80			15.19			17.05			5.96			16.05			27.30			26.27			29.27
Financial derivatives gain (loss) ($/boe)			(2.93)			2.64			(1.36)			2.06			3.00			2.59			2.39			1.45
Operating netback after financial derivatives ($/boe)			26.87			17.83			15.69			8.02			19.05			29.89			28.66			30.72

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 was relatively consistent from Q2/2019 to Q1/2020 as relatively stable crude oil prices supported an active development program in Canada and the U.S. until the sharp decline in crude oil prices in March 2020 when we shut-in production in Canada and moderated the pace of activity in the U.S. Commodity prices began to recover in Q4/2020 and have strengthened in Q1/2021 which supported increased development activity and resulted in production of 78,780 boe/d for Q1/2021.

North American benchmark commodity prices were stable throughout 2019 and relatively strong leading into Q1/2020 with the West Texas Intermediate ("WTI") benchmark price averaging US$57.53/bbl in January 2020. 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

Baytex Energy Corp.                                            

Q1 2021 MD&A    16

relaxed. Commodity prices continued to recover in Q1/2021 with WTI averaging US$57.84/bbl as the outlook for demand improved with increasing global mobility. The impact of increased commodity prices is reflected in our realized sales price of $51.84/boe for Q1/2021 which is our strongest realized pricing since Q2/2019.

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 Q1/2021 compared to lows in 2020 due to strong price realizations and our ongoing efforts to control operating and transportation costs.

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 has decreased from $2.03 billion at Q2/2019 to $1.76 billion at Q1/2021 as free cash flow of $387.4 million generated over the last eight quarters was 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 1.3091 CAD/USD at Q2/2019 to 1.2572 CAD/USD at Q1/2021.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2021, 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, 2021. 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, 2020.

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. However, provided that Baytex remains listed on the TSX and the average daily trading volume of Baytex’s common shares in the U.S. is less than 5% of Baytex’s worldwide average daily trading volume over the 12-month period following the delisting, Baytex may be eligible to deregister its common shares at that time. Deregistration of Baytex's common shares would terminate its reporting obligations under the Securities Exchange Act of 1934, as amended.

NON-GAAP AND CAPITAL MEASUREMENT MEASURES

In this MD&A, we refer to certain capital management measures (such as adjusted funds flow, exploration and development expenditures, free cash flow, net debt, operating netback and Bank EBITDA) which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). While adjusted funds flow, exploration and development expenditures, free cash flow, net debt, operating netback and Bank EBITDA 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. We believe that inclusion of these non-GAAP financial measures provide useful information to investors and shareholders when evaluating the financial results of the Company.

Adjusted Funds Flow

We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations and potential future dividends. In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our operations on a continuing basis.

Adjusted funds flow should not be construed as an alternative to performance measures determined in accordance with GAAP, such as cash flow from operating activities and net income or loss.

Baytex Energy Corp.                                            

Q1 2021 MD&A    17

The following table reconciles cash flow from operating activities to adjusted funds flow.

			Three Months Ended March 31
($ thousands)			2021			2020
Cash flow from operating activities			$	120,980		$	182,567
Change in non-cash working capital			34,185			(53,873)
Asset retirement obligations settled			1,417			4,241
Adjusted funds flow			$	156,582		$	132,935

Exploration and Development Expenditures

We use exploration and development expenditures to measure and evaluate the performance of our capital programs. The total amount of exploration and development expenditures is managed as part of our budgeting process and can vary from period to period depending on the availability of adjusted funds flow and other sources of liquidity. We eliminate changes in non-cash working capital, acquisition and dispositions, and additions to other plant and equipment from investing activities as these amounts are generated by activities outside of our programs to explore and develop our existing properties.

Changes in non-cash working capital are eliminated in the determination of exploration and development expenditures as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our operations on a continuing basis. Our capital budgeting process is focused on programs to explore and develop our existing properties, accordingly, cash flows arising from acquisition and disposition activities are eliminated as we analyze these activities on a transaction by transaction basis separately from our analysis of the performance of our capital programs. Additions to other plant and equipment is primarily comprised of expenditures on corporate assets which do not generate incremental oil and natural gas production and are therefore analyzed separately from our evaluation of the performance of our exploration and development programs.

The following table reconciles cash flow used in investing activities to exploration and development expenditures.

			Three Months Ended March 31
($ thousands)			2021			2020
Cash flow used in investing activities			$	77,177		$	161,022
Change in non-cash working capital			6,299			16,327
Proceeds from dispositions			228			40
Property acquisitions			(25)			—
Additions to other plant and equipment			(91)			(612)
Exploration and development expenditures			$	83,588		$	176,777

Free Cash Flow

We define free cash flow as adjusted funds flow less exploration and development expenditures (both non-GAAP measures defined above), payments on lease obligations and asset retirement obligations settled. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition opportunities.

The following table provides our computation of free cash flow.

			Three Months Ended March 31
($ thousands)			2021			2020
Adjusted funds flow			$	156,582		$	132,935
Exploration and development expenditures			(83,588)			(176,777)
Payments on lease obligations			(1,082)			(1,516)
Asset retirement obligations settled			(1,417)			(4,241)
Free cash flow			$	70,495		$	(49,599)

Baytex Energy Corp.                                            

Q1 2021 MD&A    18

Net Debt

We believe that net debt assists in providing a more complete understanding of our financial position and provides a key measure to assess our liquidity. We calculate net debt based on the principal amounts of our credit facilities and long-term notes outstanding, including trade and other payables, cash, and trade and other receivables. We use the principal amounts of the credit facilities and long-term notes outstanding in the calculation of net debt as these amounts represent our total repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes are excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of liquidity or repayment obligation.

The following table summarizes our calculation of net debt.

($ thousands)			March 31, 2021			December 31, 2020
Credit facilities (1)			$	606,637		$	651,173
Long-term notes (1)			1,131,480			1,147,950
Trade and other payables			178,207			155,955
Trade and other receivables			(157,430)			(107,477)
Net debt			$	1,758,894		$	1,847,601

(1)Principal amount of instruments expressed in Canadian dollars.

Operating Netback

We define operating netback as petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation expense. Operating netback per boe is the operating netback divided by barrels of oil equivalent production volume for the applicable period. We believe that this measure assists in assessing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.

			Three Months Ended March 31
($ thousands)			2021			2020
Petroleum and natural gas sales			$	384,702		$	336,614
Blending and other expense			(17,120)			(21,357)
Total sales, net of blending and other expense			367,582			315,257
Royalties			(66,950)			(56,720)
Operating expense			(80,548)			(104,470)
Transportation expense			(8,788)			(10,342)
Operating netback			211,296			143,725
Realized financial derivative (loss) gain			(20,768)			26,850
Operating netback after realized financial derivatives			$	190,528		$	170,575

Baytex Energy Corp.                                            

Q1 2021 MD&A    19

Bank EBITDA

Bank EBITDA is used to assess compliance with certain financial covenants contained in our credit facility agreements. Net income is adjusted for the items set forth in the table below as prescribed by the credit facility agreements. The following table reconciles net income or loss to Bank EBITDA on a twelve month rolling basis.

			Twelve Months Ended March 31
($ thousands)			2021			2020
Net income (loss)			$	23,901		$	(2,522,012)
Plus:
Financing and interest			113,671			132,343
Unrealized foreign exchange (gain) loss			(92,819)			63,709
Unrealized financial derivatives loss (gain)			200,479			(66,439)
Current income tax (recovery) expense			(55)			1,967
Deferred income tax expense (recovery)			127,876			(337,249)
Depletion and depreciation			407,006			727,718
Gain on dispositions			(4,470)			(2,375)
Impairment			(356,129)			2,904,171
Non-cash items (1)			17,659			18,614
Bank EBITDA			$	437,119		$	920,447

(1)Non-cash items include share-based compensation, exploration and evaluation expense, note redemption premiums, interest on lease obligations, and non-cash other income.

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, 2021.

Baytex Energy Corp.                                            

Q1 2021 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 2021 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; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures; that a significant portion of our financial obligations will be funded by adjusted funds flow; that we intend to deregister our shares with the U.S. Securities and Exchange Commission if eligible.

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); availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our Eagle Ford properties; the cost of developing and operating our assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves; new regulations on hydraulic fracturing; restrictions on or access to water or other fluids; changes in government regulations that affect the oil and gas industry; regulations regarding the disposal of fluids; changes in environmental, health and safety regulations; public perception and its influence on the regulatory regime; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; alternatives to and changing demand for petroleum products; risks associated with our use of information technology systems; 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, 2020, 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.