EX-99.2 3 a992-q32021mda.htm EX-99.2

Document

Baytex Energy Corp.                                            

Q3 2021 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2021 and 2020

Dated November 4, 2021

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2021. This information is provided as of November 4, 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 and nine months ended September 30, 2021 ("Q3/2021" and "YTD 2021") have been compared with the results for the three and nine months ended September 30, 2020 ("Q3/2020" and "YTD 2020"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 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 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.

THIRD QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results for Q3/2021 as the global economy continued to recover from the impact of the COVID-19 pandemic. The outlook for crude oil demand has improved with the increase in economic activity due to the distribution of vaccines and easing of restrictions. Oil prices were also supported by ongoing OPEC production curtailments and limited supply growth from large independent producers. As a result, the average WTI benchmark price for Q3/2021 was US$70.56/bbl which was US$29.63/bbl higher than Q3/2020 when WTI averaged US$40.93/bbl. With higher commodity prices, we generated adjusted funds flow of $198.4 million and free cash flow of $101.2 million which contributed to a $65.0 million reduction in net debt from Q2/2021. Strong well performance across all of our assets resulted in production of 79,872 boe/d which was at the high end of our annual guidance range of 79,000 - 80,000 boe/d. 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.

Exploration and development expenditures were $94.2 million for Q3/2021 and were focused on our Canadian operations where we spent $75.5 million. In Canada, we drilled 19 (18.7 net) heavy oils wells, including 2 (2.0 net) additional appraisal wells in our developing Clearwater play and 26 (25.0 net) light oil wells during Q3/2021 which resulted in production of 48,124 boe/d that increased 919 boe/d from Q2/2021. After an active first half we moderated the pace of capital activity in the U.S. which resulted in production of 31,748 boe/d in Q3/2021 compared to 33,957 boe/d boe/d in Q2/2021. In Q3/2021, we brought 17 (3.4 net) wells on production and spent $18.7 million compared to Q2/2021 where we brought 38 (10.2 net) wells on stream.

Adjusted funds flow of $198.4 million in Q3/2021 was $119.9 million higher than Q3/2020 and $22.5 million higher than Q2/2021 as a result of higher benchmark prices. The increase in crude oil prices was the primary factor that resulted in a $164.6 million increase in operating netback for Q3/2021 relative to Q3/2020. Our strong operating and financial results contributed to net income of $32.7 million for Q3/2021 compared to a net loss of $23.4 million for Q3/2020.

Baytex Energy Corp.                                            

Q3 2021 MD&A    2

We used our free cash flow of $284.2 million generated during the nine months ended September 30, 2021 to reduce our debt. Net debt decreased $282.9 million to $1.56 billion at September 30, 2021 compared to $1.85 billion at December 31, 2020. As part of our debt reduction during YTD 2021 we repurchased and cancelled US$115.5 million of the 5.625% Notes due in 2024 and subsequent to Q3/2021 we repurchased and cancelled an additional US$84.5 million of these notes on October 29, 2021. Following these repurchases US$200.0 million of the 5.625% Notes remain outstanding.

2021 GUIDANCE

The following table compares our revised 2021 annual guidance to our previously announced guidance. As a result of our strong operational performance during the first nine months of 2021 we are tightening our annual production guidance range to 79,500 - 80,000 boe/d, up from 79,000 - 80,000 boe/d, previously. Our 2021 Clearwater appraisal program has delivered production results beyond our initial expectations. As a result, we have committed to drill up to four additional Clearwater wells during the fourth quarter with the wells expected to be on production in late 2021 and early 2022. Accordingly, we are tightening our forecasted 2021 exploration and development expenditures guidance range to $300 - $315 million from $285 - $315 million, previously.

We have also refined our cost assumptions along with our interest expense guidance which is 3% lower due to reduced net debt and the repurchase and cancellation of a portion of the 5.625% Notes. Our revised royalty rate guidance is slightly higher as commodity prices have exceeded our expectations which has resulted in slightly higher royalty rates for our Canadian production.

			Previous Annual Guidance (1)			Revised Annual Guidance
Exploration and development expenditures			$285 - $315 million			$300 - $315 million
Production (boe/d)			79,000 - 80,000			79,500 - 80,000
Expenses:
Royalty rate			18.0% - 18.5%			18.5% - 19.0%
Operating			$11.25 - $12.00/boe			$11.25 - $11.75/boe
Transportation			$1.15 - $1.25/boe			$1.10 - $1.15/boe
General and administrative			$42 million ($1.45/boe)			$42 million ($1.44/boe)
Interest			$95 million ($3.27/boe)			$92 million ($3.16/boe)
Leasing expenditures			$4 million			no change
Asset retirement obligations			$6 million			no change

(1)     As announced on July 28, 2021.

Baytex Energy Corp.                                            

Q3 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 September 30
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate			16,532			19,082			35,614			18,248			15,853			34,101
Heavy oil			21,996			—			21,996			22,138			—			22,138
Natural Gas Liquids (NGL)			1,230			5,944			7,174			1,281			6,136			7,417
Total liquids (bbl/d)			39,758			25,026			64,784			41,667			21,989			63,656
Natural gas (mcf/d)			50,197			40,331			90,528			44,980			39,965			84,945
Total production (boe/d)			48,124			31,748			79,872			49,164			28,650			77,814
Production Mix
Segment as a percent of total			60		%	40		%	100		%	63		%	37		%	100		%
Light oil and condensate			34		%	60		%	45		%	37		%	55		%	44		%
Heavy oil			46		%	—		%	28		%	45		%	—		%	28		%
NGL			3		%	19		%	9		%	3		%	22		%	10		%
Natural gas			17		%	21		%	18		%	15		%	23		%	18		%
			Nine Months Ended September 30
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate			17,130			18,930			36,060			20,409			19,161			39,570
Heavy oil			21,752			—			21,752			20,946			—			20,946
Natural Gas Liquids (NGL)			1,657			5,338			6,995			1,178			6,446			7,624
Total liquids (bbl/d)			40,539			24,268			64,807			42,533			25,607			68,140
Natural gas (mcf/d)			51,416			39,396			90,812			43,028			45,574			88,602
Total production (boe/d)			49,108			30,834			79,942			49,704			33,203			82,907
Production Mix
Segment as a percent of total			61		%	39		%	100		%	60		%	40		%	100		%
Light oil and condensate			35		%	61		%	45		%	41		%	58		%	48		%
Heavy oil			44		%	—		%	27		%	42		%	—		%	25		%
NGL			3		%	17		%	9		%	2		%	19		%	9		%
Natural gas			18		%	22		%	19		%	15		%	23		%	18		%

Production was 79,872 boe/d for Q3/2021 and 79,942 boe/d for YTD 2021 compared to 77,814 boe/d for Q3/2020 and 82,907 boe/d for YTD 2020. Total production was higher in Q3/2021 compared to Q3/2020 due to increased development activity in Canada and the U.S. during 2021 following the reset of our business in 2020. Total production of 79,942 boe/d for YTD 2021 is at the high end of our revised annual guidance of 79,500 - 80,000 and reflects the strong well performance in the U.S. and Canada.

Baytex Energy Corp.                                            

Q3 2021 MD&A    4

In Canada, production of 48,124 boe/d for Q3/2021 and 49,108 boe/d for YTD 2021 was relatively consistent with 49,164 boe/d for Q3/2020 and 49,704 boe/d for YTD 2020. Strong well performance from our successful 2021 development program has restored production for Q3/2021 and YTD 2021 to levels that are relatively consistent with the comparative periods after development activity was limited throughout 2020.

In the U.S., production of 31,748 boe/d for Q3/2021 was higher than 28,650 boe/d for Q3/2020 as development activity in the U.S. increased during Q4/2020 and we continued this pace of development into 2021. Production of 30,834 boe/d during YTD 2021 was lower than 33,203 boe/d for YTD 2020 due to limited development activity during 2020 following the sharp decline in oil prices during Q2/2020. We initiated production from 17 (3.4 net) wells and 79 (20.6 net) wells during Q3/2021 and YTD 2021 respectively compared to 6 (0.8 net) wells and 53 (11.5 net) wells during the comparative periods in 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 Q3/2021. Oil supply has been impacted by OPEC production curtailments and limited production growth from large independent producers while the outlook for 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$70.56/bbl for Q3/2021 and US$64.82/bbl for YTD 2021 which was higher relative to Q3/2020 and YTD 2020 when WTI averaged US$40.93/bbl and US$38.32/bbl, respectively.

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$71.64/bbl during Q3/2021 and US$66.05/bbl during YTD 2021 which is higher than the price achieved in 2020 when the benchmark was US$41.63/bbl during Q3/2020 and US$39.19/bbl during YTD 2020. The MEH benchmark traded at a premium to WTI of US$1.08/bbl in Q3/2021 and a US$1.23/bbl premium YTD 2021 compared to a US$0.70/bbl premium to WTI during Q3/2020 and US$0.87/bbl premium YTD 2020.

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 $83.78/bbl during Q3/2021 and $75.88/bbl during YTD 2021 compared to $49.83/bbl during Q3/2020 and $43.70/bbl during YTD 2020. Edmonton par traded at a discount to WTI of US$4.07/bbl for Q3/2021 and US$4.19/bbl for YTD 2021 compared to a discount of US$3.51/bbl for Q3/2020 and US$6.04/bbl for YTD 2020.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q3/2021 and YTD 2021 averaged $71.81/bbl and $65.47/bbl, respectively, compared to $42.40/bbl and $33.34/bbl for the same periods of 2020. The WCS heavy oil differential was US$13.57/bbl in Q3/2021 and US$12.51/bbl in YTD 2021 compared to US$9.09/bbl for Q3/2020 and US$13.70/bbl for YTD 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$4.01/mmbtu for Q3/2021 and US$3.18/mmbtu for YTD 2021 which is higher than US$1.98/mmbtu for Q3/2020 and US$1.88/mmbtu for YTD 2020. Strong demand and lower U.S. production resulted in reduced natural gas inventory levels which contributed to higher NYMEX benchmark prices for YTD 2021 relative to YTD 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 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 2021 relative to 2020. The AECO benchmark averaged $3.54/mcf during Q3/2021 and $3.11/mcf during YTD 2021 which is higher than $2.18/mcf for Q3/2020 and $2.08/mcf for YTD 2020.

Baytex Energy Corp.                                            

Q3 2021 MD&A    5

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30									Nine Months Ended September 30
			2021			2020			Change			2021			2020			Change
Benchmark Averages
WTI oil (US$/bbl) (1)			70.56			40.93			29.63			64.82			38.32			26.50
MEH oil (US$/bbl) (2)			71.64			41.63			30.01			66.05			39.19			26.86
MEH oil differential to WTI (US$/bbl)			1.08			0.70			0.38			1.23			0.87			0.36
Edmonton par oil ($/bbl) (3)			83.78			49.83			33.95			75.88			43.70			32.18
Edmonton par oil differential to WTI (US$/bbl)			(4.07)			(3.51)			(0.56)			(4.19)			(6.04)			1.85
WCS heavy oil ($/bbl) (4)			71.81			42.40			29.41			65.47			33.34			32.13
WCS heavy oil differential to WTI (US$/bbl)			(13.57)			(9.09)			(4.48)			(12.51)			(13.70)			1.19
AECO natural gas price ($/mcf) (5)			3.54			2.18			1.36			3.11			2.08			1.03
NYMEX natural gas price (US$/mmbtu) (6)			4.01			1.98			2.03			3.18			1.88			1.30
CAD/USD average exchange rate			1.2601			1.3316			(0.0715)			1.2515			1.3541			(0.1026)

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

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

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

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

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

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

			Three Months Ended September 30
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)			$	82.14		$	88.01		$	85.29		$	46.72		$	51.85		$	49.10
Heavy oil ($/bbl) (1)			62.70			—			62.70			29.03			—			29.03
NGL ($/bbl)			36.92			41.94			41.08			14.95			15.79			15.65
Natural gas ($/mcf)			3.71			5.00			4.29			2.14			2.50			2.31
Weighted average ($/boe) (1)			$	61.69		$	67.11		$	63.85		$	32.76		$	35.55		$	33.79
			Nine Months Ended September 30
			2021									2020
			Canada			U.S.			Total			Canada			U.S.			Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)			$	73.29		$	80.98		$	77.33		$	41.08		$	49.11		$	44.97
Heavy oil ($/bbl) (1)			55.34			—			55.34			23.03			—			23.03
NGL ($/bbl)			27.25			36.28			34.14			12.27			14.60			14.24
Natural gas ($/mcf)			3.26			5.42			4.20			2.01			2.50			2.26
Weighted average ($/boe) (1)			$	54.41		$	62.92		$	57.69		$	28.60		$	34.61		$	31.01

(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 $63.85/boe for Q3/2021 and $57.69/boe for YTD 2021 compared to $33.79/boe for Q3/2020 and $31.01/boe for YTD 2020. In Canada, our realized price of $61.69/boe for Q3/2021 was $28.93/boe higher than $32.76/boe for Q3/2020. Our realized price in the U.S. was $67.11/boe in Q3/2021 which is $31.56/boe higher than $35.55/boe in Q3/2020. The increase in our realized price in Canada and the U.S. for Q3/2021 and YTD 2021 was a result of higher North American benchmark prices relative to the same periods of 2020.

Baytex Energy Corp.                                            

Q3 2021 MD&A    6

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $82.14/bbl for Q3/2021 and $73.29/bbl for YTD 2021 compared to $46.72/bbl for Q3/2020 and $41.08/bbl for YTD 2020. Our realized light oil and condensate price for Q3/2021 and YTD 2021 increased with the improvement in the benchmark price and represents discounts of $1.64/bbl and $2.59/bbl, respectively, to the Edmonton par price, compared to discounts of $3.11/bbl for Q3/2020 and $2.62/bbl for YTD 2020. Our realized light oil price for both periods of 2021 represents a narrower discount to the Edmonton par price than comparative periods of 2020 and reflects strong regional pricing for our Viking light oil production relative to the Edmonton par benchmark during 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 $88.01/bbl for Q3/2021 and $80.98/bbl for YTD 2021 compared to $51.85/bbl for Q3/2020 and $49.11/bbl for YTD 2020. Expressed in U.S. dollars, our realized light oil and condensate price of US$69.84/bbl for Q3/2021 and US$64.71/bbl for YTD 2021 represents discounts to MEH of US$1.80/bbl and US$1.34/bbl, respectively. Strong condensate pricing has resulted in improved price realizations for both periods of 2021 relative to Q3/2020 and YTD 2020 when our discount to MEH was US$2.69/bbl and US$2.92/bbl, respectively.

Our realized heavy oil price, net of blending and other expense averaged $62.70/bbl in Q3/2021 and $55.34/bbl in YTD 2021 compared to $29.03/bbl in Q3/2020 and $23.03/bbl in YTD 2020. Our realized heavy oil price for Q3/2021 and YTD 2021 was $33.67/bbl and $32.31/bbl higher relative to Q3/2020 and YTD 2020 compared to a $29.41/bbl and $32.13/bbl increase in the WCS benchmark price relative to Q3/2020. The increase in our realized heavy oil price for YTD 2021 was relatively consistent with change in WCS benchmark pricing relative to YTD 2020 while our realized heavy oil price for Q3/2021 improved more than the increase in the WCS benchmark due to reduced volumes and improved price realizations on our rail deliveries in 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 $41.08/bbl in Q3/2021 or 46% of WTI (expressed in Canadian dollars) compared to $15.65/bbl or 29% of WTI (expressed in Canadian dollars) in Q3/2020. Our realized NGL price was $34.14/bbl in YTD 2021 or 42% of WTI (expressed in Canadian dollars) compared to $14.24/bbl or 27% of WTI (expressed in Canadian dollars) in YTD 2020. Our realized NGL price was higher as a percentage of WTI in Q3/2021 and YTD 2021 relative to the same periods of 2020 due to strong global demand and lower supply of NGLs in 2021.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $3.71/mcf for Q3/2021 and $3.26/mcf for YTD 2021 compared to $2.14/mcf in Q3/2020 and $2.01/mcf for YTD 2020. 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$3.97/mcf for Q3/2021 and US$4.33/mcf for YTD 2021 compared to US$1.88/mcf for Q3/2020 and US$1.85/mcf for YTD 2020. A portion of our natural gas production is based on the NYMEX daily index which resulted in a US$1.15/mcf premium for our realized natural gas price when compared to the NYMEX monthly benchmark for YTD 2021 due to the fluctuations in the daily index caused by severe events which disrupted supply and caused increased demand on the U.S. Gulf coast during 2021.

Baytex Energy Corp.                                            

Q3 2021 MD&A    7

PETROLEUM AND NATURAL GAS SALES

			Three Months Ended September 30
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Oil sales
Light oil and condensate			$	124,930		$	154,511		$	279,441		$	78,432		$	75,620		$	154,052
Heavy oil			146,468			—			146,468			69,791			—			69,791
NGL			4,177			22,932			27,109			1,762			8,914			10,676
Total oil sales			275,575			177,443			453,018			149,985			84,534			234,519
Natural gas sales			17,148			18,570			35,718			8,846			9,173			18,019
Total petroleum and natural gas sales			292,723			196,013			488,736			158,831			93,707			252,538
Blending and other expense			(19,581)			—			(19,581)			(10,673)			—			(10,673)
Total sales, net of blending and other expense			$	273,142		$	196,013		$	469,155		$	148,158		$	93,707		$	241,865
			Nine Months Ended September 30
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Oil sales
Light oil and condensate			$	342,744		$	418,498		$	761,242		$	229,745		$	257,818		$	487,563
Heavy oil			385,288			—			385,288			169,638			—			169,638
NGL			12,327			52,870			65,197			3,957			25,791			29,748
Total oil sales			740,359			471,368			1,211,727			403,340			283,609			686,949
Natural gas sales			45,812			58,253			104,065			23,660			31,232			54,892
Total petroleum and natural gas sales			786,171			529,621			1,315,792			427,000			314,841			741,841
Blending and other expense			(56,668)			—			(56,668)			(37,490)			—			(37,490)
Total sales, net of blending and other expense			$	729,503		$	529,621		$	1,259,124		$	389,510		$	314,841		$	704,351

Total sales, net of blending and other expense, of $469.2 million for Q3/2021 increased $227.3 million from $241.9 million reported for Q3/2020 while total sales, net of blending and other expense, of $1,259.1 million for YTD 2021 increased $554.8 million from $704.4 million reported for YTD 2020. The increase in total sales in both periods is a result of higher realized pricing due to the increase in benchmark pricing.

In Canada, total sales, net of blending and other expense, was $273.1 million for Q3/2021 which is an increase of $125.0 million from $148.2 million reported for Q3/2020. The increase in total petroleum and natural gas sales was due to higher realized pricing for Q3/2021 relative to Q3/2020. Our increased realized price resulted in a $128.1 million increase in total sales, net of blending and other expense, while slightly lower production resulted in a $3.1 million decrease in total sales, net of blending and other expense, relative to Q3/2020. Despite lower production, the increase in benchmark prices resulted in our total sales, net of blending and other expense, increasing to $729.5 million in YTD 2021 from $389.5 million in YTD 2020.

In the U.S., petroleum and natural gas sales were $196.0 million for Q3/2021 which is an increase of $102.3 million from $93.7 million reported for Q3/2020. Total petroleum and natural gas sales increased $92.2 million due to higher realized pricing for Q3/2021 relative to Q3/2020 while higher production resulted in a $10.1 million increase in total sales, net of blending and other expense relative to Q3/2020. Higher realized pricing in YTD 2021 resulted in petroleum and natural gas sales of $529.6 million which was $214.8 million higher than $314.8 million in YTD 2020 despite lower production in YTD 2021 relative to YTD 2020.

Baytex Energy Corp.                                            

Q3 2021 MD&A    8

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30
			2021									2020
($ thousands except for % and per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Royalties			$	32,679		$	57,844		$	90,523		$	12,297		$	27,755		$	40,052
Average royalty rate (1)			12.0		%	29.5		%	19.3		%	8.3		%	29.6		%	16.6		%
Royalties per boe			$	7.38		$	19.80		$	12.32		$	2.72		$	10.53		$	5.59
			Nine Months Ended September 30
			2021									2020
($ thousands except for % and per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Royalties			$	83,536		$	155,468		$	239,004		$	33,972		$	91,956		$	125,928
Average royalty rate (1)			11.5		%	29.4		%	19.0		%	8.7		%	29.2		%	17.9		%
Royalties per boe			$	6.23		$	18.47		$	10.95		$	2.49		$	10.11		$	5.54

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

Royalties for Q3/2021 were $90.5 million or 19.3% of total sales, net of blending and other expense compared to $40.1 million or 16.6% for Q3/2020. Total royalties for YTD 2021 were $239.0 million or 19.0% of total sales, net of blending and other expense, compared to $125.9 million or 17.9% for YTD 2020. Total royalty expense was higher for Q3/2021 and YTD 2021 due to higher total sales, net of blending and other expense, relative to the same periods of 2020. Our royalty rates of 19.3% for Q3/2021 and 19.0% for YTD 2021 were higher than 16.6% for Q3/2020 and 17.9% for YTD 2020 due to a higher royalty rate on our Canadian properties as a result of higher commodity prices. Our average royalty rate of 19.0% for YTD 2021 is slightly above our annual guidance range of 18.5% - 19.0% for 2021 due to higher than expected benchmark commodity prices and strong realized pricing in Canada.

Our Canadian royalty rates of 12.0% for Q3/2021 and 11.5% for YTD 2021 were higher than 8.3% for Q3/2020 and 8.7% for YTD 2020 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in 2021 relative to 2020. In the U.S., royalties averaged 29.5% and 29.4% of total sales for Q3/2021 and YTD 2021, respectively, which is consistent with 29.6% for Q3/2020 and 29.2% for YTD 2020 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

Baytex Energy Corp.                                            

Q3 2021 MD&A    9

OPERATING EXPENSE

			Three Months Ended September 30
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Operating expense			$	63,301		$	20,895		$	84,196		$	57,557		$	15,890		$	73,447
Operating expense per boe			$	14.30		$	7.15		$	11.46		$	12.73		$	6.03		$	10.26
			Nine Months Ended September 30
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Operating expense			$	186,455		$	61,190		$	247,645		$	185,641		$	65,956		$	251,597
Operating expense per boe			$	13.91		$	7.27		$	11.35		$	13.63		$	7.25		$	11.08

Total operating expense was $84.2 million ($11.46/boe) for Q3/2021 and $247.6 million ($11.35/boe) for YTD 2021 compared to $73.4 million ($10.26/boe) for Q3/2020 and $251.6 million ($11.08/boe) for YTD 2020. Total operating expense for Q3/2021 increased with production relative to Q3/2020 while total operating expense for YTD 2021 decreased with production relative to YTD 2020. Operating expense of $11.35/boe for YTD 2021 is consistent with expectations and is at the low end of our annual guidance range of $11.25 - $11.75/boe.

In Canada, operating expense was $63.3 million ($14.30/boe) for Q3/2021 and $186.5 million ($13.91/boe) for YTD 2021 compared to $57.6 million ($12.73/boe) for Q3/2020 and $185.6 million ($13.63/boe) for YTD 2020. Operating expense in Canada has increased for Q3/2021 and YTD 2021 relative to Q3/2020 and YTD 2021 due to an increase in per unit operating expenses as production was relatively consistent over the periods. The increase in per unit operating expense to $14.30/boe for Q3/2021 and $13.91/boe for YTD 2021 relative to $12.73/boe for Q3/2020 and $13.63/boe for YTD 2020 was primarily the result of reactivating higher cost production that was shut-in for a portion of 2020 along with an increase in fuel and electricity costs in 2021.

U.S. operating expense was $20.9 million ($7.15/boe) for Q3/2021 and $61.2 million ($7.27/boe) for YTD 2021 compared to $15.9 million ($6.03/boe) for Q3/2020 and $66.0 million ($7.25/boe) for YTD 2020. Higher operating expense in Q3/2021 is primarily a result of an increase in per unit operating expenses relative to Q3/2020 while a decrease in operating expense for YTD 2021 was a result of lower production relative to YTD 2020. Expressed in U.S. dollars, per unit operating expense was US$5.67/boe in Q3/2021 and US$5.81/boe for YTD 2021 which was higher than US$4.53/boe for Q3/2020 and US$5.35/boe for YTD 2020 which included a $3.7 million reimbursement of prior period charges. Per unit operating expense for Q3/2021 and YTD 2021 were relatively consistent with the same periods of 2020 excluding the impact of the reimbursement of prior period charges included in the comparative periods.

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 and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Transportation expense			$	7,818		$	—		$	7,818		$	6,372		$	—		$	6,372
Transportation expense per boe			$	1.77		$	—		$	1.06		$	1.41		$	—		$	0.89
			Nine Months Ended September 30
			2021									2020
($ thousands except for per boe)			Canada			U.S.			Total			Canada			U.S.			Total
Transportation expense			$	24,092		$	—		$	24,092		$	21,745		$	—		$	21,745
Transportation expense per boe			$	1.80		$	—		$	1.10		$	1.60		$	—		$	0.96

Baytex Energy Corp.                                            

Q3 2021 MD&A    10

Transportation expense was $7.8 million ($1.06/boe) for Q3/2021 and $24.1 million ($1.10/boe) for YTD 2021 compared to $6.4 million ($0.89/boe) for Q3/2020 and $21.7 million ($0.96/boe) for YTD 2020. The increase in total transportation expense in both periods of 2021 relative to 2020 is the result of a higher trucked volumes and higher per unit costs in 2021. Per unit transportation expense in Canada of $1.77/boe for Q3/2021 and $1.80/boe for YTD 2021 is higher than $1.41/boe for Q3/2020 and $1.60/boe for YTD 2020 which is a result of increased trucking distances in 2021 relative to 2020. Per unit transportation expense of $1.10/boe for YTD 2021 is consistent with expectations and was slightly below our revised annual guidance of $1.10 - $1.15/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 $19.6 million for Q3/2021 and $56.7 million for YTD 2021 compared to $10.7 million for Q3/2020 and $37.5 million for YTD 2020. Higher blending and other expense reflects an increase in the price of condensate purchased as diluent in 2021 relative to 2020.

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 and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands)			2021			2020			Change			2021			2020			Change
Realized financial derivatives gain (loss)
Crude oil			$	(50,384)		$	(9,530)		$	(40,854)		$	(108,658)		$	30,640		$	(139,298)
Natural gas			(3,521)			165			(3,686)			(5,039)			753			(5,792)
Interest and financing			—			(378)			378			—			(662)			662
Total			$	(53,905)		$	(9,743)		$	(44,162)		$	(113,697)		$	30,731		$	(144,428)
Unrealized financial derivatives gain (loss)
Crude oil			$	1,520		$	(717)		$	2,237		$	(165,019)		$	27,155		$	(192,174)
Natural gas			(13,190)			(6,885)			(6,305)			(22,475)			(5,826)			(16,649)
Interest and financing			—			372			(372)			—			(101)			101
Equity total return swap ("Equity TRS")			2,729			(54)			2,783			8,086			(1,803)			9,889
Total			$	(8,941)		$	(7,284)		$	(1,657)		$	(179,408)		$	19,425		$	(198,833)
Total financial derivatives gain (loss)
Crude oil			$	(48,864)		$	(10,247)		$	(38,617)		$	(273,677)		$	57,795		$	(331,472)
Natural gas			(16,711)			(6,720)			(9,991)			(27,514)			(5,073)			(22,441)
Interest and financing			—			(6)			6			—			(763)			763
Equity TRS			2,729			(54)			2,783			8,086			(1,803)			9,889
Total			$	(62,846)		$	(17,027)		$	(45,819)		$	(293,105)		$	50,156		$	(343,261)

We recorded total financial derivative losses of $62.8 million for Q3/2021 and $293.1 million for YTD 2021 compared to a loss of $17.0 million for Q3/2020 and a gain of $50.2 million for YTD 2020. Realized financial derivatives losses of $53.9 million for Q3/2021 and $113.7 million for YTD 2021 were primarily a result of the market prices for crude oil settling at levels above those set in our derivative contracts. Unrealized losses of $179.4 million for YTD 2021 were primarily a result of the increase in forecasted crude oil pricing used to revalue our crude oil contracts in place at September 30, 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 $201.1 million at September 30, 2021 compared to a net liability of $21.7 million at December 31, 2020.

Baytex Energy Corp.                                            

Q3 2021 MD&A    11

We had the following commodity financial derivative contracts as at November 4, 2021.

Period

Volume

Price/Unit (1)

Index

Oil

Basis Swap

Oct 2021 to Dec 2021

8,000 bbl/d

WTI less US$13.41/bbl

WCS

Basis Swap

Jan 2022 to Dec 2022

12,000 bbl/d

WTI less US$12.40/bbl

WCS

Basis Swap

Oct 2021 to Dec 2021

7,500 bbl/d

WTI less US$5.03/bbl

MSW

Basis Swap

Jan 2022 to Dec 2022

4,000 bbl/d

WTI less US$4.43/bbl

MSW

Fixed Sell

Oct 2021 to Dec 2021

4,000 bbl/d

US$45.00/bbl

WTI

3-way option (2)

Oct 2021 to Dec 2021

500 bbl/d

US$35.00/US$45.00/US$49.03

WTI

3-way option (2)

Oct 2021 to Dec 2021

1,500 bbl/d

US$35.00/US$45.00/US$49.10

WTI

3-way option (2)

Oct 2021 to Dec 2021

3,500 bbl/d

US$35.00/US$45.00/US$49.50

WTI

3-way option (2)

Oct 2021 to Dec 2021

10,000 bbl/d

US$35.00/US$45.00/US$55.00

WTI

3-way option (2)

Oct 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)

Jan 2022 to Dec 2022

2,500 bbl/d

US$47.00/US$57.00/US$67.00

WTI

3-way option (2)

Jan 2022 to Dec 2022

2,500 bbl/d

US$50.00/US$60.00/US$70.00

WTI

3-way option (2)

Jan 2022 to Dec 2022

2,000 bbl/d

US$53.00/US$63.50/US$72.90

WTI

3-way option (2)(4)

Jan 2023 to Dec 2023

2,000 bbl/d

US$55.00/US$66.00/US$84.00

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

Oct 2021 to Dec 2021

16,000 GJ/d

$2.36/GJ

AECO 7A

Fixed Sell

Jan 2022 to Dec 2022

5,000 GJ/d

$2.53/GJ

AECO 7A

Fixed Sell

Oct 2021 to Dec 2021

2,500 GJ/d

$2.40/GJ

AECO 5A

Fixed Sell

Jan 2022 to Dec 2022

14,250 GJ/d

$2.84/GJ

AECO 5A

Fixed Sell

Oct 2021 to Dec 2021

12,000 mmbtu/d

US$2.70/mmbtu

NYMEX

Fixed Sell

Jan 2022 to Dec 2022

1,000 mmbtu/d

US$2.94/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

1,500 mmbtu/d

US$2.60/US$2.91/US$3.56

NYMEX

3-way option (2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.60/US$3.00/US$3.83

NYMEX

3-way option (2)

Jan 2022 to Dec 2022

2,500 mmbtu/d

US$2.65/US$2.90/US$3.40

NYMEX

3-way option (2)

Jan 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.

(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 September 30, 2021.

Baytex Energy Corp.                                            

Q3 2021 MD&A    12

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30
			2021									2020
($ per boe except for volume)			Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)			48,124			31,748			79,872			49,164			28,650			77,814
Operating netback:
Total sales, net of blending and other expense			$	61.69		$	67.11		$	63.85		$	32.76		$	35.55		$	33.79
Less:
Royalties			(7.38)			(19.80)			(12.32)			(2.72)			(10.53)			(5.59)
Operating expense			(14.30)			(7.15)			(11.46)			(12.73)			(6.03)			(10.26)
Transportation expense			(1.77)			—			(1.06)			(1.41)			—			(0.89)
Operating netback			$	38.24		$	40.16		$	39.01		$	15.90		$	18.99		$	17.05
Realized financial derivatives (loss) gain			—			—			(7.34)			—			—			(1.36)
Operating netback after financial derivatives			$	38.24		$	40.16		$	31.67		$	15.90		$	18.99		$	15.69
			Nine Months Ended September 30
			2021									2020
($ per boe except for volume)			Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)			49,108			30,834			79,942			49,704			33,203			82,907
Operating netback:
Total sales, net of blending and other expense			$	54.41		$	62.92		$	57.69		$	28.60		$	34.61		$	31.01
Less:
Royalties			(6.23)			(18.47)			(10.95)			(2.49)			(10.11)			(5.54)
Operating expense			(13.91)			(7.27)			(11.35)			(13.63)			(7.25)			(11.08)
Transportation expense			(1.80)			—			(1.10)			(1.60)			—			(0.96)
Operating netback			$	32.47		$	37.18		$	34.29		$	10.88		$	17.25		$	13.43
Realized financial derivatives (loss) gain			—			—			(5.21)			—			—			1.35
Operating netback after financial derivatives			$	32.47		$	37.18		$	29.08		$	10.88		$	17.25		$	14.78

Our operating netback of $39.01/boe for Q3/2021 and $34.29/boe for YTD 2021 was higher than $17.05/boe for Q3/2020 and $13.43/boe for YTD 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 $12.52/boe for Q3/2021 and $12.45/boe for YTD 2021 was slightly higher than $11.15/boe for Q3/2020 and $12.04/boe for YTD 2020. Including realized gains and losses on financial derivatives our operating netback was $31.67/boe for Q3/2021 and $29.08/boe for YTD 2021 compared to $15.69/boe for Q3/2020 and $14.78/boe for YTD 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.

Baytex Energy Corp.                                            

Q3 2021 MD&A    13

The following table summarizes our G&A expense for the three and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for per boe)			2021			2020			Change			2021			2020			Change
Gross general and administrative expense			$	11,251		$	7,790		$	3,461		$	31,871		$	27,153		$	4,718
Overhead recoveries			(1,271)			(49)			(1,222)			(2,548)			(2,199)			(349)
General and administrative expense			$	9,980		$	7,741		$	2,239		$	29,323		$	24,954		$	4,369
General and administrative expense per boe			$	1.36		$	1.08		$	0.28		$	1.34		$	1.10		$	0.24

G&A expense was $10.0 million ($1.36/boe) for Q3/2021 and $29.3 million ($1.34/boe) for YTD 2021 compared to $7.7 million ($1.08/boe) for Q3/2020 and $25.0 million ($1.10/boe) for YTD 2020. G&A expense for Q3/2021 and YTD 2021 was higher relative to the same periods of 2020 as employee and director compensation was reduced from Q2/2020 to Q4/2020 and the Company received benefits under the Canadian Emergency Wage Subsidy program in 2020.

G&A expense of $1.34/boe for YTD 2021 is consistent with expectations and is slightly below our revised annual guidance of $1.44/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 and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for per boe)			2021			2020			Change			2021			2020			Change
Interest on credit facilities			$	3,256		$	3,366		$	(110)		$	9,842		$	11,749		$	(1,907)
Interest on long-term notes			19,481			21,943			(2,462)			60,734			69,231			(8,497)
Interest on lease obligations			56			109			(53)			$	174		$	360		(186)
Cash interest			$	22,793		$	25,418		$	(2,625)		$	70,750		$	81,340		$	(10,590)
Accretion of debt issue costs			1,733			756			977			3,272			5,863			(2,591)
Accretion of asset retirement obligations			3,273			1,788			1,485			8,938			6,897			2,041
Early redemption expense			1,229			—			1,229			872			3,312			(2,440)
Financing and interest expense			$	29,028		$	27,962		$	1,066		$	83,832		$	97,412		$	(13,580)
Cash interest per boe			$	3.10		$	3.55		$	(0.45)		$	3.24		$	3.58		$	(0.34)
Financing and interest expense per boe			$	3.95		$	3.91		$	0.04		$	3.84		$	4.29		$	(0.45)

Financing and interest expense was $29.0 million ($3.95/boe) for Q3/2021 and $83.8 million ($3.84/boe) for YTD 2021 compared to $28.0 million ($3.91/boe) for Q3/2020 and $97.4 million ($4.29/boe) for YTD 2020.

Cash interest of $22.8 million ($3.10/boe) for Q3/2021 and $70.8 million ($3.24/boe) for YTD 2021 is lower than $25.4 million ($3.55/boe) for Q3/2020 and $81.3 million ($3.58/boe) for YTD 2020 as we had less debt outstanding during 2021. The interest on our U.S. dollar denominated long-term notes was lower as the average principal amount outstanding was lower during YTD 2021 due to the repurchase and redemption of US$115.5 million of long-term notes in YTD 2021. Interest on our credit facilities was lower in Q3/2021 and YTD 2021 compared to the same periods of 2020 due to lower borrowings on our credit facilities and lower effective interest. The weighted average interest rate applicable to our credit facilities was 2.2% YTD 2021 compared to 2.5% for YTD 2020.

Financing and interest expense for YTD 2021 was lower than YTD 2020 which included the accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the redemption of notes in Q1/2020.

Cash interest expense of $70.8 million ($3.24/boe) for YTD 2021 is consistent with our revised annual guidance of $92 million ($3.16/boe) for 2021 given we expect interest expense to be lower for the remainder of 2021 due to the additional redemption of the 5.625% Notes on October 29, 2021.

Baytex Energy Corp.                                            

Q3 2021 MD&A    14

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 $6.8 million for Q3/2021 and $10.7 million for YTD 2021 which is lower than $8.9 million for Q3/2020 and $11.0 million for YTD 2020 as less acreage expired in both periods of 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 and nine months ended September 30, 2021 and 2020.

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for per boe)			2021			2020			Change			2021			2020			Change
Depletion			$	125,681		$	104,547		$	21,134		$	328,171		$	386,587		$	(58,416)
Depreciation			1,371			1,907			(536)			3,948			5,793			(1,845)
Depletion and depreciation			$	127,052		$	106,454		$	20,598		$	332,119		$	392,380		$	(60,261)
Depletion and depreciation per boe			$	17.29		$	14.87		$	2.42		$	15.22		$	17.27		$	(2.05)

Depletion and depreciation expense was $127.1 million ($17.29/boe) for Q3/2021 and $332.1 million ($15.22/boe) for YTD 2021 compared to $106.5 million ($14.87/boe) for Q3/2020 and $392.4 million ($17.27/boe) for YTD 2020. Total depletion and depreciation expense as well as the depletion rate per boe were higher in Q3/2021 relative to Q3/2020 as a result of a $1.1 billion impairment reversal recorded at Q2/2021 which increased the depletable base of our U.S and Canadian assets.

Total depletion and depreciation expense and the depletion rate per boe were lower in YTD 2021 compared to YTD 2020 as we recorded a $2.2 billion impairment loss to our oil and gas properties at Q1/2020 which reduced the depletable base of our oil and gas properties for YTD 2021 despite the $1.1 billion impairment reversal recorded at the end of Q2/2021.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at September 30, 2021.

2021 Impairment Reversal

At June 30, 2021, we identified indicators of impairment reversal for oil and gas properties in each of our six CGU's due to the increase in forecasted commodity prices. We recorded an impairment reversal of $1.1 billion as the estimated recoverable amount of all six CGUs exceeded their carrying value. No indicators of impairment or impairment reversal were identified for the Company's E&E assets at June 30, 2021.

At June 30, 2021, the recoverable amount of the Company's CGUs were calculated using the following benchmark reference prices for the years 2021 to 2030 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2030 have been adjusted for inflation at an annual rate of 2.0%.

			2021			2022			2023			2024			2025			2026			2027			2028			2029			2030
WTI crude oil (US$/bbl)			71.33			67.20			63.95			63.23			64.50			65.79			67.10			68.44			69.81			71.21
WCS heavy oil (CA$/bbl)			72.22			66.84			61.73			60.70			61.91			63.15			64.42			65.70			67.02			68.36
LLS crude oil (US$/bbl)			72.17			68.53			65.80			65.10			66.39			67.71			69.05			70.42			71.82			73.26
Edmonton par oil (CA$/bbl)			83.20			78.27			74.06			73.05			74.51			76.00			77.52			79.07			80.66			82.27
Henry Hub gas (US$/mmbtu)			3.42			3.19			2.92			2.96			3.02			3.08			3.14			3.21			3.27			3.34
AECO gas (CA$/mmbtu)			3.46			3.13			2.72			2.71			2.76			2.82			2.88			2.94			2.99			3.05
Exchange rate (CAD/USD)			1.24			1.25			1.25			1.25			1.25			1.25			1.25			1.25			1.25			1.25

Baytex Energy Corp.                                            

Q3 2021 MD&A    15

The following table summarizes the recoverable amount and impairment reversal at June 30, 2021 and demonstrates the sensitivity of the estimated recoverable amount of the Company's CGUs comprising oil and gas properties to reasonably possible changes in key assumptions inherent in the estimate.

			Recoverable amount			Impairment reversal			Change in discount rate of 1%			Change in oil price of $2.50/bbl			Change in gas price of $0.25/mcf
Conventional CGU			$	57,891		$	15,000		$	1,000		$	1,000		$	8,000
Peace River CGU			238,714			154,000			4,000			40,000			2,500
Lloydminster CGU			340,730			154,000			12,500			52,000			—
Duvernay CGU (1)			115,157			5,000			45,000			44,500			44,500
Viking CGU			1,338,985			356,000			47,000			89,500			4,500
Eagle Ford CGU			2,015,118			442,415			109,400			103,900			24,400
			$	4,106,595		$	1,126,415		$	218,900		$	330,900		$	83,900

(1)     The impairment reversal for the Duvernay CGU was limited to total accumulated impairments less subsequent depletion of $5.0 million.

2020 Impairments

We recorded total net impairments of $2.4 billion for the year ended December 31, 2020 due to significant changes in forecasted commodity prices caused by the COVID-19 pandemic.

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 an impairment loss 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 loss 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.

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 $2.5 million for Q3/2021 and $8.3 million for YTD 2021 which is consistent with $2.9 million for Q3/2020 and $8.7 million for YTD 2020. The total expense for YTD 2021 was $8.3 million as compared to $8.7 million for YTD 2020 and is comprised of non-cash compensation expense of $4.6 million related to the Share Award Incentive Plan and cash compensation expense of $3.7 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 issued in 2020. 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.

Baytex Energy Corp.                                            

Q3 2021 MD&A    16

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands except for exchange rates)			2021			2020			Change			2021			2020			Change
Unrealized foreign exchange loss (gain)			$	7,545		$	(25,880)		$	33,425		$	3,223		$	28,125		$	(24,902)
Realized foreign exchange gain			(79)			(351)			272			(818)			(437)			(381)
Foreign exchange loss (gain)			$	7,466		$	(26,231)		$	33,697		$	2,405		$	27,688		$	(25,283)
CAD/USD exchange rates:
At beginning of period			1.2405			1.3616						1.2755			1.2965
At end of period			1.2750			1.3324						1.2750			1.3324

We recorded foreign exchange losses of $7.5 million for Q3/2021 and $2.4 million for YTD 2021 compared to a gain of $26.2 million for Q3/2020 and a loss of $27.7 million for YTD 2020.

We recorded unrealized foreign exchange losses on our long-term notes, intercompany notes and credit facilities of $7.5 million for Q3/2021 and $3.2 million for YTD 2021 due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2021 compared to June 30, 2021 and December 31, 2020, respectively. In 2020 unrealized foreign exchange gains and losses relate to changes in our long-term notes and the exchange rates at the end of the period.

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 realized foreign exchange gains of $0.1 million for Q3/2021 and $0.8 million for YTD 2021 compared to $0.4 million for both Q3/2020 and YTD 2020.

INCOME TAXES

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands)			2021			2020			Change			2021			2020			Change
Current income tax expense			$	486		$	322		$	164		$	894		$	880		$	14
Deferred income tax expense (recovery)			10,248			696			9,552			71,963			(261,481)			333,444
Total income tax expense (recovery)			$	10,734		$	1,018		$	9,716		$	72,857		$	(260,601)		$	333,458

Current income tax expense was $0.5 million for Q3/2021 and $0.9 million for YTD 2021 compared to $0.3 million for Q3/2020 and $0.9 million for YTD 2020.

We recorded deferred tax expense of $10.2 million for Q3/2021 and $72.0 million for YTD 2021 compared to an expense of $0.7 million for Q3/2020 and a recovery of $261.5 million for YTD 2020. The deferred tax expense recorded in YTD 2021 is primarily related to the impairment reversal recorded in YTD 2021 whereas the deferred tax recovery recorded in YTD 2020 is primarily related to the impairment loss recorded in YTD 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.

Baytex Energy Corp.                                            

Q3 2021 MD&A    17

NET INCOME (LOSS) AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three and nine months ended September 30, 2021 and 2020 are set forth in the following table.

			Three Months Ended September 30									Nine Months Ended September 30
($ thousands)			2021			2020			Change			2021			2020			Change
Petroleum and natural gas sales			$	488,736		$	252,538		$	236,198		$	1,315,792		$	741,841		$	573,951
Royalties			(90,523)			(40,052)			(50,471)			(239,004)			(125,928)			(113,076)
Revenue, net of royalties			398,213			212,486			185,727			1,076,788			615,913			460,875
Expenses
Operating			(84,196)			(73,447)			(10,749)			(247,645)			(251,597)			3,952
Transportation			(7,818)			(6,372)			(1,446)			(24,092)			(21,745)			(2,347)
Blending and other			(19,581)			(10,673)			(8,908)			(56,668)			(37,490)			(19,178)
Operating netback			$	286,618		$	121,994		$	164,624		$	748,383		$	305,081		$	443,302
General and administrative			(9,980)			(7,741)			(2,239)			(29,323)			(24,954)			(4,369)
Cash financing and interest			(22,793)			(25,418)			2,625			(70,750)			(81,340)			10,590
Realized financial derivatives (loss) gain			(53,905)			(9,743)			(44,162)			(113,697)			30,731			(144,428)
Realized foreign exchange gain			79			351			(272)			818			437			381
Other income (expense)			(78)			—			(78)			(16)			2,007			(2,023)
Current income tax expense			(486)			(322)			(164)			(894)			(880)			(14)
Cash share-based compensation			(1,058)			(613)			(445)			(3,659)			(1,752)			(1,907)
Adjusted funds flow			$	198,397		$	78,508		$	119,889		$	530,862		$	229,330		$	301,532
Exploration and evaluation			(6,766)			(8,909)			2,143			(10,718)			(11,000)			282
Depletion and depreciation			(127,052)			(106,454)			(20,598)			(332,119)			(392,380)			60,261
Non-cash share-based compensation			(1,453)			(2,336)			883			(4,603)			(6,973)			2,370
Non-cash financing and accretion			(6,235)			(2,544)			(3,691)			(13,082)			(16,072)			2,990
Non-cash other income			444			293			151			2,108			293			1,815
Unrealized financial derivatives (loss) gain			(8,941)			(7,284)			(1,657)			(179,408)			19,425			(198,833)
Unrealized foreign exchange gain (loss)			(7,545)			25,880			(33,425)			(3,223)			(28,125)			24,902
Gain on dispositions			2,112			98			2,014			6,092			246			5,846
Impairment			—			—			—			1,126,415			(2,716,349)			3,842,764
Deferred income tax (expense) recovery			(10,248)			(696)			(9,552)			(71,963)			261,481			(333,444)
Net income (loss) for the period			$	32,713		$	(23,444)		$	56,157		$	1,050,361		$	(2,660,124)		$	3,710,485

We generated adjusted funds flow of $198.4 million for Q3/2021 and $530.9 million for YTD 2021 compared to $78.5 million for Q3/2020 and $229.3 million for YTD 2020. The increase in adjusted funds flow for both periods of 2021 was primarily due to higher operating netback which increased $164.6 million from Q3/2020 and $443.3 million from YTD 2020 as a result of higher commodity prices which increased revenue, net of royalties. The increase in operating netback was partially offset by realized losses on financial derivatives of $53.9 million for Q3/2021 and $113.7 million for YTD 2021 due to the increase in oil and natural gas benchmark prices relative to Q3/2020 and YTD 2020 when we recorded a realized loss on financial derivatives of $9.7 million and a realized gain of $30.7 million, respectively.

We reported net income of $32.7 million for Q3/2021 and $1.05 billion for YTD 2021 compared to a net loss of $23.4 million reported for Q3/2020 and a net loss of $2.66 billion for YTD 2020. Net income generated for YTD 2021 is the result of an impairment reversal of $1.13 billion recorded in Q2/2021 compared to YTD 2020 when we recorded an impairment loss of $2.72 billion.

Baytex Energy Corp.                                            

Q3 2021 MD&A    18

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which 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 foreign currency translation gain of $26.2 million for Q3/2021 and $19.0 million for YTD 2021 relates to the change in value of our U.S. net assets and intercompany notes which are expressed in Canadian dollars and are influenced by changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2021 compared to June 30, 2021 and December 31, 2020. The CAD/USD exchange rate was 1.2750 CAD/USD as at September 30, 2021 compared to 1.2405 CAD/USD at June 30, 2021 and 1.2755 CAD/USD at December 31, 2020. Impairment reversals of US$362 million at Q2/2021 increased the value of our U.S. net assets which further contributed to the foreign currency translation gain for YTD 2021.

CAPITAL EXPENDITURES

Capital expenditures for the three and nine months ended September 30, 2021 and 2020 are summarized as follows.

			Three Months Ended September 30
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Drilling, completion and equipping			$	67,177		$	18,460		$	85,637		$	—		$	12,020		$	12,020
Facilities			5,364			11			5,375			2,056			—			2,056
Land, seismic and other			2,958			265			3,223			1,826			—			1,826
Total exploration and development			$	75,499		$	18,736		$	94,235		$	3,882		$	12,020		$	15,902
Total acquisitions, net of proceeds from divestitures			$	(19)		$	(593)		$	(612)		$	(98)		$	—		$	(98)
			Nine Months Ended September 30
			2021									2020
($ thousands)			Canada			U.S.			Total			Canada			U.S.			Total
Drilling, completion and equipping			$	129,230		$	90,092		$	219,322		$	99,545		$	71,859		$	171,404
Facilities			12,562			25			12,587			23,753			299			24,052
Land, seismic and other			6,597			802			7,399			6,624			451			7,075
Total exploration and development			$	148,389		$	90,919		$	239,308		$	129,922		$	72,609		$	202,531
Total acquisitions, net of proceeds from divestitures			$	(240)		$	(593)		$	(833)		$	(149)		$	—		$	(149)

Exploration and development expenditures were $94.2 million for Q3/2021 and $239.3 million for YTD 2021 compared to $15.9 million for Q3/2020 and $202.5 million for YTD 2020. Expenditures in Q3/2021 were higher compared to Q3/2020 as development increased in 2021 with the recovery in commodity prices and resumption of activity.

In Canada, we invested $75.5 million on exploration and development activities in Q3/2021 which is $71.6 million higher than $3.9 million in Q3/2020. Exploration and development expenditures of $75.5 million for Q3/2021 included costs associated with drilling 26 (25.0 net) light oil wells, 19 (18.7 net) heavy oil wells, and investing $5.4 million on facilities. Exploration and development expenditures of $3.9 million for Q3/2020 reflected the suspension of drilling and completion operations following the sharp decline in crude oil prices in March 2020. Exploration and development expenditures of $148.4 million for YTD 2021 included costs associated with drilling 79 (77.2 net) light oil wells, 26 (22.5 net) heavy oil wells, 2 (2.0 net) natural gas wells, and investing $12.6 million on facilities. Exploration and development expenditures of $129.9 million for YTD 2020 included costs associated with drilling 74 (71.2 net) light oil wells, 33 (33.0 net) heavy oil wells, and investing $23.8 million on facilities.

Total U.S. exploration and development expenditures were $18.7 million for Q3/2021 which is $6.7 million higher than Q3/2020 when exploration and development expenditures totaled $12.0 million. Exploration and development expenditures for Q3/2021 included costs associated with drilling 11 (2.0 net) wells along with 17 (3.4 net) wells that were brought on production. Exploration and development expenditures of $90.9 million for YTD 2021 included costs associated with drilling 52 (11.2 net) wells along with 79 (20.6 net) wells that were brought on production. Exploration and development expenditures for YTD 2021 were higher than $72.6 million for YTD 2020 that included costs associated with drilling 39 (9.2 net) wells along with 53 (11.5 net) wells that were brought on production. The $18.3 million increase in spending YTD 2021 relative to YTD 2020 is due to higher activity levels that was slightly offset by the strengthening Canadian dollar.

Baytex Energy Corp.                                            

Q3 2021 MD&A    19

Our exploration and development expenditures for YTD 2021 are consistent with expectations and we forecast expenditures of $300 - $315 million for 2021.

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 September 30, 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 September 30, 2021, net debt of $1.56 billion was $282.9 million lower than $1.85 billion at December 31, 2020. The decrease in net debt is primarily a result of free cash flow of $284.2 million generated during YTD 2021 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 September 30, 2021, our net debt to adjusted funds flow ratio was 2.6 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 higher adjusted funds flow for the twelve months ended September 30, 2021 and lower net debt at September 30, 2021.

Credit Facilities

At September 30, 2021, the principal amount of borrowings and letters of credit outstanding was $561.8 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 2.2% for Q3/2021 and YTD 2021 compared to 1.9% for Q3/2020 and 2.5% for YTD 2020.

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at September 30, 2021.

Covenant Description			Position as at September 30, 2021			Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)			0.8:1.0			3.5:1.0
Interest Coverage (3) (Minimum Ratio)			7.4:1.0			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 September 30, 2021, the Company's Senior Secured Debt totaled $561.8 million which includes $546.8 million of principal amounts outstanding and $15.0 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 September 30, 2021 was $708.4 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 September 30, 2021 were $95.7 million.

Long-Term Notes

We have two series of long-term notes outstanding that total $1.0 billion as at September 30, 2021. The long-term notes do not contain any financial maintenance covenants but contain a debt incurrence covenant that may restrict 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"). 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.

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.

During the nine months ended September 30, 2021, Baytex repurchased and cancelled US$115.5 million of the 5.625% Notes and recorded early redemption expense of $0.9 million. Subsequent to September 30, 2021, Baytex repurchased and cancelled US$84.5 million of the 5.625% Notes due 2024 at the call price of 100.938%, plus accrued interest, effective October 29, 2021. As at November 4, 2021, there was US$200.0 million of the 5.625% Notes outstanding.

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 nine months ended September 30, 2021, we issued 3.0 million common shares pursuant to our share-based compensation program. As at November 4, 2021, we had 564.2 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. 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 September 30, 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			$	195,230		$	195,230		$	—		$	—		$	—
Credit facilities (1) (2)			546,803			—			546,803			—			—
Long-term notes (2)			1,000,171			—			362,696			—			637,475
Interest on long-term notes (3)			361,400			76,181			145,542			111,558			28,119
Lease agreements (2)			9,055			3,663			3,901			1,413			78
Processing agreements			5,734			772			935			473			3,554
Transportation agreements			84,236			18,767			38,914			16,470			10,085
Total			$	2,202,629		$	294,613		$	1,098,791		$	129,914		$	679,311

(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. On September 9, 2021 Baytex submitted a redemption notice to redeem US$84.5 million of the 5.625% Notes on October 29, 2021.

(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.                                            

Q3 2021 MD&A    20

QUARTERLY FINANCIAL INFORMATION

			2021									2020												2019
($ thousands, except per common share amounts)			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Petroleum and natural gas sales			488,736			442,354			384,702			233,636			252,538			152,689			336,614			445,895
Net income (loss)			32,713			1,052,999			(35,352)			221,160			(23,444)			(138,463)			(2,498,217)			(117,772)
Per common share - basic			0.06			1.87			(0.06)			0.39			(0.04)			(0.25)			(4.46)			(0.21)
Per common share - diluted			0.06			1.85			(0.06)			0.39			(0.04)			(0.25)			(4.46)			(0.21)
Adjusted funds flow			198,397			175,883			156,582			82,176			78,508			17,887			132,935			232,147
Per common share - basic			0.35			0.31			0.28			0.15			0.14			0.03			0.24			0.42
Per common share - diluted			0.35			0.31			0.28			0.15			0.14			0.03			0.24			0.42
Exploration and development			94,235			61,485			83,588			77,809			15,902			9,852			176,777			153,117
Canada			75,499			30,387			42,503			45,030			3,882			2,929			123,110			104,460
U.S.			18,736			31,098			41,085			32,779			12,020			6,923			53,667			48,657
Acquisitions, net of divestitures			(612)			(18)			(203)			(33)			(98)			(11)			(40)			563
Net debt			1,564,658			1,629,629			1,758,894			1,847,601			1,906,079			1,994,953			2,051,617			1,871,791
Total assets			4,453,971			4,438,162			3,338,408			3,408,096			3,156,414			3,267,820			3,441,040			5,914,083
Common shares outstanding			564,213			564,182			564,111			561,227			561,163			560,545			560,483			558,305
Daily production
Total production (boe/d)			79,872			81,162			78,780			70,475			77,814			72,508			98,452			96,360
Canada (boe/d)			48,124			47,205			52,039			45,321			49,164			37,691			62,262			57,794
U.S. (boe/d)			31,748			33,957			26,741			25,154			28,650			34,817			36,190			38,566
Benchmark prices
WTI oil (US$/bbl)			70.56			66.07			57.84			42.66			40.93			27.85			46.17			56.96
WCS heavy ($/bbl)			71.81			67.03			57.46			43.46			42.40			22.70			34.48			54.29
Edmonton Light ($/bbl)			83.78			77.28			66.58			50.24			49.83			29.85			51.43			58.10
CAD/USD avg exchange rate			1.2601			1.2279			1.2663			1.3031			1.3316			1.3860			1.3445			1.3201
AECO gas ($/mcf)			3.54			2.85			2.93			2.77			2.18			1.91			2.14			2.34
NYMEX gas (US$/mmbtu)			4.01			2.83			2.69			2.66			1.98			1.72			1.95			2.50
Sales price ($/boe)			63.85			57.19			51.84			34.35			33.79			22.31			35.19			48.25
Royalties ($/boe)			(12.32)			(11.04)			(9.44)			(5.83)			(5.59)			(4.42)			(6.33)			(8.72)
Operating expense ($/boe)			(11.46)			(11.22)			(11.36)			(12.30)			(10.26)			(11.17)			(11.66)			(11.23)
Transportation expense ($/boe)			(1.06)			(1.01)			(1.24)			(1.03)			(0.89)			(0.76)			(1.15)			(1.00)
Operating netback ($/boe)			39.01			33.92			29.80			15.19			17.05			5.96			16.05			27.30
Financial derivatives gain (loss) ($/boe)			(7.34)			(5.28)			(2.93)			2.64			(1.36)			2.06			3.00			2.59
Operating netback after financial derivatives ($/boe)			31.67			28.64			26.87			17.83			15.69			8.02			19.05			29.89

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 in Q4/2019 and 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 YTD 2021 which supported increased development activity and resulted in production of 79,872 boe/d for Q3/2021.

North American benchmark commodity prices were 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 relaxed. Commodity prices continued to

Baytex Energy Corp.                                            

Q3 2021 MD&A    21

strengthen in 2021 with WTI averaging US$70.56/bbl in Q3/2021 as the outlook for demand improved with increasing global mobility and supply growth was limited by OPEC production curtailments along with limited production growth from large independent producers. The impact of increased commodity prices is reflected in our realized sales price of $63.85/boe for Q3/2021 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 Q3/2021 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 $1.87 billion at Q4/2019 to $1.56 billion at Q3/2021 as free cash flow of $375.2 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 1.2965 CAD/USD at Q4/2019 to 1.2750 CAD/USD at Q3/2021.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 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 nine months ended September 30, 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 a 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.                                            

Q3 2021 MD&A    22

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

			Three Months Ended September 30						Nine Months Ended September 30
($ thousands)			2021			2020			2021			2020
Cash flow from operating activities			$	178,961		$	93,688		$	471,817		$	302,079
Change in non-cash working capital			17,631			(16,391)			54,830			(78,829)
Asset retirement obligations settled			1,805			1,211			4,215			6,080
Adjusted funds flow			$	198,397		$	78,508		$	530,862		$	229,330

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 September 30						Nine Months Ended September 30
($ thousands)			2021			2020			2021			2020
Cash flow used in investing activities			$	92,763		$	16,288		$	214,796		$	233,092
Change in non-cash working capital			1,018			(444)			24,248			(28,683)
Proceeds from dispositions			701			98			947			149
Property acquisitions			(89)			—			(114)			—
Additions to other plant and equipment			(158)			(40)			(569)			(2,027)
Exploration and development expenditures			$	94,235		$	15,902		$	239,308		$	202,531

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 September 30						Nine Months Ended September 30
($ thousands)			2021			2020			2021			2020
Adjusted funds flow			$	198,397		$	78,508		$	530,862		$	229,330
Exploration and development expenditures			(94,235)			(15,902)			(239,308)			(202,531)
Payments on lease obligations			(1,142)			(1,456)			(3,143)			(4,440)
Asset retirement obligations settled			(1,805)			(1,211)			(4,215)			(6,080)
Free cash flow			$	101,215		$	59,939		$	284,196		$	16,279

Baytex Energy Corp.                                            

Q3 2021 MD&A    23

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)			September 30, 2021			December 31, 2020
Credit facilities (1)			$	546,803		$	651,173
Long-term notes (1)			1,000,171			1,147,950
Trade and other payables			195,230			155,955
Trade and other receivables			(177,546)			(107,477)
Net debt			$	1,564,658		$	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 September 30						Nine Months Ended September 30
($ thousands)			2021			2020			2021			2020
Petroleum and natural gas sales			$	488,736		$	252,538		$	1,315,792		$	741,841
Blending and other expense			(19,581)			(10,673)			(56,668)			(37,490)
Total sales, net of blending and other expense			469,155			241,865			1,259,124			704,351
Royalties			(90,523)			(40,052)			(239,004)			(125,928)
Operating expense			(84,196)			(73,447)			(247,645)			(251,597)
Transportation expense			(7,818)			(6,372)			(24,092)			(21,745)
Operating netback			286,618			121,994			748,383			305,081
Realized financial derivative (loss) gain			(53,905)			(9,743)			(113,697)			30,731
Operating netback after realized financial derivatives			$	232,713		$	112,251		$	634,686		$	335,812

Baytex Energy Corp.                                            

Q3 2021 MD&A    24

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 September 30
($ thousands)			2021			2020
Net income (loss)			$	1,271,521		$	(2,777,896)
Plus:
Financing and interest			111,861			126,228
Unrealized foreign exchange (gain) loss			(15,670)			3,776
Unrealized financial derivatives loss			217,333			32,470
Current income tax expense			588			1,382
Deferred income tax expense (recovery)			172,477			(315,078)
Depletion and depreciation			426,119			572,518
Gain on dispositions			(6,747)			(1,409)
Impairment (reversal) loss			(1,482,544)			2,904,171
Non-cash items (1)			13,498			18,619
Bank EBITDA			$	708,436		$	564,781

(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 September 30, 2021.

Baytex Energy Corp.                                            

Q3 2021 MD&A    25

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; the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; that a significant portion of our financial obligations will be funded by adjusted funds flow; our expectations with respect to the LIBOR transition and that we do not expect it to have a material impact on Baytex; and the circumstances in which we would be eligible to terminate our reporting obligations under the Securities Exchange Act of 1934, as amended.

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.