Baytex Energy Corp.                                            

Q3 2020 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2020 and 2019

Dated November 2, 2020

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, 2020. This information is provided as of November 2, 2020. 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, 2020 ("Q3/2020" and "YTD 2020") have been compared with the results for the three and nine months ended September 30, 2019 ("Q3/2019" and "YTD 2019"). 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 endedSeptember 30, 2020, its audited comparative consolidated financial statements for the years ended December 31, 2019 and 2018, together with the accompanying notes, and its Annual Information Form for the year ended December 31, 2019. 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.

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

This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). The terms "adjusted funds flow", "operating netback", "exploration and development expenditures", "free cash flow", "net debt", and "Bank EBITDA" do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to our advisory on forward-looking information and statements and a summary of our non-GAAP measures at the end of the MD&A.

BAYTEX ENERGY CORP.

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

CURRENT ENVIRONMENT

In March 2020, the World Health Organization declared a global pandemic related to the novel coronavirus ("COVID-19"). The emergence of COVID-19 and the steps taken by governments to control the spread of the virus resulted in significant instability in the global economy and a sharp decline in demand for crude oil. This combined with the increased supply of crude oil due to the Russia and Saudi Arabia price war resulted in an unprecedented collapse in global crude oil prices and significant volatility during Q2/2020. Global crude oil prices began to recover and were relatively stable during Q3/2020 as members of OPEC+ agreed to production curtailments and governments began to ease restrictions that allowed economies to begin reopening which increased demand. While these factors have resulted in recent improvements in crude oil prices the outlook for prices remains uncertain due to the potential for additional government restrictions from COVID-19 and uncertainty that members of OPEC+ will maintain production curtailments.

We have taken significant action in response to the uncertain outlook for our industry. In March, we established a COVID-19 response team to coordinate, establish and implement our response measures which include restricted travel and adjusted work schedules. We have established remote working capabilities and procedures that will ensure business continuity as we continue to adhere to recommendations from applicable government and public health agencies. We have also taken steps to preserve our financial liquidity by reducing exploration and development expenditures and shutting in low margin production when operating netbacks were challenged. As a result of these actions we have maintained $425.8 million of availability on our credit facilities at September 30, 2020 and we are forecasting compliance with the financial covenants in our credit facilities at current forward prices.

The global health crisis surrounding COVID-19 has impacted our results for YTD 2020 and has resulted in uncertainty regarding the outlook and future performance of our industry. We do not know the extent and duration to which COVID-19 will impact demand and the price for oil. The overall effect on our business will depend on how quickly the world economy resumes activity which is highly dependent on the progression of the pandemic and the success of measures taken to prevent its spread.

Baytex Energy Corp.                                            

Q3 2020 MD&A    2

THIRD QUARTER HIGHLIGHTS

Our financial and operating results for Q3/2020 reflect our response to the challenging market conditions caused by COVID-19. We delivered free cash flow of $59.9 million which allowed us to enhance our liquidity at Q3/2020 with $425.8 million available on our credit facilities. Production of 77,814 boe/d was in line with expectations and reflects limited development expenditures in the U.S. and minimal spending in Canada during Q2/2020 and Q3/2020. We reduced development activity in Canada and the U.S. following the decline in crude oil prices during March 2020 which resulted in total capital expenditures of $15.9 million for Q3/2020.

In Canada, production of 49,164 boe/d for Q3/2020 was consistent with expectations after we suspended development activity in March 2020. Development expenditures of $3.9 million for Q3/2020 were preliminary costs for Q4/2020 completion activity and land acquisition costs. Production of 49,164 boe/d for Q3/2020 was lower than 58,134 boe/d in Q3/2019 as a result of these actions.

In the U.S., we invested $12.0 million on exploration and development activity during Q3/2020 and drilled 22 (5.4 net) wells with 6 (0.8 net) wells brought on production. Production of 28,650 boe/d for Q3/2020 is consistent with expectations and reflects the suspension of completion activity during Q2/2020 along with a limited number of wells brought on production during Q3/2020. Completion activity was lower in Q3/2020 relative to Q3/2019 when we commenced production from 20 (4.6 net) wells and generated production of 36,793 boe/d in our U.S. operations.

Global benchmark prices for crude oil stabilized during Q3/2020 as the result of renewed production curtailments between members of the OPEC+ group and demand was partially restored after governments eased restrictions intended to limit the spread of COVID-19. Even with recent improvements the WTI benchmark price was 27% lower in Q3/2020 relative to Q3/2019 due to elevated global inventory levels and lower demand caused by the COVID-19 pandemic. The WTI benchmark price averaged US$40.93/bbl for Q3/2020 compared to US$56.45/bbl during Q3/2019.

Adjusted funds flow was $78.5 million in Q3/2020 compared to $213.4 million for Q3/2019. Our financial and operating results for Q3/2020 reflect our actions to reduce development activity during this period of low oil prices. Lower production combined with the decline in crude oil prices caused a $107.4 million decrease in operating netback relative to Q3/2019. The $133.1 million decrease in revenue, net of royalties and blending and other expense, was mitigated by our cost savings initiatives which resulted in a $29.7 million decrease in operating, transportation, and general and administrative expenses for Q3/2020 compared to Q3/2019. We also recorded realized financial derivative losses of $9.7 million in Q3/2020 compared to gains of $20.9 million in Q3/2019. We recorded net loss of $23.4 million for Q3/2020 compared to net income of $15.2 million in Q3/2019 which reflects the decrease in adjusted funds flow partially offset by lower depletion in Q3/2020 relative to Q3/2019.

Net debt was $1.91 billion at September 30, 2020 compared to $1.87 billion at December 31, 2019. We generated free cash flow of $16.3 million during YTD 2020 and we had $425.8 million available on our credit facilities at September 30, 2020. The reduction in net debt from free cash flow was offset by total transaction and financing costs of $17.6 million related to the refinancing transactions in Q1/2020 in addition to a $30.9 million increase in the reported amount of our U.S. dollar denominated net debt due to a weaker Canadian dollar at September 30, 2020 compared to December 31, 2019.

Baytex Energy Corp.                                            

Q3 2020 MD&A    3

2020 GUIDANCE

Our results for YTD 2020 are consistent with expectations and are in line with our annual guidance released on June 25, 2020. Production for YTD 2020 exceeded our annual guidance while exploration and development expenditures are expected to fall within our annual guidance range. We have revised our annual guidance for 2020 which reflects our cost savings initiatives and efforts to optimize our operations in response to lower crude oil prices.

The following table compares our updated 2020 guidance to our previously announced guidance and our YTD 2020 results.

	Previous Annual Guidance (1)	Revised Annual Guidance	YTD 2020 Results
Exploration and development expenditures ($ millions)	$260 - $290	no change	$202.5
Production (boe/d)	78,000 - 82,000	~80,000	82,907
Expenses:
Royalty rate (%)	~18.5	~18.0	17.9
Operating ($/boe)	$11.75 - $12.50	$11.20 - $11.40	$11.08
Transportation ($/boe)	$0.95 - $1.05	no change	$0.96
General and administrative ($ millions)	$38 ($1.30/boe)	no change	$25.0 ($1.10/boe)
Cash interest ($ millions)	$112 ($3.84/boe)	$108 ($3.70/boe)	$81.3 ($3.58/boe)
Leasing expenditures ($ millions)	$7	$6	$4.4
Asset retirement obligations ($ millions)	$10	$8	$6.1

(1)As announced on June 25, 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    4

RESULTS OF OPERATIONS

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

Production

	Three Months Ended September 30
	2020						2019
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	18,248		15,853		34,101		22,493		20,336		42,829
Heavy oil	22,138		—		22,138		25,712		—		25,712
Natural Gas Liquids (NGL)	1,281		6,136		7,417		1,575		7,968		9,543
Total liquids (bbl/d)	41,667		21,989		63,656		49,780		28,304		78,084
Natural gas (mcf/d)	44,980		39,965		84,945		50,122		50,932		101,054
Total production (boe/d)	49,164		28,650		77,814		58,134		36,793		94,927
Production Mix
Segment as a percent of total	63	%	37	%	100	%	61	%	39	%	100	%
Light oil and condensate	37	%	55	%	44	%	39	%	55	%	45	%
Heavy oil	45	%	—	%	28	%	44	%	—	%	27	%
NGL	3	%	22	%	10	%	3	%	22	%	10	%
Natural gas	15	%	23	%	18	%	14	%	23	%	18	%
	Nine Months Ended September 30
	2020						2019
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	20,409		19,161		39,570		22,636		20,843		43,479
Heavy oil	20,946		—		20,946		26,637		—		26,637
Natural Gas Liquids (NGL)	1,178		6,446		7,624		1,430		9,315		10,745
Total liquids (bbl/d)	42,533		25,607		68,140		50,703		30,158		80,861
Natural gas (mcf/d)	43,028		45,574		88,602		49,207		54,380		103,587
Total production (boe/d)	49,704		33,203		82,907		58,904		39,221		98,125
Production Mix
Segment as a percent of total	60	%	40	%	100	%	60	%	40	%	100	%
Light oil and condensate	41	%	58	%	48	%	39	%	53	%	44	%
Heavy oil	42	%	—	%	25	%	45	%	—	%	27	%
NGL	2	%	19	%	9	%	2	%	24	%	11	%
Natural gas	15	%	23	%	18	%	14	%	23	%	18	%

Production was 77,814 boe/d for Q3/2020 and 82,907 boe/d for YTD 2020 compared to 94,927 boe/d for Q3/2019 and 98,125 boe/d for YTD 2019. Our production results for Q3/2020 and YTD 2020 were in line with expectations and are a result of lower development activity in Canada and the U.S. following the sharp decline in crude oil prices in March 2020.

In Canada, production was 49,164 boe/d for Q3/2020 and 49,704 boe/d for YTD 2020 compared to 58,134 boe/d for Q3/2019 and 58,904 boe/d for YTD 2019. Lower production in both periods of 2020 is a result of lower development activity relative to the comparative periods of 2019 as we suspended our Canadian development program and temporarily shut-in production in response to the sharp decline in crude oil prices in March 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    5

Production in the U.S. was 28,650 boe/d for Q3/2020 and 33,203 boe/d for YTD 2020 compared to 36,793 boe/d for Q3/2019 and 39,221 boe/d for YTD 2019. U.S. production was lower for both periods of 2020 which reflects lower completion activity during Q3/2020 and YTD 2020 relative to the same periods of 2019. We initiated production from 6 (0.8 net) wells during Q3/2020 and 53 (11.5 net) wells during YTD 2020 compared to 20 (4.6 net) in Q3/2019 and 85 (18.6 net) wells in YTD 2019.

Our annual guidance of approximately 80,000 boe/d reflects optimized production levels and development activity in Canada and the U.S.

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 were relatively strong leading into 2020 as stable demand and production outlooks continued from Q4/2019. Benchmark prices began to decline rapidly in March after members of the OPEC+ group began to increase the supply of crude oil to the global market and measures to limit the spread of COVID-19 resulted in a significant decrease in the demand for crude oil. Global benchmark prices began to improve in July 2020 and were relatively stable throughout Q3/2020 following the OPEC+ decision to reinstate supply cuts along with improved demand after measures intended to limit the spread of COVID-19 were relaxed.

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$41.63/bbl during Q3/2020 and US$39.19/bbl during YTD 2020 compared to US$61.07/bbl during Q3/2019 and US$62.63/bbl during YTD 2019. The MEH benchmark was at a US$0.70/bbl and US$0.87/bbl premium to WTI in Q3/2020 and YTD 2020 compared to a US$4.62/bbl and US$5.57/bbl premium to WTI during Q3/2019 and YTD 2019. The decrease in the MEH benchmark premium to WTI in 2020 was a result of elevated inventory levels as a result of lower refinery demand on the U.S. Gulf coast relative to both periods in 2019.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Canadian light and heavy oil differentials to WTI were wider in early 2020 relative to 2019 as a result of higher Canadian oil production. Canadian oil differentials narrowed with production shut-ins in Western Canada during Q2/2020 and resulted in light and heavy oil differentials for Q3/2020 that were US$1.15/bbl and US$3.15/bbl narrower relative to Q3/2019 respectively.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price which is the representative benchmark for light grades of crude oil in Western Canada. The Edmonton par price averaged $49.83/bbl during Q3/2020 and $43.70/bbl during YTD 2020 compared to $68.41/bbl during Q3/2019 and $69.59/bbl during YTD 2019. Edmonton par traded at a discount to WTI of US$3.51/bbl for Q3/2020 and US$6.04/bbl for YTD 2020 compared to a discount of US$4.66/bbl for Q3/2019 and US$4.70/bbl for YTD 2019.

The price received for our heavy oil production in Canada is based on the WCS benchmark price which is the representative benchmark for heavy grades of crude oil in Western Canada. The WCS heavy oil price averaged $42.40/bbl for Q3/2020 and $33.34/bbl for YTD 2020 as compared to $58.39/bbl for Q3/2019 and $60.24/bbl for YTD 2019. The WCS heavy oil differential was US$9.09/bbl in Q3/2020 and US$13.70/bbl in YTD 2020 compared to US$12.24/bbl for Q3/2019 and US$11.74/bbl for YTD 2019.

Natural Gas

U.S. natural gas prices for Q3/2020 and YTD 2020 were lower than Q3/2019 and YTD 2019 as U.S. natural gas inventory levels remained elevated due to lower demand despite falling natural gas production. Canadian natural gas prices improved in Q3/2020 and YTD 2020 due to lower associated gas production as a result of oil production being shut-in in Western Canada during 2020.

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$1.98/mmbtu in Q3/2020 and US$1.88/mmbtu in YTD 2020 which is lower than US$2.23/mmbtu in Q3/2019 and US$2.67/mmbtu in YTD 2019. Record U.S. natural gas production levels leading into 2020 resulted in an oversupplied North American market and lower natural gas prices in YTD 2020 relative to YTD 2019.

In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a result of increasing supply and limited market access for Canadian natural gas production. The AECO benchmark averaged $2.18/mcf during Q3/2020 and $2.08/mcf during YTD 2020 which is higher than $1.04/mcf for Q3/2019 and $1.39/mcf for YTD 2019. The AECO gas benchmark was higher in both periods of 2020 relative to 2019 due to lower associated gas production from oil production that was shut-in in Western Canada during both periods of 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    6

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30			Nine Months Ended September 30
	2020	2019	Change	2020	2019	Change
Benchmark Averages
WTI oil (US$/bbl)(1)	40.93	56.45	(15.52)	38.32	57.06	(18.74)
MEH oil (US$/bbl)(2)	41.63	61.07	(19.44)	39.19	62.63	(23.44)
MEH oil differential to WTI (US$/bbl)	0.70	4.62	(3.92)	0.87	5.57	(4.70)
Edmonton par oil ($/bbl)	49.83	68.41	(18.58)	43.70	69.59	(25.89)
Edmonton par oil differential to WTI (US$/bbl)	(3.51)	(4.66)	1.15	(6.04)	(4.70)	(1.34)
WCS heavy oil ($/bbl)(3)	42.40	58.39	(15.99)	33.34	60.24	(26.90)
WCS heavy oil differential to WTI (US$/bbl)	(9.09)	(12.24)	3.15	(13.70)	(11.74)	(1.96)
AECO natural gas price ($/mcf)(4)	2.18	1.04	1.14	2.08	1.39	0.69
NYMEX natural gas price (US$/mmbtu)(5)	1.98	2.23	(0.25)	1.88	2.67	(0.79)
CAD/USD average exchange rate	1.3316	1.3207	0.0109	1.3541	1.3292	0.0249

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

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

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

	Three Months Ended September 30
	2020						2019
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)	$	46.72	$	51.85	$	49.10	$	65.20	$	75.01	$	69.86
Heavy oil ($/bbl)(1)	29.03		—		29.03		44.39		—		44.39
NGL ($/bbl)	14.95		15.79		15.65		10.26		15.07		14.27
Natural gas ($/mcf)	2.14		2.50		2.31		0.95		3.08		2.03
Weighted average ($/boe)(1)	$	32.76	$	35.55	$	33.79	$	45.96	$	48.99	$	47.14
	Nine Months Ended September 30
	2020						2019
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl)	$	41.08	$	49.11	$	44.97	$	66.20	$	77.81	$	71.77
Heavy oil ($/bbl)(1)	23.03		—		23.03		45.53		—		45.53
NGL ($/bbl)	12.27		14.60		14.24		17.12		18.74		18.52
Natural gas ($/mcf)	2.01		2.50		2.26		1.49		3.51		2.55
Weighted average ($/boe)(1)	$	28.60	$	34.61	$	31.01	$	47.69	$	50.67	$	48.88

(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 $33.79/boe for Q3/2020 and $31.01/boe for YTD 2020 compared to $47.14/boe for Q3/2019 and $48.88/boe for YTD 2019. Our realized price in the U.S. was $35.55/boe in Q3/2020 which is $13.44/boe lower than $48.99/boe in Q3/2019. In Canada, our realized price of $32.76/boe for Q3/2020 was $13.20/boe lower than $45.96/boe for Q3/2019. The decrease in our realized price in Canada and the U.S. for both periods of 2020 were a result of the decrease in North American benchmark prices relative to the comparatives periods of 2019.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price was $46.72/bbl in Q3/2020 and $41.08/bbl in YTD 2020 compared to $65.20/bbl in Q3/2019 and $66.20/bbl in YTD 2019. Our

Baytex Energy Corp.                                            

Q3 2020 MD&A    7

realized light oil and condensate price for Q3/2020 and YTD 2020 represents a discount of $3.11/bbl and $2.62/bbl respectively to the Edmonton par price which is relatively consistent with discounts of $3.21/bbl in Q3/2019 and $3.39/bbl in YTD 2019. The discount of $3.11/bbl for Q3/2020 reflects fluctuations in regional pricing for our Viking light oil production relative to the Edmonton par benchmark and is consistent with our expectations to receive a $2.50/bbl to $3.50/bbl discount to the Edmonton par price for the second half of 2020. Our YTD 2020 discount of $2.62/bbl to the Edmonton par price reflects improved price realizations on our light oil production relative to YTD 2019 when our discount to the Edmonton par price was $3.39/bbl.

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 $51.85/bbl for Q3/2020 and $49.11/bbl for YTD 2020 compared to $75.01/bbl for Q3/2019 and $77.81/bbl for YTD 2019. Expressed in U.S. dollars, our realized light oil and condensate price of US$38.94/bbl for Q3/2020 and US$36.27/bbl for YTD 2020 represents a US$2.69/bbl discount to MEH for Q3/2020 and a discount of US$2.92/bbl for YTD 2020. A change in marketing contracts during Q3/2019 resulted in improved price realizations for both periods of 2020 relative to Q3/2019 and YTD 2019 when our discount to MEH was US$4.27/bbl and US$4.09/bbl, respectively.

Our realized heavy oil price, net of blending and other expense averaged $29.03/bbl in Q3/2020 and $23.03/bbl in YTD 2020 compared to $44.39/bbl in Q3/2019 and $45.53/bbl in YTD 2019. Our realized heavy oil price for Q3/2020 and YTD 2020 was $15.36/bbl and $22.50/bbl lower relative to Q3/2019 and YTD 2019 respectively compared to a $15.99/bbl and $26.90/bbl decrease in the WCS benchmark price over the same periods. Our realized heavy oil price did not decrease as much as WCS benchmark pricing as we optimized production levels and the timing of deliveries during 2020 which achieved stronger price realizations.

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 $15.65/bbl in Q3/2020 or 29% of WTI (expressed in Canadian dollars) compared to $14.27/bbl or 19% of WTI (expressed in Canadian dollars) in Q3/2019. Our YTD 2020 realized NGL price was $14.24/bbl or 27% of WTI (expressed in Canadian dollars) compared to $18.52/bbl or 24% of WTI (expressed in Canadian dollars) in YTD 2019. Our realized NGL price was higher as a percentage of WTI in Q3/2020 and YTD 2020 relative to the same periods of 2019 as the decrease in the underlying product prices wasn't as large relative to the decrease in WTI over the same period.

We compare our realized natural gas price in Canada to the AECO benchmark price. Our realized natural gas price was $2.14/mcf for Q3/2020 and $2.01/mcf in YTD 2020 compared to $0.95/mcf in Q2/2019 and $1.49/mcf in YTD 2019. The increase in our realized natural gas price in Canada is consistent with the increase in the AECO benchmark price over the same periods. In the U.S., our realized natural gas price was US$1.88/mcf for Q3/2020 and US$1.85/mcf in YTD 2020 compared to US$2.33/mcf in Q3/2019 and US$2.64/mcf in YTD 2019. Our realized natural gas price in the U.S. is consistent with the NYMEX benchmark in both periods of 2020 and 2019.

Baytex Energy Corp.                                            

Q3 2020 MD&A    8

Petroleum and Natural Gas Sales

	Three Months Ended September 30
	2020						2019
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	78,432	$	75,620	$	154,052	$	134,921	$	140,344	$	275,265
Heavy oil	69,791		—		69,791		117,961		—		117,961
NGL	1,762		8,914		10,676		1,486		11,045		12,531
Total oil sales	149,985		84,534		234,519		254,368		151,389		405,757
Natural gas sales	8,846		9,173		18,019		4,401		14,442		18,843
Total petroleum and natural gas sales	158,831		93,707		252,538		258,769		165,831		424,600
Blending and other expense	(10,673)		—		(10,673)		(12,950)		—		(12,950)
Total sales, net of blending and other expense	$	148,158	$	93,707	$	241,865	$	245,819	$	165,831	$	411,650
	Nine Months Ended September 30
	2020						2019
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	229,745	$	257,818	$	487,563	$	409,117	$	442,763	$	851,880
Heavy oil	169,638		—		169,638		381,684		—		381,684
NGL	3,957		25,791		29,748		6,684		47,656		54,340
Total oil sales	403,340		283,609		686,949		797,485		490,419		1,287,904
Natural gas sales	23,660		31,232		54,892		20,021		52,099		72,120
Total petroleum and natural gas sales	427,000		314,841		741,841		817,506		542,518		1,360,024
Blending and other expense	(37,490)		—		(37,490)		(50,628)		—		(50,628)
Total sales, net of blending and other expense	$	389,510	$	314,841	$	704,351	$	766,878	$	542,518	$	1,309,396

Total sales, net of blending and other expense, of $241.9 million for Q3/2020 decreased $169.8 million from $411.7 million reported for Q3/2019 while total sales, net of blending and other expense, of $704.4 million for YTD 2020 decreased $605.0 million from $1,309.4 million in YTD 2019. The decrease in total sales in both periods of 2020 is a result of lower realized pricing from the decrease in benchmark pricing along with lower production relative to the comparative periods of 2019.

In Canada, total sales, net of blending and other expense, was $148.2 million for Q3/2020 which is a decrease of $97.7 million from Q3/2019. Total petroleum and natural gas sales decreased due lower realized pricing combined with lower production in Q3/2020 relative to Q3/2019. Lower pricing in Q3/2020 resulted in a $59.7 million decrease in total sales, net of blending and other expense and lower production contributed a $37.9 million decrease in total sales, net of blending and other expense relative to Q3/2019. Lower production and the decrease in benchmark prices resulted in our total sales, net of blending and other expense, decreasing to $389.5 million in YTD 2020 from $766.9 million in YTD 2019.

In the U.S., petroleum and natural gas sales were $93.7 million for Q3/2020 which is a decrease of $72.1 million from $165.8 million reported for Q3/2019. Lower pricing in Q3/2020 resulted in a $35.4 million decrease in total petroleum and natural gas sales while lower production contributed a $36.7 million decrease in total petroleum and natural gas sales relative to Q3/2019. Lower production and realized pricing in YTD 2020 resulted in petroleum and natural gas sales of $314.8 million which was $227.7 million lower than $542.5 million for YTD 2019.

Baytex Energy Corp.                                            

Q3 2020 MD&A    9

Royalties

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects, and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30
	2020									2019
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	12,297		$	27,755		$	40,052		$	26,193		$	48,824		$	75,017
Average royalty rate(1)	8.3		%	29.6		%	16.6		%	10.7		%	29.4		%	18.2		%
Royalties per boe	$	2.72		$	10.53		$	5.59		$	4.90		$	14.42		$	8.59
	Nine Months Ended September 30
	2020									2019
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	33,972		$	91,956		$	125,928		$	82,313		$	160,646		$	242,959
Average royalty rate(1)	8.7		%	29.2		%	17.9		%	10.7		%	29.6		%	18.6		%
Royalties per boe	$	2.49		$	10.11		$	5.54		$	5.12		$	15.00		$	9.07

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

Royalties for Q3/2020 were $40.1 million or 16.6% of total sales, net of blending and other expense compared to $75.0 million or 18.2% in Q3/2019. Total royalties in YTD 2020 were $125.9 million or 17.9% of total sales, net of blending and other expense compared to $243.0 million or 18.6% in YTD 2019. Total royalty expense is lower in Q3/2020 and YTD 2020 due to lower total sales, net of blending and other expense, relative to the same periods of 2019. Our royalty rate of 16.6% for Q3/2020 was lower than 18.2% for Q3/2019 as a higher proportion of our total sales, net of blending and other expense, were from our Canadian properties in Q3/2020 relative to the same period of 2019. Our royalty rate of 17.9% for YTD 2020 was slightly lower 18.6% in YTD 2019 due to a lower royalty rate on our Canadian properties as a result of lower commodity prices.

Our Canadian royalty rate of 8.3% for Q3/2020 and 8.7% for YTD 2020 was lower than 10.7% for Q3/2019 and 10.7% for YTD 2019 due to lower benchmark commodity prices which resulted in a lower royalty rate on our Canadian properties in 2020 relative to 2019. In the U.S., royalties averaged 29.6% for Q3/2020 and 29.2% YTD 2020 of total sales which is consistent with the same periods of 2019 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

Our average royalty rate of 17.9% for YTD 2020 is consistent with expectations and our annual guidance of approximately 18.0% for 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    10

Operating Expense

	Three Months Ended September 30
	2020						2019
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	57,557	$	15,890	$	73,447	$	73,701	$	23,676	$	97,377
Operating expense per boe	$	12.73	$	6.03	$	10.26	$	13.78	$	6.99	$	11.15
	Nine Months Ended September 30
	2020						2019
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	185,641	$	65,956	$	251,597	$	221,680	$	76,463	$	298,143
Operating expense per boe	$	13.63	$	7.25	$	11.08	$	13.79	$	7.14	$	11.13

Operating expense was $73.4 million ($10.26/boe) for Q3/2020 and $251.6 million ($11.08/boe) for YTD 2020 compared to $97.4 million ($11.15/boe) in Q3/2019 and $298.1 million ($11.13/boe) in YTD 2019. The decrease in total operating expense can be attributed to a decrease in production in addition to our cost savings initiatives which resulted in per boe operating expense for Q3/2020 and YTD 2020 which was slightly lower than the comparative periods of 2019.

In Canada, operating expense was $57.6 million ($12.73/boe) for Q3/2020 and $185.6 million ($13.63/boe) for YTD 2020 compared to $73.7 million ($13.78/boe) for Q3/2019 and $221.7 million ($13.79/boe) in YTD 2019. Total operating expense in Canada has decreased with lower production in both periods of 2020 compared to 2019. Per unit operating expense of $12.73/boe for Q3/2020 and $13.63/boe for YTD 2020 was lower than the comparative periods of 2019 due to our cost savings initiatives in addition to shutting in certain high operating cost, low margin properties for a portion of 2020.

U.S. operating expense was $15.9 million ($6.03/boe) for Q3/2020 and $66.0 million ($7.25/boe) for YTD 2020 compared to $23.7 million ($6.99/boe) for Q3/2019 and $76.5 million ($7.14/boe) in YTD 2019. Lower total operating expense is primarily a result of lower U.S. production in Q3/2020 and YTD 2020 relative to the comparative periods of 2019. Expressed in U.S. dollars, per unit operating expense was US$4.53/boe in Q3/2020 and US$5.35/boe in YTD 2020 which is lower than US$5.29/boe for Q3/2019 and US$5.37/boe in YTD 2019. During Q3/2020, we received a $3.7 million reimbursement of prior period charges from the operator of our Eagle Ford properties which resulted in lower total and per unit operating expense for Q3/2020.

Operating expense of $11.08/boe for YTD 2020 is consistent with our expectations and slightly below our annual guidance range of $11.20 - $11.40/boe for 2020.

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, 2020 and 2019.

	Three Months Ended September 30
	2020						2019
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	6,372	$	—	$	6,372	$	9,903	$	—	$	9,903
Transportation expense per boe	$	1.41	$	—	$	0.89	$	1.85	$	—	$	1.13
	Nine Months Ended September 30
	2020						2019
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	21,745	$	—	$	21,745	$	35,102	$	—	$	35,102
Transportation expense per boe	$	1.60	$	—	$	0.96	$	2.18	$	—	$	1.31

Transportation expense was $6.4 million ($0.89/boe) for Q3/2020 and $21.7 million ($0.96/boe) for YTD 2020 compared to $9.9 million ($1.13/boe) in Q3/2019 and $35.1 million ($1.31/boe) in YTD 2019. The decrease in total transportation expense in both periods of 2020 relative to 2019 is primarily the result of lower crude oil shipments due to lower light and heavy oil production

Baytex Energy Corp.                                            

Q3 2020 MD&A    11

in Canada. Optimization of light and heavy oil deliveries in Canada resulted in lower per boe transportation expense for both periods of 2020 relative to the same periods of 2019. Transportation expense of $0.96 per boe for YTD 2020 is consistent with expectations and is at the low end of our annual guidance of $0.95 to $1.05 per boe for 2020.

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 $10.7 million for Q3/2020 and $37.5 million for YTD 2020 compared to $13.0 million for Q3/2019 and $50.6 million for YTD 2019. Lower blending and other expense in both periods of 2020 compared to 2019 reflects lower heavy oil sales as we shut in heavy oil production in addition to a decrease in the per unit cost of blending diluent during YTD 2020.

Financial Derivatives

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. 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, 2020 and 2019.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2020		2019		Change		2020		2019		Change
Realized financial derivatives gain (loss)
Crude oil	$	(9,530)	$	19,631	$	(29,161)	$	30,640	$	49,944	$	(19,304)
Natural gas	165		1,243		(1,078)		753		2,713		(1,960)
Interest and financing	(378)		(17)		(361)		(662)		7		(669)
Total	$	(9,743)	$	20,857	$	(30,600)	$	30,731	$	52,664	$	(21,933)
Unrealized financial derivatives gain (loss)
Crude oil	$	(717)	$	8,559	$	(9,276)	$	27,155	$	(29,083)	$	56,238
Natural gas	(6,885)		(1,041)		(5,844)		(5,826)		(1,391)		(4,435)
Interest and financing	372		148		224		(101)		(448)		347
Equity total return swap ("Equity TRS")	(54)		—		(54)		(1,803)		—		(1,803)
Total	$	(7,284)	$	7,666	$	(14,950)	$	19,425	$	(30,922)	$	50,347
Total financial derivatives gain (loss)
Crude oil	$	(10,247)	$	28,190	$	(38,437)	$	57,795	$	20,861	$	36,934
Natural gas	(6,720)		202		(6,922)		(5,073)		1,322		(6,395)
Interest and financing	(6)		131		(137)		(763)		(441)		(322)
Equity TRS	(54)		—		(54)		(1,803)		—		(1,803)
Total	$	(17,027)	$	28,523	$	(45,550)	$	50,156	$	21,742	$	28,414

We recorded total financial derivative losses of $17.0 million for Q3/2020 and gains of $50.2 million for YTD 2020. Realized financial derivative gains and losses were primarily driven by settlements on our crude oil contracts and we recorded realized losses of $9.7 million for Q3/2020 and realized gains of $30.7 million for YTD 2020. The unrealized loss of $7.3 million for Q3/2020 and the unrealized gain of $19.4 million for YTD 2020 is primarily due to fluctuations in future commodity prices and revaluation of contracts in place at September 30, 2020 compared to the value of contracts in place at the start of the respective periods.

During Q2/2020, we entered into short-term crude oil financial derivative contracts to provide price certainty for restarting production in our Canadian operations. These contracts were the primary reason for realized losses of $9.5 million in Q3/2020 as market prices for crude oil recovered from Q2/2020 lows and settled at levels above the prices set in these contracts. Realized gains on crude oil financial derivatives of $30.6 million in YTD 2020 are primarily a result of market prices for WTI settling at levels below the prices set in our contracts outstanding during the period.

Unrealized losses of $7.3 million in Q3/2020 and gains of $19.4 million for YTD 2020 reflect the volatility in forecasted gas and crude oil pricing used to revalue our contracts in place at September 30, 2020 relative to June 30, 2020 and December 31, 2019 along with the valuation of new contracts entered during the period. Forecasted crude oil prices at September 30, 2020 were

Baytex Energy Corp.                                            

Q3 2020 MD&A    12

relatively consistent with June 30, 2020 and lower relative to December 31, 2019. Forecasted gas prices at September 30, 2020 were higher relative to June 30, 2020 and December 31, 2019. The fair value of our financial derivative contracts resulted in a net asset of $16.2 million at September 30, 2020 compared to a net asset of $23.5 million at June 30, 2020 and a net liability of $3.2 million at December 31, 2019.

Baytex Energy Corp.                                            

Q3 2020 MD&A    13

We had the following commodity financial derivative contracts as at November 2, 2020.

	Period	Volume	Price/Unit(1)	Index
Oil
Basis Swap	Oct 2020 to Dec 2020	6,500 bbl/d	WTI less US$16.27/bbl	WCS
Basis Swap	Jan 2021 to Jun 2021	2,000 bbl/d	WTI less US$13.75/bbl	WCS
Basis Swap	Jan 2021 to Dec 2021	4,000 bbl/d	WTI less US$14.26/bbl	WCS
Basis Swap(6)	Jan 2021 to Dec 2021	2,000 bbl/d	WTI less US$13.41/bbl	WCS
Basis Swap	Oct 2020 to Dec 2020	5,000 bbl/d	WTI less US$6.15/bbl	MSW
Basis Swap	Jan 2021 to Dec 2021	2,000 bbl/d	WTI less US$5.95/bbl	MSW
Basis Swap(6)	Jan 2021 to Dec 2021	4,000 bbl/d	WTI less US$4.78/bbl	MSW
Fixed - Sell	Oct 2020 to Dec 2020	8,000 bbl/d	US$42.78/bbl	WTI
3-way option(2)	Oct 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$56.00/US$61.35	WTI
3-way option(2)	Oct 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$57.00/US$60.00	WTI
3-way option(2)	Oct 2020 to Dec 2020	4,500 bbl/d	US$50.00/US$57.00/US$62.00	WTI
3-way option(2)	Oct 2020 to Dec 2020	3,000 bbl/d	US$50.00/US$58.00/US$62.00	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$58.00/US$60.50	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$58.00/US$60.83	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,500 bbl/d	US$51.00/US$59.00/US$65.60	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,500 bbl/d	US$51.00/US$59.00/US$66.00	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$59.50/US$66.15	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$65.60	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$66.00	WTI
3-way option(2)	Oct 2020 to Dec 2020	1,000 bbl/d	US$51.00/US$60.00/US$66.05	WTI
3-way option(2)	Oct 2020 to Dec 2020	2,000 bbl/d	US$51.00/US$60.00/US$66.70	WTI
3-way option(2)	Jan 2021 to Dec 2021	3,500 bbl/d	US$35.00/US$45.00/US$49.50	WTI
3-way option(2)	Jan 2021 to Dec 2021	10,000 bbl/d	US$35.00/US$45.00/US$55.00	WTI
Swaption(3)	Jan 2021 to Dec 2021	3,000 bbl/d	US$70.00/bbl	Brent
Swaption(3)	Jan 2021 to Dec 2021	3,000 bbl/d	US$60.75/bbl	WTI
Swaption(5)	Jan 2022 to Dec 2022	5,000 bbl/d	US$53.00/bbl	WTI
Swaption(5)	Jan 2022 to Dec 2022	5,000 bbl/d	US$54.00/bbl	WTI
Natural Gas
Fixed - Sell	Oct 2020 to Dec 2020	10,500 GJ/d	$2.01/GJ	AECO 7A
Fixed - Sell	Jan 2021 to Jun 2021	3,000 GJ/d	$2.71/GJ	AECO 7A
Fixed - Sell	Jan 2021 to Dec 2021	16,000 GJ/d	$2.36/GJ	AECO 7A
Fixed - Sell	Oct 2020 to Dec 2020	2,500 GJ/d	$2.29/GJ	AECO 5A
Fixed - Sell	Jan 2021 to Dec 2021	2,500 GJ/d	$2.40/GJ	AECO 5A
Fixed - Sell	Oct 2020 to Dec 2020	5,500 mmbtu/d	US$2.64/mmbtu	NYMEX
Fixed - Sell	Jan 2021 to Dec 2021	12,000 mmbtu/d	US$2.70/mmbtu	NYMEX
3-way option(2)	Oct 2020 to Dec 2020	5,000 mmbtu/d	US$2.25/US$2.60/US$2.85	NYMEX
3-way option(2)(6)	Jan 2022 to Dec 2022	2,500 mmbtu/d	US$2.25/US$2.75/US$3.06	NYMEX
Swaption(4)	Jan 2021 to Dec 2021	5,000 mmbtu/d	US$2.90/mmbtu	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$58.00/US$62.00 contract, Baytex receives WTI plus US$8.00/bbl when WTI is at or below US$50.00/bbl; Baytex receives US$58.00/bbl when WTI is between US$50.00/bbl and US$58.00/bbl; Baytex receives the market price when WTI is between US$58.00/bbl and US$62.00/bbl; and Baytex receives US$62.00/bbl when WTI is above US$62.00/bbl.

(3)For these contracts, the counterparty has the right, if exercised on December 31, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

(4)For these contracts, the counterparty has the right, if exercised on December 23, 2020, to enter a swap transaction for the remaining term, notional volume and fixed price per unit indicated above.

(5)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.

(6)Contracts entered subsequent to September 30, 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    14

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, 2020 and 2019.

	Three Months Ended September 30
	2020						2019
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	49,164		28,650		77,814		58,134		36,793		94,927
Operating netback:
Total sales, net of blending and other expense	$	32.76	$	35.55	$	33.79	$	45.96	$	48.99	$	47.14
Less:
Royalties	(2.72)		(10.53)		(5.59)		(4.90)		(14.42)		(8.59)
Operating expense	(12.73)		(6.03)		(10.26)		(13.78)		(6.99)		(11.15)
Transportation expense	(1.41)		—		(0.89)		(1.85)		—		(1.13)
Operating netback	$	15.90	$	18.99	$	17.05	$	25.43	$	27.58	$	26.27
Realized financial derivatives (loss) gain	—		—		(1.36)		—		—		2.39
Operating netback after financial derivatives	$	15.90	$	18.99	$	15.69	$	25.43	$	27.58	$	28.66
	Nine Months Ended September 30
	2020						2019
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	49,704		33,203		82,907		58,904		39,221		98,125
Operating netback:
Total sales, net of blending and other expense	$	28.60	$	34.61	$	31.01	$	47.69	$	50.67	$	48.88
Less:
Royalties	(2.49)		(10.11)		(5.54)		(5.12)		(15.00)		(9.07)
Operating expense	(13.63)		(7.25)		(11.08)		(13.79)		(7.14)		(11.13)
Transportation expense	(1.60)		—		(0.96)		(2.18)		—		(1.31)
Operating netback	$	10.88	$	17.25	$	13.43	$	26.60	$	28.53	$	27.37
Realized financial derivatives gain	—		—		1.35		—		—		1.97
Operating netback after financial derivatives	$	10.88	$	17.25	$	14.78	$	26.60	$	28.53	$	29.34

Our operating netback after financial derivatives was $15.69/boe for Q3/2020 and $14.78/boe for YTD 2020 compared to $28.66/boe for Q3/2019 and $29.34/boe for YTD 2019. Operating netback was lower in both periods of 2020 relative to the comparative periods of 2019 due to the decrease in benchmark pricing which resulted in lower per unit sales, net of royalties, in Canada and the U.S. Total operating and transportation expense of $11.15/boe in Q3/2020 and $12.04/boe in YTD 2020 reflects our production optimization and cost savings initiatives which resulted in lower costs relative to $12.28/boe in Q3/2019 and $12.44/boe in YTD 2019. Including realized gains and losses on financial derivatives our operating net back was $15.69/boe for Q3/2020 and $14.78/boe for YTD 2020 compared to $28.66/boe in Q3/2019 and $29.34/boe in YTD 2019.

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 2020 MD&A    15

The following table summarizes our G&A expense for the three and nine months ended September 30, 2020 and 2019.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2020		2019		Change		2020		2019		Change
Gross general and administrative expense	$	7,790	$	11,633	$	(3,843)	$	27,153	$	39,907	$	(12,754)
Overhead recoveries	(49)		(1,699)		1,650		(2,199)		(4,331)		2,132
General and administrative expense	$	7,741	$	9,934	$	(2,193)	$	24,954	$	35,576	$	(10,622)
General and administrative expense per boe	$	1.08	$	1.14	$	(0.06)	$	1.10	$	1.33	$	(0.23)

G&A expense was $7.7 million ($1.08/boe) for Q3/2020 and $25.0 million ($1.10/boe) in YTD 2020 compared to $9.9 million ($1.14/boe) for Q3/2019 and $35.6 million ($1.33/boe) for YTD 2019.

G&A expense for Q3/2020 and YTD 2020 was lower relative to Q3/2019 and YTD 2019 due to reduced staffing levels combined with our cost savings initiatives that included salary reductions. G&A for Q3/2020 and YTD 2020 includes $1.5 million and $3.5 million respectively related to the CEWS program. Despite lower production, G&A per boe was lower in Q3/2020 and YTD 2020 relative to comparative periods of 2019 due to our cost savings initiatives and the benefit of the CEWS.

G&A expense of $25.0 million ($1.10/boe) in YTD 2020 is below our annual guidance of $38 million ($1.30/boe) as YTD 2020 production exceeded the high end of our guidance range, and we benefited from additional cost savings and the CEWS program extension. Our annual guidance of $38 million ($1.30/boe) reflects our cost savings initiatives and the announced changes to the CEWS program.

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 and 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, 2020 and 2019.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2020		2019		Change		2020		2019		Change
Interest on credit facilities	$	3,366	$	4,650	$	(1,284)	$	11,749	$	15,171	$	(3,422)
Interest on long-term notes	21,943		21,955		(12)		69,231		67,382		1,849
Interest on lease obligations	109		147		(38)		$	360	$	475	(115)
Cash interest	$	25,418	$	26,752	$	(1,334)	$	81,340	$	83,028	$	(1,688)
Accretion of debt issue costs	756		1,607		(851)		5,863		3,753		2,110
Accretion of asset retirement obligations	1,788		3,407		(1,619)		6,897		10,268		(3,371)
Early redemption expense	—		—		—		3,312		—		3,312
Financing and interest expense	$	27,962	$	31,766	$	(3,804)	$	97,412	$	97,049	$	363
Cash interest per boe	$	3.55	$	3.06	$	0.49	$	3.58	$	3.10	$	0.48
Financing and interest expense per boe	$	3.91	$	3.64	$	0.27	$	4.29	$	3.62	$	0.67

Financing and interest expense was $28.0 million in Q3/2020 and $97.4 million in YTD 2020 compared to $31.8 million in Q3/2019 and $97.0 million in YTD 2019.

Cash interest of $25.4 million ($3.55/boe) in Q3/2020 and $81.3 million ($3.58/boe) in YTD 2020 is slightly lower than $26.8 million ($3.06/boe) in Q3/2019 and $83.0 million ($3.10/boe) in YTD 2019. Interest on our credit facilities was lower in both periods of 2020 primarily due to a lower weighted average borrowing rate on amounts outstanding relative to 2019. The weighted average interest rate on our credit facilities was 2.5% in YTD 2020 compared to 3.7% in YTD 2019. Interest on our long-term notes was higher in YTD 2020 due to a temporary increase in the principal amount outstanding between the issuance of the US$500 million principal amount of 8.75% senior unsecured notes on February 5, 2020 and the redemption of the US$400 principal amount of 5.125% senior unsecured notes on February 20, 2020 along with the redemption of the $300 million principal amount of 6.625% senior unsecured notes on March 5, 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    16

Financing and interest expense for YTD 2020 includes the accelerated amortization of debt issue costs and $3.3 million of early redemption expense associated with the $300 million principal amount of 6.625% senior unsecured notes which were redeemed at 101.104% of the principal amount on March 5, 2020.

Cash interest expense of $3.58/boe is slightly below our annual guidance of $3.70/boe as production in YTD 2020 exceeded our annual guidance. We expect cash financing and interest expense of $108.0 million ($3.70/boe) for 2020.

Exploration and Evaluation Expense

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $8.9 million for Q3/2020 and $11.0 million in YTD 2020 which is higher than $2.1 million for Q3/2019 and $8.7 million in YTD 2019 due to a higher amount of acreage expiring in 2020 relative to 2019.

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, 2020 and 2019.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2020		2019		Change		2020		2019		Change
Depletion	$	104,547	$	178,364	$	(73,817)	$	386,587	$	547,345	$	(160,758)
Depreciation	1,907		2,058		(151)		5,793		4,203		1,590
Depletion and depreciation	$	106,454	$	180,422	$	(73,968)	$	392,380	$	551,548	$	(159,168)
Depletion and depreciation per boe	$	14.87	$	20.66	$	(5.79)	$	17.27	$	20.59	$	(3.32)

Depletion and depreciation expense was $106.5 million ($14.87/boe) for Q3/2020 and $392.4 million ($17.27/boe) in YTD 2020 compared to $180.4 million($20.66/boe) for Q3/2019 and $551.5 million ($20.59/boe) for YTD 2019. Total depletion and depreciation expense and the depletion rate per boe were lower in both periods of 2020 relative to the comparative periods of 2019 due to lower production in 2020 along with $2.6 billion of impairment write-downs recorded in Q1/2020 which reduced the depletable base of our oil and gas properties.

Impairment

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at September 30, 2020.

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

The recoverable amount of each CGU was calculated at March 31, 2020 using the following benchmark reference prices for the years 2020 to 2029 adjusted for commodity differentials specific to the Company.

	2020	2021	2022	2023	2024	2025	2026	2027	2028	2029
WTI crude oil (US$/bbl)	29.17	40.45	49.17	53.28	55.66	56.87	58.01	59.17	60.35	61.56
WCS heavy oil (CA$/bbl)	19.21	34.65	46.34	51.25	54.28	55.72	56.96	58.22	59.51	60.82
LLS crude oil (US$/bbl)	32.17	43.80	52.55	56.68	59.10	60.35	61.52	62.72	63.94	65.19
Edmonton par oil (CA$/bbl)	29.22	46.85	59.27	65.02	68.43	69.81	71.24	72.70	74.19	75.71
Henry Hub gas (US$/mmbtu)	2.10	2.58	2.79	2.86	2.93	3.00	3.07	3.13	3.19	3.25
AECO gas (CA$/mmbtu)	1.74	2.20	2.38	2.45	2.53	2.60	2.66	2.72	2.79	2.85
Exchange rate (CAD/USD)	1.41	1.37	1.34	1.34	1.34	1.33	1.33	1.33	1.33	1.33

Baytex Energy Corp.                                            

Q3 2020 MD&A    17

This data is combined with assumptions relating to long-term prices, inflation rates and exchange rates together with estimates of transportation costs and pricing of competing fuels to forecast long-term energy prices, consistent with external sources of information. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2.0%.

The following table summarizes the recoverable amount and impairment at March 31, 2020 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		Change in discount rate of 1%		Change in oil price of $2.50/bbl		Change in gas price of $0.25/mcf
Conventional CGU	$	37,444	$	41,000	$	3,000	$	3,500	$	8,500
Peace River CGU	109,631		345,000		9,500		53,500		3,000
Lloydminster CGU	227,967		470,000		25,000		69,500		—
Duvernay CGU	61,197		5,000		5,500		9,500		1,500
Viking CGU	962,134		915,000		57,000		123,000		4,000
Eagle Ford CGU	1,576,423		812,488		120,750		141,500		32,000
	$	2,974,796	$	2,588,488	$	220,750	$	400,500	$	49,000

Share-Based Compensation Expense

Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan and our Incentive Award 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 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 $2.9 million for Q3/2020 and $8.7 million for YTD 2020 compared to $3.4 million for Q3/2019 and $14.2 million for YTD 2019. SBC expense is lower in both periods of 2020 as the total value of awards granted in 2020 was lower than prior years. The total expense for YTD 2020 is comprised of non-cash compensation expense of $7.0 million related to the Share Award Incentive Plan and cash compensation expense of $1.7 million related to the Incentive Award Plan.

Foreign Exchange

Unrealized foreign exchange gains and losses represent the change in value of the long-term notes and credit facilities denominated in U.S. dollars. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate. When the Canadian dollar strengthens against the U.S. dollar at the end of the current period compared to the previous period an unrealized gain is recorded and conversely when the Canadian dollar weakens at the end of the current period compared to the previous period an unrealized loss is recorded. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for exchange rates)	2020		2019		Change		2020		2019		Change
Unrealized foreign exchange (gain) loss	$	(25,880)	$	13,855	$	(39,735)	$	28,125	$	(38,404)	$	66,529
Realized foreign exchange (gain) loss	(351)		382		(733)		(437)		426		(863)
Foreign exchange (gain) loss	$	(26,231)	$	14,237	$	(40,468)	$	27,688	$	(37,978)	$	65,666
CAD/USD exchange rates:
At beginning of period	1.3616		1.3091				1.2965		1.3646
At end of period	1.3324		1.3244				1.3324		1.3244

We recorded unrealized foreign exchange gains of $25.9 million for Q3/2020 due to the strengthening of the Canadian dollar relative to the U.S. dollar at September 30, 2020 compared to June 30, 2020. This compares to an unrealized foreign exchange loss of $13.9 million for Q3/2019 due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2019 relative to June 30, 2019.

We recorded an unrealized foreign exchange loss of $28.1 million for YTD 2020 due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2020 compared to December 31, 2019. This compares to an unrealized foreign exchange gain of $38.4 million in YTD 2019 due to the strengthening of the Canadian dollar relative to the U.S. dollar at September 30, 2019 relative to December 31, 2018.

Baytex Energy Corp.                                            

Q3 2020 MD&A    18

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange gain of $0.4 million for Q3/2020 and YTD 2020 compared to a loss of $0.4 million for Q3/2019 and YTD 2019.

Income Taxes

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2020		2019		Change		2020		2019		Change
Current income tax expense	$	322	$	501	$	(179)	$	880	$	1,591	$	(711)
Deferred income tax expense (recovery)	696		1,082		(386)		(261,481)		(14,958)		(246,523)
Total income tax expense (recovery)	$	1,018	$	1,583	$	(565)	$	(260,601)	$	(13,367)	$	(247,234)

Current income tax expense was $0.3 million for Q3/2020 and $0.9 million for YTD 2020 compared to $0.5 million for Q3/2019 and $1.6 million in YTD 2019. Current income tax was lower in both periods of 2020 due to lower state tax owed on our U.S. operations relative to the comparative periods of 2019.

We recorded a deferred tax recovery of $261.5 million for YTD 2020 which was lower compared to a $15.0 million recovery for YTD 2019 as income before tax was lower due to the impairment recorded in Q1/2020. We recorded a deferred income tax expense of $0.7 million for Q3/2020 compared to $1.1 million for Q3/2019. Deferred income tax expense for Q3/2020 did not decrease in proportion to the decrease in net income relative to Q3/2019 as deferred income tax in our Canadian operations is offset by a change in the valuation allowance recorded against the deferred income tax asset in Canada.

As disclosed in the 2019 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) that deny $591 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 2020 MD&A    19

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, 2020 and 2019 are set forth in the following table.

	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2020		2019		Change		2020		2019		Change
Petroleum and natural gas sales	$	252,538	$	424,600	$	(172,062)	$	741,841	$	1,360,024	$	(618,183)
Royalties	(40,052)		(75,017)		34,965		(125,928)		(242,959)		117,031
Revenue, net of royalties	212,486		349,583		(137,097)		615,913		1,117,065		(501,152)
Expenses
Operating	(73,447)		(97,377)		23,930		(251,597)		(298,143)		46,546
Transportation	(6,372)		(9,903)		3,531		(21,745)		(35,102)		13,357
Blending and other	(10,673)		(12,950)		2,277		(37,490)		(50,628)		13,138
Operating netback	$	121,994	$	229,353	$	(107,359)	$	305,081	$	733,192	$	(428,111)
General and administrative	(7,741)		(9,934)		2,193		(24,954)		(35,576)		10,622
Cash financing and interest	(25,418)		(26,752)		1,334		(81,340)		(83,028)		1,688
Realized financial derivatives (loss) gain	(9,743)		20,857		(30,600)		30,731		52,664		(21,933)
Realized foreign exchange gain (loss)	351		(382)		733		437		(426)		863
Other income	—		738		(738)		2,007		5,044		(3,037)
Current income tax expense	(322)		(501)		179		(880)		(1,591)		711
Share-based compensation	(613)		—		(613)		(1,752)		—		(1,752)
Adjusted funds flow	$	78,508	$	213,379	$	(134,871)	$	229,330	$	670,279	$	(440,949)
Exploration and evaluation	(8,909)		(2,138)		(6,771)		(11,000)		(8,667)		(2,333)
Depletion and depreciation	(106,454)		(180,422)		73,968		(392,380)		(551,548)		159,168
Non-cash share-based compensation	(2,336)		(3,401)		1,065		(6,973)		(14,245)		7,272
Non-cash financing and accretion	(2,544)		(5,014)		2,470		(16,072)		(14,021)		(2,051)
Non-cash other income	293		—		293		293		—		293
Unrealized financial derivatives (loss) gain	(7,284)		7,666		(14,950)		19,425		(30,922)		50,347
Unrealized foreign exchange gain (loss)	25,880		(13,855)		39,735		(28,125)		38,404		(66,529)
Gain on dispositions	98		18		80		246		1,075		(829)
Impairment	—		—		—		(2,716,349)		—		(2,716,349)
Deferred income tax (expense) recovery	(696)		(1,082)		386		261,481		14,958		246,523
Net income (loss) for the period	$	(23,444)	$	15,151	$	(38,595)	$	(2,660,124)	$	105,313	$	(2,765,437)

We generated adjusted funds flow of $78.5 million for Q3/2020 and $229.3 million for YTD 2020 compared to $213.4 million reported in Q3/2019 and $670.3 million for YTD 2019. The decrease in adjusted funds flow in both periods of 2020 is primarily due to the decline in commodity benchmark prices which resulted in a $133.1 million decrease in revenue, net of royalties and blending and other expense for Q3/2020 and a $486.3 million decrease for YTD 2020. This decrease in adjusted funds flow in 2020 relative to 2019 was mitigated by our costs savings initiatives which resulted in a $29.7 million reduction in operating, transportation, and general and administrative expenses for Q3/2020 and $70.5 million for YTD 2020.

We reported a net loss of $23.4 million for Q3/2020 and $2.7 billion for YTD 2020 compared to net income of $15.2 million and $105.3 million for Q2/2019 and YTD 2019 respectively. The net loss for Q3/2020 was primarily a result of lower commodity prices and shut-in production which resulted in a $134.9 million decrease in adjusted funds flow compared to Q3/2019. This decrease was partially offset by lower depletion and unrealized gains and losses on derivatives and foreign exchange in Q3/2020 relative to Q3/2019 which resulted in the $38.6 million decrease in net income over the same period. We recorded total impairments of $2.7 billion during YTD 2020 which was the main reason for the net loss of $2.7 billion recorded for the period.

Other Comprehensive Income (Loss)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in profit or loss. The foreign currency translation loss of $30.3 million for Q3/2020 and the gain of $90.2 million for YTD 2020 relates to the change in value of our U.S. net assets expressed in Canadian dollars and is due to the change of the Canadian dollar relative to the U.S. dollar at September 30, 2020 compared to June 30, 2020 and December 31, 2019. The CAD/USD exchange rate was 1.3324 CAD/USD as at September 30, 2020 compared to 1.3616 CAD/USD at March 31, 2020 and 1.2965 CAD/USD at December 31, 2019.

Baytex Energy Corp.                                            

Q3 2020 MD&A    20

Capital Expenditures

Capital expenditures for the three and nine months ended September 30, 2020 and 2019 are summarized as follows.

	Three Months Ended September 30
	2020						2019
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	—	$	12,020	$	12,020	$	85,633	$	38,731	$	124,364
Facilities	2,056		—		2,056		9,934		2,991		12,925
Land, seismic and other	1,826		—		1,826		1,207		589		1,796
Total exploration and development	$	3,882	$	12,020	$	15,902	$	96,774	$	42,311	$	139,085
Total acquisitions, net of proceeds from divestitures	$	(98)	$	—	$	(98)	$	(30)	$	—	$	(30)
	Nine Months Ended September 30
	2020						2019
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	99,545	$	71,859	$	171,404	$	228,570	$	120,716	$	349,286
Facilities	23,753		299		24,052		31,401		7,573		38,974
Land, seismic and other	6,624		451		7,075		9,932		982		10,914
Total exploration and development	$	129,922	$	72,609	$	202,531	$	269,903	$	129,271	$	399,174
Total acquisitions, net of proceeds from divestitures	$	(149)	$	—	$	(149)	$	1,617	$	—	$	1,617

Exploration and development expenditures were $15.9 million for Q3/2020 and $202.5 million for YTD 2020 compared to $139.1 million for Q3/2019 and $399.2 million for YTD 2019. Expenditures in Q3/2020 and YTD 2020 were lower than the comparative periods of 2019 as we suspended our operated capital activity in Canada and moderated the pace of development in the U.S. in response to the significant decline in crude oil prices in March 2020.

In Canada, we invested $3.9 million on exploration and development activities in Q3/2020 which is $92.9 million lower than $96.8 million in Q3/2019. Development expenditures of $3.9 million for Q3/2020 relate to $2.1 million of well-site equipping costs associated with Q4/2020 completion activity along with land acquisition costs of $1.8 million. Drilling and completion operations were suspended after the sharp decline in crude oil prices in March 2020 and we did not drill any wells in our Canadian operations during Q3/2020. Exploration and development expenditures of $129.9 million for YTD 2020 included costs associated with drilling 72 (69.2 net) light oil wells in the Viking, 2 (2.0 net) light oil wells in the Duvernay, 33 (33.0 net) heavy oil wells, 6 (6.0 net) stratigraphic exploration wells and investing $23.8 million on facilities. Exploration and development expenditures of $269.9 million for YTD 2019 included costs associated with 223 (193.7 net) light oil wells, 25 (25.0 net) heavy oil wells and 4 (4.0 net) stratigraphic exploration wells. Total exploration and development costs were lower in YTD 2020 relative to YTD 2019 as we suspended development operations following the sharp decline in crude oil pricing in March 2020.

Total U.S. exploration and development expenditures were $12.0 million for Q3/2020 which is $30.3 million lower than $42.3 million for Q3/2019. Exploration and development expenditures of $12.0 million included costs associated with drilling 22 (5.4 net) wells along with 6 (0.8 net) wells that were brought on production during Q3/2020. Exploration and development expenditures of $72.6 million for YTD 2020 included costs associated with the drilling of 39 (9.2 net) wells and completion activities on 53 (11.5 net) wells. Development expenditures were lower in YTD 2020 which was primarily due to lower drilling and completions activity relative to YTD 2019 when we drilled 65 (14.5 net) wells and brought 85 (18.5 net) wells on production and spent $129.3 million.

Our 2020 annual guidance range of $260 - $290 million reflects a more active development program in Q4/2020 in Canada and the U.S. in anticipation of an improved price environment leading into 2021.

Baytex Energy Corp.                                            

Q3 2020 MD&A    21

CAPITAL RESOURCES AND LIQUIDITY

We took action to improve our capital structure and financial liquidity during YTD 2020. On February 5, 2020, we issued US$500 million of senior unsecured notes bearing interest at 8.75% which mature on April 1, 2027. Proceeds from the issuance were used in conjunction with availability on our credit facilities to complete the early redemption of the US$400 million principal amount of 5.125% senior unsecured notes due June 1, 2021 and the $300 million principal amount of 6.625% senior unsecured notes due July 19, 2022. We also negotiated an extension to the maturity of our credit facilities from April 2, 2021 to April 2, 2024. As a result of these actions we do not have any debt maturities until 2024 and we had $425.8 million of undrawn capacity on our credit facilities at September 30, 2020.

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, 2020, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivable, trade and other payables and the credit facilities.

During 2020 we took additional action to protect our financial liquidity in response to lower oil prices and the global economic instability related to COVID-19. Our 2020 exploration and development expenditures were reduced by moderating the pace of activity in the U.S. and suspending drilling and completion operations in Canada. Certain high cost, low margin, production was shut-in for a portion of 2020 when netbacks were challenged by low commodity prices. We remain committed to our cost savings initiatives which resulted in lower operating expenses and general administrative costs during YTD 2020. We have also taken advantage of all government assistance programs available to our industry. These actions resulted in free cash flow of $59.9 million for Q3/2020 and $16.3 million for YTD 2020.

The capital intensive nature of our operations requires us to maintain adequate sources of liquidity to fund ongoing exploration and development. Our capital resources consist primarily of adjusted funds flow, available credit facilities and proceeds received from the divestiture of oil and gas properties. We believe that our internally generated adjusted funds flow and our existing undrawn 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 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.

At September 30, 2020, net debt of $1.91 billion was $34.3 million higher than $1.87 billion at December 31, 2019. Free cash flow of $16.3 million generated during YTD 2020 was directed towards debt repayment and reduced net debt at September 30, 2020. Net debt increased due to a $30.9 million increase in the reported amount of our U.S. dollar denominated net debt at September 30, 2020 due to a weaker Canadian dollar. We also incurred total transaction and financing costs of $17.6 million related to the refinancing transactions in Q1/2020 including the issuance of the US$500 million senior notes due 2027, the early redemption of the US$400 million senior notes due 2021 and the $300 million senior notes due 2022 along with extending the maturity of our credit facilities to 2024.

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a twelve month trailing basis. At September 30, 2020, our net debt to adjusted funds flow ratio was 4.1 compared to a ratio of 2.1 as at December 31, 2019. The increase in the net debt to adjusted funds flow ratio relative to December 31, 2019 is attributed to lower adjusted funds flow due to lower commodity pricing.

Credit Facilities

At September 30, 2020, the principal amount of credit facilities and letters of credit outstanding was $640.3 million and we had $425.8 million of undrawn capacity under our credit facilities that total approximately $1.07 billion. Our credit facilities include US$575 million of revolving credit facilities and a $300 million non-revolving term loan (collectively, the "Credit Facilities").

On March 3, 2020, we amended our Credit Facilities to extend maturity from April 2, 2021 to April 2, 2024. These facilities 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, plus applicable margins. In the event that Baytex breaches any of the covenants under the Credit Facilities, Baytex may be required to repay, refinance or renegotiate the loan terms and may be restricted from taking on further debt or paying dividends to shareholders.

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 1.9% for Q3/2020 and 2.5% for YTD 2020 compared to 3.6% for Q3/2019 and 3.7% for YTD 2019.

Financial Covenants

At September 30, 2020, we were in compliance with all of the covenants contained in our Credit Facilities and we expect to remain in compliance with the financial covenants applicable to our credit facilities at current forward commodity prices. A decrease or a sustained period of low commodity prices may result in non-compliance with our financial covenants and reduced liquidity on our existing credit facilities. Non-compliance with the financial covenants in our credit facilities could result in our debt becoming due and payable on demand.

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at September 30, 2020.

Covenant Description	Position as at September 30, 2020	Covenant
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio)	1.1:1.0	3.5:1.0
Interest Coverage(3) (Minimum Ratio)	5.4:1.0	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, 2020, the Company's Senior Secured Debt totaled $640.3 million which includes $624.8 million of principal amounts outstanding and $15.5 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, 2020 was $566.1 million.

(3)Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expenses, excluding accretion of debt issue costs and asset retirement obligations, for the three months ended September 30, 2020 were $105.2 million.

Long-Term Notes

We have two series of long-term notes outstanding that total $1.2 billion as at September 30, 2020. The long-term notes do not contain any financial maintenance covenants. The long-term notes contain a debt incurrence covenant that restricts our ability to raise additional debt beyond our existing Credit Facilities and long-term notes unless we maintain a minimum fixed charge coverage ratio (computed as the ratio of Bank EBITDA to financing and interest expenses on a trailing twelve month basis) of 2.00:1.00. The fixed charge coverage ratio was 5.0:1.0 as at September 30, 2020.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "5.125% Notes"), which were redeemed February 20, 2020, and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"), which remain outstanding. The 5.625% Notes pay interest semi-annually with the principal amount repayable at maturity. As of June 1, 2019, the 5.625% Notes are redeemable at our option, in whole or in part, at specified redemption prices and will be redeemable at par from June 1, 2022 to maturity.

On February 5, 2020, we issued US$500 million aggregate principal amount of senior unsecured notes due April 1, 2027 bearing interest at a rate of 8.75% per annum payable semi-annually (the "8.75% Senior Notes)". The 8.75% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023 and will be redeemable at par from April 1, 2026 to maturity. Transaction costs of $12.5 million were incurred in conjunction with the issuance which resulted in net proceeds of $652.2 million.

On February 20, 2020, we used a portion of the net proceeds from the issuance of the 8.75% Senior Notes to complete the early redemption of the US$400 million principal amount of the 5.125% senior unsecured notes due June 1, 2021 at par plus accrued interest. The payment at redemption was $530.4 million.

On March 5, 2020, we completed the early redemption of the $300 million principal amount of the 6.625% senior unsecured notes due July 19, 2022 at 101.104% of the principal amount plus accrued interest. The payment at redemption includes principal of $300.0 million plus early redemption expense of $3.3 million.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the nine months ended September 30, 2020, we issued 2.9 million common shares pursuant to our share-based compensation program. As at November 2, 2020, we had 561.2 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, 2020 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	$	179,482	$	179,482	$	—	$	—	$	—
Credit facilities(1) (2)	624,826		—		—		624,826		—
Long-term notes(2)	1,199,160		—		—		532,960		666,200
Interest on long-term notes(3)	489,037		88,272		176,543		136,544		87,678
Lease agreements	11,132		6,086		4,449		597		—
Processing agreements	8,912		3,403		1,396		503		3,610
Transportation agreements	102,101		13,619		41,372		28,345		18,765
Total	$	2,614,650	$	290,862	$	223,760	$	1,323,775	$	776,253

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

(2)Principal amount of instruments.

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

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

Baytex Energy Corp.                                            

Q3 2020 MD&A    22

QUARTERLY FINANCIAL INFORMATION

	2020			2019				2018
($ thousands, except per common share amounts)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Petroleum and natural gas sales	252,538	152,689	336,614	445,895	424,600	482,000	453,424	358,437
Net income (loss)	(23,444)	(138,463)	(2,498,217)	(117,772)	15,151	78,826	11,336	(231,238)
Per common share - basic	(0.04)	(0.25)	(4.46)	(0.21)	0.03	0.14	0.02	(0.42)
Per common share - diluted	(0.04)	(0.25)	(4.46)	(0.21)	0.03	0.14	0.02	(0.42)
Adjusted funds flow	78,508	17,887	132,935	232,147	213,379	236,130	220,770	110,828
Per common share - basic	0.14	0.03	0.24	0.42	0.38	0.42	0.40	0.20
Per common share - diluted	0.14	0.03	0.24	0.42	0.38	0.42	0.40	0.20
Exploration and development	15,902	9,852	176,777	153,117	139,085	106,246	153,843	184,162
Canada	3,882	2,929	123,110	104,460	96,774	68,259	104,870	125,507
U.S.	12,020	6,923	53,667	48,657	42,311	37,987	48,973	58,655
Acquisitions, net of divestitures	(98)	(11)	(40)	563	(30)	1,647	—	229
Net debt	1,906,079	1,994,953	2,051,617	1,871,791	1,971,339	2,028,686	2,175,241	2,265,167
Total assets	3,156,414	3,267,820	3,441,040	5,914,083	6,233,875	6,222,190	6,359,157	6,377,198
Common shares outstanding	561,163	560,545	560,483	558,305	557,972	556,798	555,872	554,060
Daily production
Total production (boe/d)	77,814	72,508	98,452	96,360	94,927	98,402	101,115	98,890
Canada (boe/d)	49,164	37,691	62,262	57,794	58,134	58,580	60,018	60,453
U.S. (boe/d)	28,650	34,817	36,190	38,566	36,793	39,822	41,097	38,437
Benchmark prices
WTI oil (US$/bbl)	40.93	27.85	46.17	56.96	56.45	59.81	54.90	58.81
WCS heavy (US$/bbl)	31.84	16.38	25.65	41.13	44.21	49.14	42.61	19.39
CAD/USD avg exchange rate	1.3316	1.3860	1.3445	1.3201	1.3207	1.3376	1.3293	1.3215
AECO gas ($/mcf)	2.18	1.91	2.14	2.34	1.04	1.17	1.94	1.94
NYMEX gas (US$/mmbtu)	1.98	1.72	1.95	2.50	2.23	2.64	3.15	3.64
Sales price ($/boe)	33.79	22.31	35.19	48.25	47.14	51.49	47.98	37.89
Royalties ($/boe)	(5.59)	(4.42)	(6.33)	(8.72)	(8.59)	(9.67)	(8.94)	(8.77)
Operating expense ($/boe)	(10.26)	(11.17)	(11.66)	(11.23)	(11.15)	(11.22)	(11.02)	(10.76)
Transportation expense ($/boe)	(0.89)	(0.76)	(1.15)	(1.00)	(1.13)	(1.33)	(1.46)	(1.21)
Operating netback ($/boe)	17.05	5.96	16.05	27.30	26.27	29.27	26.56	17.15
Financial derivatives gain (loss) ($/boe)	(1.36)	2.06	3.00	2.59	2.39	1.45	2.07	(0.34)
Operating netback after financial derivatives ($/boe)	15.69	8.02	19.05	29.89	28.66	30.72	28.63	16.81

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 reached a high of 101,115 boe/d during Q1/2019 after relatively stable crude oil prices supported an active development program in Canada and the U.S. leading into 2019. Production was relatively consistent in the quarters following Q1/2019 until we shut-in production in Canada and moderated the pace of activity in the U.S. after the sharp decline in crude oil prices in March 2020. Production of 77,814 boe/d for Q3/2020 reflects reduced capital spending in response to low commodity prices for the second consecutive quarter.

North American benchmark commodity prices were stable throughout 2019 and were relatively strong leading into Q1/2020 with the West Texas Intermediate ("WTI") benchmark price averaging US$57.53/bbl in January. 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 during Q3/2020 as OPEC+ agreed to reinstate production curtailments and measures to control the spread of COVID-19 were relaxed. Despite this

Baytex Energy Corp.                                            

Q3 2020 MD&A    23

recent improvement commodity prices remained low with WTI averaging US$40.93/bbl for Q3/2020. The impact of low commodity prices is reflected in our realized sales price of $33.79/boe for Q3/2020. Our development programs were significantly reduced in Canada and the U.S. as a result of this decline in crude oil pricing with exploration and development spending of $15.9 million during Q3/2020.

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 throughout 2019 due to increased production and strong well performance along with higher realizations associated with the higher weighting of light oil production. Adjusted funds flow of $78.5 million in Q3/2020 reflects the impact of lower commodity prices and reduced development expenditures.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt has decreased from $2.3 billion at Q4/2018 to $1.9 billion at Q3/2020 which is primarily due to adjusted funds flow exceeding exploration and development expenditures by $303.6 million over the last eight quarters which reflects our efforts to preserve liquidity during periods of challenging crude oil prices. Our net debt has also be reduced by a decrease in the CAD/USD exchange rate used to translate our U.S. dollar denominated debt from 1.3646 CAD/USD at Q4/2018 to 1.3324 CAD/USD at Q3/2020.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 2020, 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, 2020. 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, 2019.

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 trading period. At this time, Baytex has not regained compliance and expects that its common shares will be delisted from the NYSE on December 3, 2020.

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 2020 MD&A    24

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

	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2020		2019		2020		2019
Cash flow from operating activities	$	93,688	$	194,970	$	302,079	$	599,920
Change in non-cash working capital	(16,391)		17,275		(78,829)		59,499
Asset retirement obligations settled	1,211		1,134		6,080		10,860
Adjusted funds flow	$	78,508	$	213,379	$	229,330	$	670,279

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)	2020		2019		2020		2019
Cash flow used in investing activities	$	16,288	$	150,651	$	233,092	$	447,835
Change in non-cash working capital	(444)		(11,577)		(28,683)		(46,646)
Proceeds from dispositions	98		150		149		1,100
Property acquisitions	—		(120)		—		(2,717)
Additions to other plant and equipment	(40)		(19)		(2,027)		(398)
Exploration and development expenditures	$	15,902	$	139,085	$	202,531	$	399,174

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)	2020		2019		2020		2019
Adjusted funds flow	$	78,508	$	213,379	$	229,330	$	670,279
Exploration and development expenditures	(15,902)		(139,085)		(202,531)		(399,174)
Payments on lease obligations	(1,456)		(1,390)		(4,440)		(4,402)
Asset retirement obligations settled	(1,211)		(1,134)		(6,080)		(10,860)
Free cash flow	$	59,939	$	71,770	$	16,279	$	255,843

Baytex Energy Corp.                                            

Q3 2020 MD&A    25

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, 2020		December 31, 2019
Credit facilities(1)	$	624,826	$	506,471
Long-term notes(1)	1,199,160		1,337,200
Trade and other payables	179,482		207,454
Cash	—		(5,572)
Trade and other receivables	(97,389)		(173,762)
Net debt	$	1,906,079	$	1,871,791

(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)	2020		2019		2020		2019
Petroleum and natural gas sales	$	252,538	$	424,600	$	741,841	$	1,360,024
Blending and other expense	(10,673)		(12,950)		(37,490)		(50,628)
Total sales, net of blending and other expense	241,865		411,650		704,351		1,309,396
Royalties	(40,052)		(75,017)		(125,928)		(242,959)
Operating expense	(73,447)		(97,377)		(251,597)		(298,143)
Transportation expense	(6,372)		(9,903)		(21,745)		(35,102)
Operating netback	121,994		229,353		305,081		733,192
Realized financial derivative (loss) gain	(9,743)		20,857		30,731		52,664
Operating netback after realized financial derivatives	$	112,251	$	250,210	$	335,812	$	785,856

Baytex Energy Corp.                                            

Q3 2020 MD&A    26

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)	2020		2019
Net income (loss)	$	(2,777,896)	$	(125,925)
Plus:
Financing and interest	126,228		129,310
Unrealized foreign exchange (gain) loss	3,776		29,603
Unrealized financial derivatives (gain) loss	32,470		(150,933)
Current income tax expense	1,382		1,627
Deferred income tax expense (recovery)	(315,078)		(64,785)
Depletion and depreciation	572,518		745,578
Gain on dispositions	(1,409)		(1,257)
Transaction costs	—		8
Impairment	2,904,171		285,341
Non-cash items(1)	18,619		44,803
Bank EBITDA	$	564,781	$	893,370

(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, 2020.

Baytex Energy Corp.                                            

Q3 2020 MD&A    27

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; that the outlook for our industry is uncertain; our capital budget and expected average daily production for 2020; our expected royalty rate and operating, transportation, general and administrative and interest expenses for 2020; the existence, operation and strategy of our risk management program; that we committed to cost savings initiatives; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; that our internally generated adjusted funds flow and our existing undrawn credit facilities will provide sufficient liquidity to sustain our operations and planned capital expenditures; that a significant portion of our financial obligations will be funded by adjusted funds flow; we expect to remain in compliance with the financial covenants; that we expect to be delisted from the NSYE on December 3rd, 2020 and that we do not expect the delisting to affect our business operations or the listing and trading of our common shares on the TSX.

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, 2019, 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.