Document

EX-99.2 3 a992-q32022mda.htm EX-99.2 Document

Baytex Energy Corp.

Q3 2022 MD&A 1

Exhibit 99.2

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and nine months ended September 30, 2022 and 2021

Dated November 3, 2022

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, 2022. This information is provided as of November 3, 2022. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and nine months ended September 30, 2022 ("Q3/2022" and "YTD 2022") have been compared with the results for the three and nine months ended September 30, 2021 ("Q3/2021" and "YTD 2021"). This MD&A should be read in conjunction with the Company’s condensed consolidated interim financial statements (“consolidated financial statements”) for the three and nine months ended September 30, 2022, its audited comparative consolidated financial statements for the years ended December 31, 2021 and 2020, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2021. These documents and additional information about Baytex are accessible on the SEDAR website at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.

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

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

BAYTEX ENERGY CORP.

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

THIRD QUARTER HIGHLIGHTS

Baytex delivered solid operating and financial results in Q3/2022. Energy prices remained strong due to uncertainty surrounding global energy security while recent concerns over high inflation and slowing economic activity have caused recent declines in oil prices. As a result, the average WTI benchmark price for Q3/2022 was US$91.56/bbl which was US$21.00/bbl higher than Q3/2021 when WTI averaged US$70.56/bbl. Strong benchmark prices contributed to adjusted funds flow(1) of $284.3 million and free cash flow(2) of $111.6 million. Production increased to 83,194 boe/d in Q3/2022 compared to 79,872 boe/d in Q3/2021 primarily from strong well results in our Clearwater program. Production was consistent with our expectations and within our annual guidance range of 83,000 - 85,000 boe/d.

Exploration and development expenditures were $167.5 million for Q3/2022 with $117.2 million invested in Canada and $50.3 million in the U.S. In Canada, we brought 11 (8.6 net) heavy oil wells and 45 (43.5 net) light oil wells on production during Q3/2022. In the U.S., we brought 19 (4.1 net) wells on production during Q3/2022. Production in Canada was 55,803 boe/d in Q3/2022, a 7,679 boe/d increase from Q3/2021, driven primarily from our success in the Clearwater play at Peavine. In the U.S. production decreased to 27,391 boe/d in Q3/2022 from 31,748 boe/d in Q3/2021 with less activity on our lands in 2022.

Adjusted funds flow of $284.3 million and free cash flow of $111.6 million in Q3/2022 were higher than $198.4 million and $101.2 million for Q3/2021, respectively, as a result of higher benchmark prices and production. Our strong operating and financial results contributed to net income of $265.0 million for Q3/2022 compared to net income of $32.7 million in Q3/2021.

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

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

Baytex Energy Corp.

Q3 2022 MD&A 2

We used free cash flow generated during Q3/2022 for debt reduction and to continue our shareholder returns. We repurchased and cancelled 12.6 million common shares for $78.8 million during the quarter, for a total of 21.6 million shares for $141.3 million repurchased as of Q3/2022, representing 3.8% of the shares outstanding at commencement of the normal course issuer bid.

Net debt(1) was $1.11 billion at September 30, 2022 compared to $1.12 billion at Q2/2022 and $1.41 billion at Q4/2021. The reduction from Q4/2021 reflects YTD 2022 free cash flow(2) of $478.2 million along with $25.5 million of disposition proceeds offset by $141.3 million of share repurchases and a $63.9 million increase in the reported amount of our U.S. dollar denominated net debt due to the weakening of the Canadian dollar relative to the U.S. dollar during YTD 2022.

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

2022 GUIDANCE

We now anticipate 2022 exploration and development expenditures of approximately $515 million which is up from our previously targeted $500 million (representing the high end of our prior guidance range of $450 to $500 million). The incremental capital largely reflects the impact of a strengthening U.S. dollar relative to the Canadian dollar, on our U.S. operations and further level loading of activity through year-end to maintain the efficiency of our operations.

We have increased our general and administrative expense by 12% to reflect the impacts of inflation and expanded staffing levels associated with our higher pace of activity along with anticipated performance based pay reflecting our strong financial performance to date. We have also updated our interest expense guidance to reflect higher interest rates on our credit facilities and the impact of a strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt.

The following table highlights our 2022 annual guidance.

Previous Annual Guidance (1)

Revised Annual Guidance

Exploration and development expenditures

$450 - $500 million

~ $515 million

Production (boe/d)

83,000 - 85,000

~ 84,000 boe/d

Expenses:

Average royalty rate (2)

21.0% - 22.0%

no change

Operating (3)

$13.75 - $14.25/boe

no change

Transportation (3)

$1.50 - $1.60/boe

no change

General and administrative (3)

$43 million ($1.40/boe)

$48 million ($1.57/boe)

Interest (3)

$75 million ($2.45/boe)

$79 million ($2.58/boe)

Leasing expenditures

$3 million

no change

Asset retirement obligations

$20 million

no change

(1)As announced on July 27, 2022.

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

Baytex Energy Corp.

Q3 2022 MD&A 3

RESULTS OF OPERATIONS

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

Production


	Three Months Ended September 30
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	16,509		16,738		33,247		16,532		19,082		35,614
Heavy oil	29,244		—		29,244		21,996		—		21,996
Natural Gas Liquids (NGL)	1,873		5,663		7,536		1,230		5,944		7,174
Total liquids (bbl/d)	47,626		22,401		70,027		39,758		25,026		64,784
Natural gas (mcf/d)	49,060		29,943		79,003		50,197		40,331		90,528
Total production (boe/d)	55,803		27,391		83,194		48,124		31,748		79,872

Production Mix
Segment as a percent of total	67	%	33	%	100	%	60	%	40	%	100	%

Light oil and condensate	30	%	61	%	40	%	34	%	60	%	45	%
Heavy oil	52	%	—	%	35	%	46	%	—	%	28	%
NGL	3	%	21	%	9	%	3	%	19	%	9	%
Natural gas	15	%	18	%	16	%	17	%	21	%	18	%

	Nine Months Ended September 30
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	16,582		16,855		33,437		17,130		18,930		36,060
Heavy oil	27,703		—		27,703		21,752		—		21,752
Natural Gas Liquids (NGL)	1,875		5,671		7,546		1,657		5,338		6,995
Total liquids (bbl/d)	46,160		22,526		68,686		40,539		24,268		64,807
Natural gas (mcf/d)	51,303		30,929		82,232		51,416		39,396		90,812
Total production (boe/d)	54,711		27,681		82,392		49,108		30,834		79,942

Production Mix
Segment as a percent of total	66	%	34	%	100	%	61	%	39	%	100	%

Light oil and condensate	30	%	61	%	41	%	35	%	61	%	45	%
Heavy oil	51	%	—	%	34	%	44	%	—	%	27	%
NGL	3	%	20	%	9	%	3	%	17	%	9	%
Natural gas	16	%	19	%	16	%	18	%	22	%	19	%

Production was 83,194 boe/d for Q3/2022 and 82,392 boe/d for YTD 2022 compared to 79,872 boe/d for Q3/2021 and 79,942 boe/d for YTD 2021. Total production was higher in Q3/2022 and YTD 2022 compared to comparable periods of 2021 due to our successful development program in Canada which includes strong well results from our Clearwater development program.

Baytex Energy Corp.

Q3 2022 MD&A 4

In Canada, production was 55,803 boe/d for Q3/2022 and 54,711 boe/d for YTD 2022 compared to 48,124 boe/d for Q3/2021 and

49,108 boe/d for YTD 2021. Our successful 2022 development program and strong well performance from our Clearwater development program has resulted in production that was 7,679 boe/d higher in Q3/2022 and 5,603 boe/d higher YTD 2022 relative to the comparative periods of 2021.

In the U.S., production was 27,391 boe/d for Q3/2022 and 27,681 boe/d for YTD 2022 compared to 31,748 boe/d for Q3/2021 and

30,834 boe/d for YTD 2021. U.S. production was lower in 2022 due to reduced activity levels during the second half of 2021 and YTD 2022. We initiated production from 56 (12.7 net) wells during YTD 2022 compared to 79 (20.6 net) wells during the comparative period in 2021.

Total production of 82,392 boe/d for YTD 2022 is consistent with expectations and is slightly below our annual guidance of approximately 84,000 boe/d for 2022 as we are targeting an exit rate of 87,000 - 88,000 boe/d for Q4/2022.

COMMODITY PRICES

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

Crude Oil

Global benchmark pricing for crude oil decreased during Q3/2022 due to the release of barrels from the U.S. Strategic Petroleum Reserve which increased supply along with concerns over slowing economic activity and reduced future demand. Despite these recent declines, crude oil prices remained higher relative to 2021 due to strong demand and heightened concern over supply caused by the conflict in Ukraine. The WTI price averaged US$91.56/bbl for Q3/2022 and US$98.09/bbl for YTD 2022 compared to Q3/2021 and YTD 2021 when WTI averaged US$70.56/bbl and US$64.82/bbl, respectively.

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$96.15/bbl during Q3/2022 and US$101.76/bbl during YTD 2022 which is higher than US$71.64/bbl during Q3/2021 and US$66.05/bbl during YTD 2021. The MEH benchmark trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$4.59/bbl and US$3.67/bbl for Q3/2022 and YTD 2022 compared to premiums of US$1.08/bbl and US$1.23/bbl for Q3/2021 and YTD 2021, respectively. The MEH benchmark traded at a higher premium to WTI in both periods of 2022 as a result of heightened uncertainty over global supply relative to 2021.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $116.79/bbl during Q3/2022 and $123.41/bbl during YTD 2022 compared to $83.78/bbl during Q3/2021 and $75.88/bbl during YTD 2021. Edmonton par traded at a discount to WTI of US$2.13/bbl for Q3/2022 and US$1.89/bbl for YTD 2022 which is slightly narrower compared to a discount of US$4.07/bbl for Q3/2021 and US$4.19/bbl for YTD 2021 due to higher demand for Canadian light oil in 2022.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q3/2022 and YTD 2022 averaged $93.62/bbl and $105.65/bbl, respectively, compared to $71.81/bbl and $65.47/bbl for the same periods of 2021. The WCS heavy oil differential was US$19.87/bbl in Q3/2022 and US$15.74/bbl in YTD 2022 which is wider than US$13.57/bbl for Q3/2021 and US$12.51/bbl for YTD 2021 due to reduced refining capacity for Canadian heavy oil following the release of oil from the U.S. Strategic Petroleum Reserve and refining outages.

Natural Gas

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. Strong global demand to replace Russian supply of natural gas resulted in higher NYMEX benchmark prices in 2022 relative to 2021.The NYMEX natural gas benchmark averaged US$8.20/mmbtu for Q3/2022 and US$6.77/mmbtu for YTD 2022 compared to US$4.01/mmbtu for Q3/2021 and US$3.18/mmbtu for YTD 2021.

In Canada, we receive natural gas pricing based on the AECO benchmark which continues to trade at a discount to NYMEX as a result of limited market access for Canadian natural gas production. Increased global demand for natural gas resulted in higher AECO benchmark prices in 2022 relative to 2021 while maintenance on the Nova Gas Transmission Line limited export capacity from Alberta and resulted in a wider AECO basis to NYMEX in 2022 relative to 2021. The AECO benchmark averaged $5.81/mcf during Q3/2022 and $5.56/mcf during YTD 2022 which is higher than $3.54/mcf for Q3/2021 and $3.11/mcf for YTD 2021.

Baytex Energy Corp.

Q3 2022 MD&A 5

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30			Nine Months Ended September 30
	2022	2021	Change	2022	2021	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	91.56	70.56	21.00	98.09	64.82	33.27
MEH oil (US$/bbl) (2)	96.15	71.64	24.51	101.76	66.05	35.71
MEH oil differential to WTI (US$/bbl)	4.59	1.08	3.51	3.67	1.23	2.44
Edmonton par oil ($/bbl) (3)	116.79	83.78	33.01	123.41	75.88	47.53
Edmonton par oil differential to WTI (US$/bbl)	(2.13)	(4.07)	1.94	(1.89)	(4.19)	2.30
WCS heavy oil ($/bbl) (4)	93.62	71.81	21.81	105.65	65.47	40.18
WCS heavy oil differential to WTI (US$/bbl)	(19.87)	(13.57)	(6.30)	(15.74)	(12.51)	(3.23)
AECO natural gas ($/mcf) (5)	5.81	3.54	2.27	5.56	3.11	2.45
NYMEX natural gas (US$/mmbtu) (6)	8.20	4.01	4.19	6.77	3.18	3.59
CAD/USD average exchange rate	1.3059	1.2601	0.0458	1.2829	1.2515	0.0314

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

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

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

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

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

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


	Three Months Ended September 30
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	115.51	$	122.43	$	118.99	$	82.14	$	88.01	$	85.29
Heavy oil, net of blending and other expense ($/bbl) (2)	84.38		—		84.38		62.70		—		62.70
NGL ($/bbl) (1)	46.01		43.43		44.07		36.92		41.94		41.08
Natural gas ($/mcf) (1)	4.96		9.88		6.82		3.71		5.00		4.29
Total sales, net of blending and other expense ($/boe) (2)	$	84.30	$	94.59	$	87.68	$	61.69	$	67.11	$	63.85

	Nine Months Ended September 30
	2022						2021
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	121.19	$	128.65	$	124.95	$	73.29	$	80.98	$	77.33
Heavy oil, net of blending and other expense ($/bbl) (2)	95.10		—		95.10		55.34		—		55.34
NGL ($/bbl) (1)	46.29		44.91		45.25		27.25		36.28		34.14
Natural gas ($/mcf) (1)	5.56		8.29		6.58		3.26		5.42		4.20
Total sales, net of blending and other expense ($/boe) (2)	$	91.68	$	96.79	$	93.40	$	54.41	$	62.92	$	57.69

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

Baytex Energy Corp.

Q3 2022 MD&A 6

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $87.68/boe for Q3/2022 and $93.40/bbl for YTD 2022 compared to $63.85/boe for Q3/2021 and $57.69/boe for YTD 2021. In Canada, our realized price of $84.30/boe for Q3/2022 was $22.61/boe higher than $61.69/boe for Q3/2021. Our realized price in the U.S. was $94.59/boe in Q3/2022 which is $27.48/boe higher than $67.11/boe in Q3/2021. The increase in our realized price in Canada and the U.S. for Q3/2022 and YTD 2022 was a result of higher North American benchmark prices relative to the same periods of 2021.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $115.51/bbl for Q3/2022 and $121.19/bbl for YTD 2022 compared to $82.14/bbl for Q3/2021 and $73.29/bbl for YTD 2021. Our realized light oil and condensate price for Q3/2022 and YTD 2022 increased with the improvement in the benchmark price and represents discounts to the Edmonton par price of $1.28/bbl and $2.22/bbl for Q3/2022 and YTD 2022, respectively, which is consistent with a discount of $1.64/bbl in Q3/2021 and $2.59/bbl in YTD 2021.

We compare the price received for our U.S. light oil and condensate production to the MEH benchmark. Our realized light oil and condensate price averaged $122.43/bbl for Q3/2022 and $128.65/bbl for YTD 2022 compared to $88.01/bbl for Q3/2021 and $80.98/bbl for YTD 2021. Expressed in U.S. dollars, our realized light oil and condensate price of US$93.75/bbl for Q3/2022 and US$100.28/bbl for YTD 2022 represents discounts to MEH of US$2.40/bbl and US$1.48/bbl Q3/2022 and YTD 2022, respectively, which is consistent with discounts of US$1.80/bbl for Q3/2021 and US$1.34/bbl for YTD 2021.

Our realized heavy oil price, net of blending and other expense(1) averaged $84.38/bbl in Q3/2022 and $95.10/bbl in YTD 2022 compared to $62.70/bbl in Q3/2021 and $55.34/bbl in YTD 2021. Our realized heavy oil, net of blending and other expense for Q3/2022 and YTD 2022 was $21.68/bbl and $39.76/bbl higher relative to Q3/2021 and YTD 2021, respectively, which is consistent with a $21.81/bbl and $40.18/bbl increase in the WCS benchmark price over the same periods.

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(2) was $44.07/bbl in Q3/2022 or 37% of WTI (expressed in Canadian dollars) and $45.25/bbl in YTD 2022 or 36% of WTI (expressed in Canadian dollars) compared to $41.08/bbl or 46% of WTI (expressed in Canadian dollars) in Q3/2021 and $34.14/bbl or 42% of WTI (expressed in Canadian dollars) in YTD 2021. The increase in our realized price is primarily a result of higher WTI pricing in 2022 relative to the comparative periods of 2021 as our realization as a percentage of WTI was slightly lower in 2022.

We compare our realized natural gas price in Canada to the AECO benchmark price and to the NYMEX benchmark in the U.S.. Our realized natural gas price(2) in Canada was $4.96/mcf for Q3/2022 and $5.56/mcf for YTD 2022 compared to $3.71/mcf in Q3/2021 and $3.26/mcf for YTD 2021. In the U.S., our realized natural gas price was US$7.57/mcf for Q3/2022 and US$6.46/mcf for YTD 2022 compared to US$3.97/mcf for Q3/2021 and US$4.33/mcf for YTD 2021. The increase in our realized gas price in Canada and the U.S. is relatively consistent with the increases in the AECO and NYMEX benchmarks in 2022 compared to the same periods of 2021.

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

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

Baytex Energy Corp.

Q3 2022 MD&A 7

PETROLEUM AND NATURAL GAS SALES


	Three Months Ended September 30
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	175,447	$	188,521	$	363,968	$	124,930	$	154,511	$	279,441
Heavy oil	267,958		—		267,958		146,468		—		146,468
NGL	7,929		22,627		30,556		4,177		22,932		27,109
Total oil sales	451,334		211,148		662,482		275,575		177,443		453,018
Natural gas sales	22,374		27,209		49,583		17,148		18,570		35,718
Total petroleum and natural gas sales	473,708		238,357		712,065		292,723		196,013		488,736
Blending and other expense	(40,945)		—		(40,945)		(19,581)		—		(19,581)
Total sales, net of blending and other expense (1)	$	432,763	$	238,357	$	671,120	$	273,142	$	196,013	$	469,155

	Nine Months Ended September 30
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	548,588	$	591,946	$	1,140,534	$	342,744	$	418,498	$	761,242
Heavy oil	858,497		—		858,497		385,288		—		385,288
NGL	23,701		69,529		93,230		12,327		52,870		65,197
Total oil sales	1,430,786		661,475		2,092,261		740,359		471,368		1,211,727
Natural gas sales	77,823		69,975		147,798		45,812		58,253		104,065
Total petroleum and natural gas sales	1,508,609		731,450		2,240,059		786,171		529,621		1,315,792
Blending and other expense	(139,280)		—		(139,280)		(56,668)		—		(56,668)
Total sales, net of blending and other expense (1)	$	1,369,329	$	731,450	$	2,100,779	$	729,503	$	529,621	$	1,259,124

Total sales, net of blending and other expense, of $671.1 million for Q3/2022 increased $202.0 million from $469.2 million reported for Q3/2021 while total sales, net of blending and other expense, of $2.1 billion for YTD 2022 increased $841.7 million from $1.3 billion reported for YTD 2021. The increase in total sales is primarily a result of higher realized pricing consistent with the increase in benchmark pricing along with a modest increase in production due to our successful development program in Canada.

In Canada, total sales, net of blending and other expense, was $432.8 million for Q3/2022 which is an increase of $159.6 million from $273.1 million reported for Q3/2021. The increase in total petroleum and natural gas sales was the result of higher realized pricing and increased production volumes for Q3/2022 relative to Q3/2021. Our increased realized price resulted in a $116.0 million increase in total sales, net of blending and other expense, while an increase in production contributed to a $43.6 million increase in total sales, net of blending and other expense, relative to Q3/2021. Improvements in benchmark prices was the primary factor contributing to our total sales, net of blending and other expense, increasing to $1.4 billion in YTD 2022 from $729.5 million in YTD 2021.

In the U.S., petroleum and natural gas sales were $238.4 million for Q3/2022 which is an increase of $42.3 million from $196.0 million reported for Q3/2021. Total petroleum and natural gas sales increased $69.2 million due to higher realized pricing for Q3/2022 relative to Q3/2021 while lower production resulted in a $26.9 million decrease in total sales relative to Q3/2021. Higher realized pricing in YTD 2022 resulted in petroleum and natural gas sales of $731.5 million which was $201.8 million higher than $529.6 million in YTD 2021 despite lower production in YTD 2022 relative to YTD 2021.

Baytex Energy Corp.

Q3 2022 MD&A 8

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30
	2022									2021
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	75,901		$	71,093		$	146,994		$	32,679		$	57,844		$	90,523
Average royalty rate (1)(2)	17.5		%	29.8		%	21.9		%	12.0		%	29.5		%	19.3		%
Royalties per boe (3)	$	14.78		$	28.21		$	19.21		$	7.38		$	19.80		$	12.32

	Nine Months Ended September 30
	2022									2021
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	224,710		$	216,563		$	441,273		$	83,536		$	155,468		$	239,004
Average royalty rate (1)(2)	16.4		%	29.6		%	21.0		%	11.5		%	29.4		%	19.0		%
Royalties per boe (3)	$	15.04		$	28.66		$	19.62		$	6.23		$	18.47		$	10.95

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

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

Royalties for Q3/2022 were $147.0 million or 21.9% of total sales, net of blending and other expense, compared to $90.5 million or 19.3% for Q3/2021. Total royalties for YTD 2022 were $441.3 million or 21.0% of total sales, net of blending and other expense, compared to $239.0 million or 19.0% for YTD 2021. Total royalty expense was higher for Q3/2022 and YTD 2022 due to higher total sales, net of blending and other expense, along with a slight increase in our royalty rate relative to the same periods of 2021. Our royalty rates of 21.9% for Q3/2022 and 21.0% for YTD 2022 were higher than 19.3% for Q3/2021 and 19.0% for YTD 2021 due to a higher royalty rate on our Canadian properties as a result of higher commodity prices. Our average royalty rate of 21.0% for YTD 2022 is at the low end of our annual guidance range of 21.0% - 22.0% for 2022.

Our Canadian royalty rates of 17.5% for Q3/2022 and 16.4% for YTD 2022 were higher than 12.0% for Q3/2021 and 11.5% for YTD 2021 due to higher benchmark commodity prices which resulted in a higher royalty rate on our Canadian properties in 2022 relative to 2021. In the U.S., royalties averaged 29.8% and 29.6% of total sales for Q3/2022 and YTD 2022 respectively, which is consistent with 29.5% for Q3/2021 and 29.4% for YTD 2021 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

Baytex Energy Corp.

Q3 2022 MD&A 9

OPERATING EXPENSE


	Three Months Ended September 30
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	83,141	$	26,998	$	110,139	$	63,301	$	20,895	$	84,196
Operating expense per boe (1)	$	16.19	$	10.71	$	14.39	$	14.30	$	7.15	$	11.46

	Nine Months Ended September 30
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	244,152	$	74,179	$	318,331	$	186,455	$	61,190	$	247,645
Operating expense per boe (1)	$	16.35	$	9.82	$	14.15	$	13.91	$	7.27	$	11.35

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

Total operating expense was $110.1 million ($14.39/boe) for Q3/2022 and $318.3 million ($14.15/boe) for YTD 2022 compared to $84.2 million ($11.46/boe) for Q3/2021 and $247.6 million ($11.35/boe) for YTD 2021. Operating expense for both periods of 2022 increased in total and per boe reflecting increased production and cost inflation throughout our operations in 2022 relative to 2021. Operating expense of $14.15 for YTD 2022 is consistent with our annual guidance range of $13.75 - $14.25/boe for 2022.

In Canada, operating expense was $83.1 million ($16.19/boe) for Q3/2022 and $244.2 million ($16.35/boe) for YTD 2022 compared to $63.3 million ($14.30/boe) for Q3/2021 and $186.5 million ($13.91/boe) for YTD 2021. U.S. operating expense was $27.0 million ($10.71/boe) for Q3/2022 and $74.2 million ($9.82/boe) for YTD 2022 compared to $20.9 million ($7.15/boe) for Q3/2021 and $61.2 million ($7.27/boe) in YTD 2021. Our U.S. operating expenses expressed in U.S. dollars, per unit operating expense was US$8.20/boe in Q3/2022 and US$7.65/boe in YTD 2022 which was higher than US$5.67/boe for Q3/2021 and US$5.81/boe in YTD 2021. The increase in per unit operating expense in Canada and the U.S. was primarily due to increased costs from energy inputs resulting in higher fuel, electricity and hauling costs along with additional workover and maintenance activity in 2022 relative to 2021.

TRANSPORTATION EXPENSE

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

The following table compares our transportation expense for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	12,771	$	—	$	12,771	$	7,818	$	—	$	7,818
Transportation expense per boe (1)	$	2.49	$	—	$	1.67	$	1.77	$	—	$	1.06

	Nine Months Ended September 30
	2022						2021
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	33,744	$	—	$	33,744	$	24,092	$	—	$	24,092
Transportation expense per boe (1)	$	2.26	$	—	$	1.50	$	1.80	$	—	$	1.10

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

Transportation expense was $12.8 million ($1.67/boe) for Q3/2022 and $33.7 million ($1.50/boe) for YTD 2022 compared to $7.8 million ($1.06/boe) for Q3/2021 and $24.1 million ($1.10/boe) for YTD 2021. Total transportation expense and per unit costs are higher in Q3/2022 and YTD 2022 as a result of additional heavy oil production along with higher trucking rates relative to the same periods of 2021 due to higher fuel costs. Per unit transportation expense of $1.50/boe for YTD 2022 is at the low end of our annual guidance of $1.50 - $1.60/boe for 2022.

Baytex Energy Corp.

Q3 2022 MD&A 10

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 $40.9 million for Q3/2022 and $139.3 million for YTD 2022 compared to $19.6 million for Q3/2021 and $56.7 million for YTD 2021. Higher blending and other expense reflects an increase in the price of condensate purchased as diluent along with an increase in heavy oil production shipped via pipeline in 2022 relative to 2021.

FINANCIAL DERIVATIVES

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2022		2021		Change		2022		2021		Change
Realized financial derivatives loss
Crude oil	$	(66,582)	$	(50,384)	$	(16,198)	$	(258,180)	$	(108,658)	$	(149,522)
Natural gas	(9,826)		(3,521)		(6,305)		(26,636)		(5,039)		(21,597)

Total	$	(76,408)	$	(53,905)	$	(22,503)	$	(284,816)	$	(113,697)	$	(171,119)
Unrealized financial derivatives gain (loss)
Crude oil	$	189,613	$	1,520	$	188,093	$	98,111	$	(165,019)	$	263,130
Natural gas	4,018		(13,190)		17,208		(3,253)		(22,475)		19,222

Equity total return swap ("Equity TRS")	(3,160)		2,729		(5,889)		(1,880)		8,086		(9,966)
Total	$	190,471	$	(8,941)	$	199,412	$	92,978	$	(179,408)	$	272,386
Total financial derivatives gain (loss)
Crude oil	$	123,031	$	(48,864)	$	171,895	$	(160,069)	$	(273,677)	$	113,608
Natural gas	(5,808)		(16,711)		10,903		(29,889)		(27,514)		(2,375)

Equity TRS	(3,160)		2,729		(5,889)		(1,880)		8,086		(9,966)
Total	$	114,063	$	(62,846)	$	176,909	$	(191,838)	$	(293,105)	$	101,267

We recorded a total financial derivative gain of $114.1 million for Q3/2022 and a loss of $191.8 million for YTD 2022 compared to a loss of $62.8 million for Q3/2021 and a loss of $293.1 million for YTD 2021. The realized financial derivatives loss of $76.4 million for Q3/2022 and $284.8 million for YTD 2022 were primarily a result of the market prices for crude oil and natural gas settling at levels above those set in our derivative contracts. The unrealized gain of $190.5 million for Q3/2022 and $93.0 million for YTD 2022 reflect changes in forecasted crude oil pricing used to revalue the unsettled notional volume outstanding on our crude oil contracts in place at September 30, 2022 relative to June 30, 2022 and December 31, 2021. The fair value of our financial derivative contracts resulted in a net liability of $32.4 million at September 30, 2022 compared to a net liability of $222.9 million at June 30, 2022 and a net liability of $125.4 million at December 31, 2021.

Baytex Energy Corp.

Q3 2022 MD&A 11

We had the following commodity financial derivative contracts as at November 3, 2022.

Period

Volume

Price/Unit (1)

Index

Oil

Basis Swap

Oct 2022 to Dec 2022

12,000 bbl/d

WTI less US$12.40/bbl

WCS

Basis Swap

Oct 2022 to Dec 2022

6,750 bbl/d

WTI less US$3.73/bbl

MSW

Fixed Sell

Oct 2022 to Dec 2022

10,000 bbl/d

US$53.50/bbl

WTI

3-way option (2)

Oct 2022 to Dec 2022

1,500 bbl/d

US$40.00/US$50.00/US$58.10

WTI

3-way option (2)

Oct 2022 to Dec 2022

2,000 bbl/d

US$46.00/US$56.00/US$66.72

WTI

3-way option (2)

Oct 2022 to Dec 2022

2,500 bbl/d

US$47.00/US$57.00/US$67.00

WTI

3-way option (2)

Oct 2022 to Dec 2022

2,500 bbl/d

US$50.00/US$60.00/US$70.00

WTI

3-way option (2)

Oct 2022 to Dec 2022

2,000 bbl/d

US$53.00/US$63.50/US$72.90

WTI

3-way option (2)

Jan 2023 to Dec 2023

2,000 bbl/d

US$55.00/US$66.00/US$84.00

WTI

3-way option (2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$60.00/US$75.00/US$91.54

WTI

3-way option (2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$65.00/US$85.00/US$100.00

WTI

3-way option (2)

Jan 2023 to Dec 2023

2,500 bbl/d

US$65.00/US$85.00/US$106.50

WTI

Natural Gas

Fixed Sell

Oct 2022 to Dec 2022

5,000 GJ/d

$2.53/GJ

AECO 7A

Fixed Sell

Oct 2022 to Dec 2022

14,250 GJ/d

$2.84/GJ

AECO 5A

Fixed Sell

Oct 2022 to Dec 2022

1,000 mmbtu/d

US$2.94/mmbtu

NYMEX

3-way option (2)

Oct 2022 to Dec 2022

2,500 mmbtu/d

US$2.25/US$2.75/US$3.06

NYMEX

3-way option (2)

Oct 2022 to Dec 2022

1,500 mmbtu/d

US$2.60/US$2.91/US$3.56

NYMEX

3-way option (2)

Oct 2022 to Dec 2022

2,500 mmbtu/d

US$2.60/US$3.00/US$3.83

NYMEX

3-way option (2)

Oct 2022 to Dec 2022

2,500 mmbtu/d

US$2.65/US$2.90/US$3.40

NYMEX

3-way option (2)

Oct 2022 to Dec 2022

2,500 mmbtu/d

US$3.00/US$3.75/US$4.40

NYMEX

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

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

Baytex Energy Corp.

Q3 2022 MD&A 12

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30
	2022						2021
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	55,803		27,391		83,194		48,124		31,748		79,872
Operating netback:
Total sales, net of blending and other expense (1)	$	84.30	$	94.59	$	87.68	$	61.69	$	67.11	$	63.85
Less:
Royalties (2)	(14.78)		(28.21)		(19.21)		(7.38)		(19.80)		(12.32)
Operating expense (2)	(16.19)		(10.71)		(14.39)		(14.30)		(7.15)		(11.46)
Transportation expense (2)	(2.49)		—		(1.67)		(1.77)		—		(1.06)
Operating netback (1)	$	50.84	$	55.67	$	52.41	$	38.24	$	40.16	$	39.01
Realized financial derivatives loss (3)	—		—		(9.98)		—		—		(7.34)
Operating netback after financial derivatives (1)	$	50.84	$	55.67	$	42.43	$	38.24	$	40.16	$	31.67

	Nine Months Ended September 30
	2022						2021
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	54,711		27,681		82,392		49,108		30,834		79,942
Operating netback:
Total sales, net of blending and other expense (1)	$	91.68	$	96.79	$	93.40	$	54.41	$	62.92	$	57.69
Less:
Royalties (2)	(15.04)		(28.66)		(19.62)		(6.23)		(18.47)		(10.95)
Operating expense (2)	(16.35)		(9.82)		(14.15)		(13.91)		(7.27)		(11.35)
Transportation expense (2)	(2.26)		—		(1.50)		(1.80)		—		(1.10)
Operating netback (1)	$	58.03	$	58.31	$	58.13	$	32.47	$	37.18	$	34.29
Realized financial derivatives loss (3)	—		—		(12.66)		—		—		(5.21)
Operating netback after financial derivatives (1)	$	58.03	$	58.31	$	45.47	$	32.47	$	37.18	$	29.08

(2)Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description of the composition these measures.

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

Our operating netback of $52.41/boe for Q3/2022 and $58.13/boe for YTD 2022 was higher than $39.01/boe for Q3/2021 and $34.29/boe for YTD 2021 due to the increase in benchmark pricing in Canada and the U.S. which resulted in higher per unit sales net of royalties. Total operating and transportation expense of $16.06/boe for Q3/2022 and $15.65/boe for YTD 2022 were higher than $12.52/boe for Q3/2021 and $12.45/boe for YTD 2021 due to inflation which resulted in higher fuel, electricity and hauling costs along with increased workover and maintenance activity in YTD 2022. Including realized losses on financial derivatives our operating netback was $42.43/boe for Q3/2022 and $45.47/boe for YTD 2022 compared to $31.67/boe for Q3/2021 and $29.08/boe for YTD 2021.

GENERAL AND ADMINISTRATIVE EXPENSE

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

Baytex Energy Corp.

Q3 2022 MD&A 13

The following table summarizes our G&A expense for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2022		2021		Change		2022		2021		Change
Gross general and administrative expense	$	13,782	$	11,251	$	2,531	$	39,511	$	31,871	$	7,640
Overhead recoveries	(1,779)		(1,271)		(508)		(4,186)		(2,548)		(1,638)
General and administrative expense	$	12,003	$	9,980	$	2,023	$	35,325	$	29,323	$	6,002
General and administrative expense per boe (1)	$	1.57	$	1.36	$	0.21	$	1.57	$	1.34	$	0.23

(1)General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period.

G&A expense was $12.0 million ($1.57/boe) for Q3/2022 and $35.3 million ($1.57/boe) for YTD 2022 compared to $10.0 million ($1.36/boe) for Q3/2021 and $29.3 million ($1.34/boe) for YTD 2021. G&A expense for Q3/2022 and YTD 2022 was higher relative to the same periods of 2021 due to higher staffing costs associated with increased exploration and development expenditures in Canada during 2022. G&A expense of $1.57/boe during YTD 2022 is consistent with our revised annual guidance of $1.57/boe for 2022.

FINANCING AND INTEREST EXPENSE

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

The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2022 and 2021.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2022		2021		Change		2022		2021		Change
Interest on credit facilities	$	5,788	$	3,256	$	2,532	$	12,897	$	9,842	$	3,055
Interest on long-term notes	13,935		19,481		(5,546)		47,635		60,734		(13,099)
Interest on lease obligations	51		56		(5)		$	143	$	174	(31)
Cash interest	$	19,774	$	22,793	$	(3,019)	$	60,675	$	70,750	$	(10,075)
Accretion of debt issue costs	1,242		1,733		(491)		4,671		3,272		1,399
Accretion of asset retirement obligations	4,412		3,273		1,139		11,403		8,938		2,465

Early redemption expense	325		1,229		(904)		325		872		(547)
Financing and interest expense	$	25,753	$	29,028	$	(3,275)	$	77,074	$	83,832	$	(6,758)
Cash interest per boe (1)	$	2.58	$	3.10	$	(0.52)	$	2.70	$	3.24	$	(0.54)
Financing and interest expense per boe (1)	$	3.36	$	3.95	$	(0.59)	$	3.43	$	3.84	$	(0.41)

(1)Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period.

Financing and interest expense was $25.8 million ($3.36/boe) for Q3/2022 and $77.1 million ($3.43/boe) for YTD 2022 compared to $29.0 million ($3.95/boe) for Q3/2021 and $83.8 million ($3.84/boe) for YTD 2021. Lower debt levels have resulted in reduced financing and interest expense in both periods of 2022 relative to 2021.

Cash interest of $19.8 million ($2.58/boe) for Q3/2022 and $60.7 million ($2.70/boe) for YTD 2022 is lower than $22.8 million ($3.10/boe) for Q3/2021 and $70.8 million ($3.24/boe) for YTD 2021 as we had less debt outstanding during 2022. The interest on our U.S. dollar denominated long-term notes was lower as the average principal amount outstanding was lower during YTD 2022 due to the repurchase and redemption of US$200.0 million of long-term notes in 2021 and US$226.8 million of long-term notes in YTD 2022. Interest on our credit facilities in Q3/2022 and YTD 2022 was higher than the same periods of 2021 and is consistent with the increase in benchmark borrowing rates. The weighted average interest rate applicable to our credit facilities was 4.1% for Q3/2022 and 3.1% for YTD 2022 which is higher than 2.2% for both Q3/2021 and YTD 2021.

Financing and interest expense for YTD 2022 was lower than YTD 2021 which was primarily the result of the repurchase and redemption of the 2024 senior notes and also reflects a higher discount rate on our asset retirement obligations for YTD 2022.

Cash interest expense of $2.70/boe for YTD 2022 is above our revised annual guidance of $2.58/boe for 2022 as we expect a reduction in our net debt during the remainder of the year along with higher production.

Baytex Energy Corp.

Q3 2022 MD&A 14

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $6.6 million for Q3/2022 and $17.3 million for YTD 2022 compared to $6.8 million for Q3/2021 and $10.7 million for YTD 2021.

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, 2022 and 2021.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for per boe)	2022		2021		Change		2022		2021		Change
Depletion	$	142,651	$	125,681	$	16,970	$	422,906	$	328,171	$	94,735
Depreciation	1,526		1,371		155		4,348		3,948		400
Depletion and depreciation	$	144,177	$	127,052	$	17,125	$	427,254	$	332,119	$	95,135
Depletion and depreciation per boe (1)	$	18.84	$	17.29	$	1.55	$	18.99	$	15.22	$	3.77

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

Depletion and depreciation expense was $144.2 million ($18.84/boe) for Q3/2022 and $427.3 million ($18.99/boe) for YTD 2022 compared to $127.1 million ($17.29/boe) for Q3/2021 and $332.1 million ($15.22/boe) for YTD 2021. Total depletion and depreciation expense as well as the depletion rate per boe were higher in both periods of 2022 relative to 2021 as a result of $1.5 billion of impairment reversals recorded during 2021 which increased the depletable base of our U.S. and Canadian assets.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGU") at September 30, 2022.

2021 Impairment Reversals

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

SHARE-BASED COMPENSATION EXPENSE

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

We recorded SBC expense of $3.1 million for Q3/2022 and $10.0 million for YTD 2022 which is slightly higher than $2.5 million for Q3/2021 and $8.3 million for YTD 2021. The total expense for YTD 2022 is comprised of non-cash compensation expense of $2.7 million (YTD 2021 - $4.6 million) related to the Share Award Incentive Plan and cash compensation expense of $7.3 million (YTD 2021 - $3.7 million) related to the Incentive Award Plan and the Deferred Share Unit Plan.

Baytex Energy Corp.

Q3 2022 MD&A 15

FOREIGN EXCHANGE

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


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands except for exchange rates)	2022		2021		Change		2022		2021		Change
Unrealized foreign exchange loss	$	39,799	$	7,545	$	32,254	$	52,750	$	3,223	$	49,527
Realized foreign exchange gain	(894)		(79)		(815)		(481)		(818)		337
Foreign exchange loss	$	38,905	$	7,466	$	31,439	$	52,269	$	2,405	$	49,864
CAD/USD exchange rates:
At beginning of period	1.2872		1.2405				1.2656		1.2755
At end of period	1.3700		1.2750				1.3700		1.2750

We recorded a foreign exchange loss of $38.9 million for Q3/2022 and $52.3 million for YTD 2022 compared to a loss of $7.5 million for Q3/2021 and $2.4 million for YTD 2021.

The unrealized foreign exchange loss of $39.8 million for Q3/2022 and $52.8 million for YTD 2022 is primarily related to changes in the reported amount of our long-term notes and credit facilities due to a weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2022 compared to June 30, 2022 and December 31, 2021. The unrealized foreign exchange loss for Q3/2021 and YTD 2021 relates to changes in the reported amount of our long-term notes and intercompany notes outstanding at September 30, 2021 compared to June 30, 2021 and December 31, 2020.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange gain of $0.9 million for Q3/2022 and $0.5 million for YTD 2022 compared to a gain of $0.1 million for Q3/2021 and $0.8 million for YTD 2021.

INCOME TAXES


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2022		2021		Change		2022		2021		Change
Current income tax expense	$	703	$	486	$	217	$	2,753	$	894	$	1,859
Deferred income tax expense (recovery)	18,475		10,248		8,227		(8,937)		71,963		(80,900)
Total income tax expense (recovery)	$	19,178	$	10,734	$	8,444	$	(6,184)	$	72,857	$	(79,041)

Current income tax expense was $0.7 million for Q3/2022 and $2.8 million for YTD 2022 compared to $0.5 million for Q3/2021 and $0.9 million for YTD 2021.

We recorded deferred tax expense of $18.5 million for Q3/2022 and a recovery of $8.9 million for YTD 2022 compared to expense of $10.2 million for Q3/2021 and $72.0 million for YTD 2021. The deferred tax recovery recorded in YTD 2022 is primarily related to the effect of an internal debt restructuring offset by the income generated in our U.S. operations for the period. The deferred tax expense in YTD 2021 is primarily related to the impairment reversal recorded in our U.S. operating segment during YTD 2021.

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

Baytex Energy Corp.

Q3 2022 MD&A 16

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three and nine months ended September 30, 2022 and 2021 are set forth in the following table.


	Three Months Ended September 30						Nine Months Ended September 30
($ thousands)	2022		2021		Change		2022		2021		Change
Petroleum and natural gas sales	$	712,065	$	488,736	$	223,329	$	2,240,059	$	1,315,792	$	924,267
Royalties	(146,994)		(90,523)		(56,471)		(441,273)		(239,004)		(202,269)
Revenue, net of royalties	565,071		398,213		166,858		1,798,786		1,076,788		721,998

Expenses
Operating	(110,139)		(84,196)		(25,943)		(318,331)		(247,645)		(70,686)
Transportation	(12,771)		(7,818)		(4,953)		(33,744)		(24,092)		(9,652)
Blending and other	(40,945)		(19,581)		(21,364)		(139,280)		(56,668)		(82,612)
Operating netback (1)	$	401,216	$	286,618	$	114,598	$	1,307,431	$	748,383	$	559,048
General and administrative	(12,003)		(9,980)		(2,023)		(35,325)		(29,323)		(6,002)
Cash interest	(19,774)		(22,793)		3,019		(60,675)		(70,750)		10,075
Realized financial derivatives loss	(76,408)		(53,905)		(22,503)		(284,816)		(113,697)		(171,119)
Realized foreign exchange gain	894		79		815		481		818		(337)
Other expense	(6,499)		(78)		(6,421)		(7,500)		(16)		(7,484)
Current income tax expense	(703)		(486)		(217)		(2,753)		(894)		(1,859)
Share-based compensation - cash	(2,435)		(1,058)		(1,377)		(7,244)		(3,659)		(3,585)

Adjusted funds flow (2)	$	284,288	$	198,397	$	85,891	$	909,599	$	530,862	$	378,737

Exploration and evaluation	(6,566)		(6,766)		200		(17,346)		(10,718)		(6,628)
Depletion and depreciation	(144,177)		(127,052)		(17,125)		(427,254)		(332,119)		(95,135)
Share-based compensation - non-cash	(637)		(1,453)		816		(2,715)		(4,603)		1,888
Non-cash financing and accretion	(5,979)		(6,235)		256		(16,399)		(13,082)		(3,317)
Non-cash other income	1,276		444		832		2,741		2,108		633
Unrealized financial derivatives gain (loss)	190,471		(8,941)		199,412		92,978		(179,408)		272,386
Unrealized foreign exchange loss	(39,799)		(7,545)		(32,254)		(52,750)		(3,223)		(49,527)
Gain on dispositions	4,566		2,112		2,454		5,007		6,092		(1,085)
Impairment reversal	—		—		—		—		1,126,415		(1,126,415)
Deferred income tax (expense) recovery	(18,475)		(10,248)		(8,227)		8,937		(71,963)		80,900

Net income for the period	$	264,968	$	32,713	$	232,255	$	502,798	$	1,050,361	$	(547,563)

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

We generated adjusted funds flow of $284.3 million for Q3/2022 and $909.6 million for YTD 2022 compared to $198.4 million for Q3/2021 and $530.9 million for YTD 2021. The increase in adjusted funds flow for both periods of 2022 was primarily due to higher operating netback which increased $114.6 million from Q3/2021 and $559.0 million from YTD 2021 as a result of higher commodity prices that increased revenue, net of royalties. The increase in operating netback was partially offset by realized losses on financial derivatives of $76.4 million for Q3/2022 and $284.8 million for YTD 2022 which increased $22.5 million and $171.1 million relative to Q3/2021 and YTD 2021 when we recorded realized losses on financial derivatives of $53.9 million and $113.7 million respectively.

We reported net income of $265.0 million for Q3/2022 and $502.8 million for YTD 2022 compared to net income of $32.7 million reported for Q3/2021 and $1.1 billion for YTD 2021. Higher net income reported for YTD 2021 is primarily the result of a $1.1 billion impairment reversal that was recorded in Q2/2021.

Baytex Energy Corp.

Q3 2022 MD&A 17

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation gain of $117.0 million for Q3/2022 and $147.9 million for YTD 2022 relates to the change in value of our U.S. net assets and is due to the weakening of the Canadian dollar relative to the U.S. dollar at September 30, 2022 compared to June 30, 2022 and December 31, 2021. The CAD/USD exchange rate was 1.3700 CAD/USD as at September 30, 2022 compared to 1.2872 CAD/USD at June 30, 2022 and 1.2656 CAD/USD at December 31, 2021.

CAPITAL EXPENDITURES

Capital expenditures for the three and nine months ended September 30, 2022 and 2021 are summarized as follows.


	Three Months Ended September 30
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	103,523	$	49,150	$	152,673	$	67,177	$	18,460	$	85,637
Facilities	8,130		969		9,099		5,364		11		5,375
Land, seismic and other	5,497		184		5,681		2,958		265		3,223
Exploration and development expenditures	$	117,150	$	50,303	$	167,453	$	75,499	$	18,736	$	94,235
Property acquisitions	$	—	$	—	$	—	$	89	$	—	$	89
Proceeds from dispositions	$	(25,460)	$	—	$	(25,460)	$	(108)	$	(593)	$	(701)

	Nine Months Ended September 30
	2022						2021
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	247,785	$	119,454	$	367,239	$	129,230	$	90,092	$	219,322
Facilities	22,807		2,769		25,576		12,562		25		12,587
Land, seismic and other	24,569		524		25,093		6,597		802		7,399
Exploration and development expenditures	$	295,161	$	122,747	$	417,908	$	148,389	$	90,919	$	239,308
Property acquisitions	$	267	$	—	$	267	$	114	$	—	$	114
Proceeds from dispositions	$	(25,501)	$	—	$	(25,501)	$	(354)	$	(593)	$	(947)

Exploration and development expenditures were $167.5 million for Q3/2022 and $417.9 million for YTD 2022 compared to $94.2 million for Q3/2021 and $239.3 million for YTD 2021. Exploration and development expenditures in Q3/2022 were higher compared to Q3/2021 as development increased with stronger commodity prices in 2022 along with inflationary pressures that have resulted in higher costs relative to 2021.

In Canada, exploration and development expenditures were $117.2 million in Q3/2022 and $295.2 million in YTD 2022 compared to $75.5 million in Q3/2021 and $148.4 million in YTD 2021. Drilling and completion spending of $103.5 million in Q3/2022 and $247.8 million in YTD 2022 reflects higher light and heavy oil development activity relative to Q3/2021 and YTD 2021 when we spent $67.2 million and $129.2 million respectively. We also invested $8.1 million on facilities and $5.5 million on land, seismic and other expenditures during Q3/2022 and we completed a minor non-core property disposition in our conventional business unit in West Central Alberta for proceeds of $25.5 million.

Total U.S. exploration and development expenditures were $50.3 million for Q3/2022 and $122.7 million for YTD 2022 compared to $18.7 million in Q3/2021 and $90.9 million during YTD 2021. Exploration and development expenditures for Q3/2022 included costs associated with drilling 14 (3.7 net) wells along with 19 (4.1 net) wells that we brought on production compared to drilling 11 (2.0 net) wells along with 17 (3.4 net) wells brought on production during Q3/2021. The timing and pace of development activity combined with inflationary pressures and weaker Canadian dollar resulted in exploration and development expenditures of $50.3 million for Q3/2022 and $122.7 million for YTD 2022 compared to $18.7 million and $90.9 million for the same periods of 2021.

Our exploration and development expenditures for YTD 2022 are consistent with expectations and we now expect full year expenditures of $515 million for 2022.

Baytex Energy Corp.

Q3 2022 MD&A 18

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management is to maintain a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At September 30, 2022, our capital structure was comprised of shareholders' capital, long-term notes, trade and other receivables, trade and other payables, cash and the credit facilities.

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

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

Management of debt levels is a priority for us in order to sustain operations and support our long-term plans. At September 30, 2022, net debt(1) of $1.11 billion was $296.2 million lower than $1.41 billion at December 31, 2021. The decrease in net debt for 2022 is primarily a result of the free cash flow(2) of $478.2 million generated during 2022 being allocated towards debt repayment which was partially offset by $141.3 million in common share repurchases completed in conjunction with our shareholder returns initiative.

In May 2022, we began repurchasing our common shares under a previously announced normal course issuer bid ("NCIB") as part of our shareholder return framework. During YTD 2022 we have spent $141.3 million to repurchase and cancel 21.6 million common shares, representing 3.8% of the total shares outstanding at the commencement of the NCIB.

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a trailing twelve month basis. At September 30, 2022, our net debt to adjusted funds flow ratio(1) was 1.0 compared to a ratio of 1.9 as at December 31, 2021. The decrease in the net debt to adjusted funds flow ratio relative to December 31, 2021 is attributed to higher adjusted funds flow for the trailing twelve months ended September 30, 2022 and lower net debt at September 30, 2022.

Credit Facilities

At September 30, 2022, the principal amount of borrowings outstanding under our credit facilities was $450.1 million. On April 1, 2022, we amended the credit facilities to expand our revolving facilities to US$850 million and extend maturity to April 1, 2026. The term loan facility was eliminated as part of this amendment.

The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. There are no mandatory principal payments required prior to maturity which could be extended upon our request. The credit facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances under the credit facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the credit facilities was 4.1% for Q3/2022 and 3.1% for YTD 2022 compared to 2.2% for both Q3/2021 and YTD 2021. The interest rate on our credit facilities has increased with higher government benchmark rates in 2022 relative to 2021.

On July 25, 2022 we entered into a $20 million uncommitted unsecured demand revolving letter of credit facility (the "LC Facility"). Letters of credit under this facility are guaranteed by Export Development Canada and do not use available capacity under the credit facilities. As at September 30, 2022, we had $15.8 million of outstanding letters of credit under the LC Facility.

The agreements and associated amending agreements relating to the credit facilities are accessible on the SEDAR website at www.sedar.com.

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

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and our compliance therewith at September 30, 2022.


Covenant Description	Position as at September 30, 2022	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.4:1:0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	14.8:1.0	2.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreements and is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at September 30, 2022, the Company's Senior Secured Debt totaled $450.1 million of principal amounts outstanding.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2022 was $1.2 billion.

(3)"Interest coverage" is calculated in accordance with the credit agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the twelve months ended September 30, 2022 were $81.8 million.

Long-Term Notes

We have one series of long-term notes outstanding that totals $648.2 million as at September 30, 2022. The long-term notes do not contain any financial maintenance covenants.

On June 6, 2014, we issued US$800 million of senior unsecured notes, comprised of US$400 million of 5.125% notes due June 1, 2021 (the "5.125% Notes"), and US$400 million of 5.625% notes due June 1, 2024 (the "5.625% Notes"). We redeemed the 5.125% Notes on February 20, 2020. During 2021, we redeemed and cancelled US$200 million of the 5.625% Notes and on June 1, 2022, we redeemed and cancelled the remaining US$200 million of the 5.625% Notes at par.

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. During the Q3/2022, Baytex repurchased and cancelled an aggregate principal amount of US$26.8 million of the 8.75% Notes.

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, 2022, we issued 5.0 million common shares pursuant to our share-based compensation program and cancelled 21.6 million common shares repurchased under a NCIB. As at September 30, 2022, we had 547.6 million common shares issued and outstanding and no preferred shares issued and outstanding.

Contractual Obligations

We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of September 30, 2022 and the expected timing for funding these obligations are noted in the table below.


($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Trade and other payables	$	271,400	$	268,410	$	2,990	$	—	$	—
Financial derivatives	48,587		48,587		—		—		—
Credit facilities - principal (1)(2)	450,051		—		—		450,051		—
Long-term notes - principal (2)	648,207		—		—		648,207		—
Interest on long-term notes (3)	255,464		56,718		113,436		85,310		—
Lease obligations (2)	7,449		3,873		3,295		281		—
Processing agreements	6,971		1,193		1,216		838		3,724
Transportation agreements	54,840		10,813		26,610		14,673		2,744
Total	$	1,742,969	$	389,594	$	147,547	$	1,199,360	$	6,468

(1)On April 1, 2022 we extended the maturity of our credit facilities to April 1, 2026.

(2)Principal amount of instruments.

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

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

Baytex Energy Corp.

Q3 2022 MD&A 19

QUARTERLY FINANCIAL INFORMATION


	2022			2021				2020
($ thousands, except per common share amounts)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Petroleum and natural gas sales	712,065	854,169	673,825	552,403	488,736	442,354	384,702	233,636
Net income (loss)	264,968	180,972	56,858	563,239	32,713	1,052,999	(35,352)	221,160
Per common share - basic	0.48	0.32	0.10	1.00	0.06	1.87	(0.06)	0.39
Per common share - diluted	0.47	0.32	0.10	0.98	0.06	1.85	(0.06)	0.39
Adjusted funds flow (1)	284,288	345,704	279,607	214,766	198,397	175,883	156,582	82,176
Per common share - basic	0.51	0.61	0.49	0.38	0.35	0.31	0.28	0.15
Per common share - diluted	0.51	0.60	0.49	0.37	0.35	0.31	0.28	0.15
Free cash flow (2)	111,568	245,316	121,318	137,133	101,215	112,486	70,495	1,794
Per common share - basic	0.20	0.43	0.21	0.24	0.18	0.20	0.13	—
Per common share - diluted	0.20	0.43	0.21	0.24	0.18	0.20	0.13	—
Cash flows from operating activities	310,423	360,034	198,974	240,567	178,961	171,876	120,980	51,017
Per common share - basic	0.56	0.63	0.35	0.43	0.32	0.30	0.22	0.09
Per common share - diluted	0.56	0.63	0.35	0.42	0.31	0.30	0.22	0.09
Exploration and development	167,453	96,633	153,822	73,995	94,235	61,485	83,588	77,809
Canada	117,150	51,881	126,130	59,821	75,499	30,387	42,503	45,030
U.S.	50,303	44,752	27,692	14,174	18,736	31,098	41,085	32,779
Property acquisitions	—	208	59	1,443	89	—	25	—
Proceeds from dispositions	(25,460)	(14)	(27)	(6,857)	(701)	(18)	(228)	(33)
Net debt (1)	1,113,559	1,123,297	1,275,680	1,409,717	1,564,658	1,629,629	1,758,894	1,847,601
Total assets (3)	4,923,617	4,870,432	4,917,811	4,834,643	4,453,971	4,438,162	3,338,408	3,408,096
Common shares outstanding	547,615	560,139	569,214	564,213	564,213	564,182	564,111	561,227

Daily production
Total production (boe/d)	83,194	83,090	80,867	80,789	79,872	81,162	78,780	70,475
Canada (boe/d)	55,803	54,919	53,385	50,362	48,124	47,205	52,039	45,321
U.S. (boe/d)	27,391	28,170	27,482	30,428	31,748	33,957	26,741	25,154

Benchmark prices
WTI oil (US$/bbl)	91.56	108.41	94.29	77.19	70.56	66.07	57.84	42.66
WCS heavy oil ($/bbl)	93.62	122.05	100.99	78.82	71.81	67.03	57.46	43.46
Edmonton par oil ($/bbl)	116.79	137.79	115.66	93.29	83.78	77.28	66.58	50.24
CAD/USD avg exchange rate	1.3059	1.2766	1.2661	1.2600	1.2601	1.2279	1.2663	1.3031
AECO natural gas ($/mcf)	5.81	6.27	4.59	4.94	3.54	2.85	2.93	2.77
NYMEX natural gas (US$/mmbtu)	8.20	7.17	4.95	5.83	4.01	2.83	2.69	2.66

Total sales, net of blending and other expense ($/boe) (2)	87.68	105.44	86.89	70.42	63.85	57.19	51.84	34.35
Royalties ($/boe) (3)	(19.21)	(22.69)	(16.86)	(13.47)	(12.32)	(11.04)	(9.44)	(5.83)
Operating expense ($/boe) (3)	(14.39)	(14.21)	(13.85)	(12.83)	(11.46)	(11.22)	(11.36)	(12.30)
Transportation expense ($/boe) (3)	(1.67)	(1.56)	(1.27)	(1.10)	(1.06)	(1.01)	(1.24)	(1.03)
Operating netback ($/boe) (2)	52.41	66.98	54.91	43.02	39.01	33.92	29.80	15.19
Financial derivatives (loss) gain ($/boe) (3)	(9.98)	(16.41)	(11.59)	(9.49)	(7.34)	(5.28)	(2.93)	2.64
Operating netback after financial derivatives ($/boe) (2)	42.43	50.57	43.32	33.53	31.67	28.64	26.87	17.83

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

(3)Previously disclosed amounts have been revised to conform with current period presentation.

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

Baytex Energy Corp.

Q3 2022 MD&A 20

Our results for the previous eight quarters reflect the disciplined execution of our capital programs and management of production in response to fluctuations in the prices for the commodities we produce. Production of 70,475 boe/d in Q4/2020 reflects our efforts to manage capital and production levels in response to volatile commodity prices caused by the COVID-19 pandemic. Development activity increased as commodity prices began to climb in Q1/2021 and we have continued the pace of activity as commodity prices improved throughout 2021 and 2022. Strong well performance and our successful development programs have resulted in production of 83,194 boe/d for Q3/2022.

Prices began to strengthen in 2021 as measures to control the spread of COVID-19 were relaxed. Commodity prices continued to improve to multi-year highs in 2022 following Russia's invasion of Ukraine which created elevated uncertainty surrounding the global supply of oil. The impact of increased commodity prices is reflected in our realized sales price of $105.44/boe for Q2/2022 which is our strongest realized pricing in eight quarters. Our realized price of $87.68/boe for Q3/2022 reflects recent declines in crude oil prices caused by concern over future demand and economic slowdowns.

Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow(1) of $284.3 million for Q3/2022 reflects strong price realizations and production results from our development plans in the U.S. and Canada.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt(1) has decreased from $1.8 billion at Q4/2020 to $1.1 billion at Q3/2022 as free cash flow(2) of $901.3 million generated over the last eight quarters has been primarily directed towards debt repayment. The decrease in net debt due to free cash flow was partially offset by our shareholder return initiative which was implemented during Q2/2022 and resulted in the repurchase and cancellation of 21.6 million common shares for total consideration of $141.3 million as of Q3/2022.

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

Baytex Energy Corp.

Q3 2022 MD&A 21

ENVIRONMENTAL REGULATIONS

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

Reporting Regulations

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

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at September 30, 2022, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the nine months ended September 30, 2022. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2021.

SPECIFIED FINANCIAL MEASURES

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

Non-GAAP Financial Measures

Total sales, net of blending and other expense

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

Operating netback

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

Baytex Energy Corp.

Q3 2022 MD&A 22

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2022		2021		2022		2021
Petroleum and natural gas sales	$	712,065	$	488,736	$	2,240,059	$	1,315,792
Blending and other expense	(40,945)		(19,581)		(139,280)		(56,668)
Total sales, net of blending and other expense	671,120		469,155		2,100,779		1,259,124
Royalties	(146,994)		(90,523)		(441,273)		(239,004)
Operating expense	(110,139)		(84,196)		(318,331)		(247,645)
Transportation expense	(12,771)		(7,818)		(33,744)		(24,092)
Operating netback	401,216		286,618		1,307,431		748,383
Realized financial derivatives loss (1)	(76,408)		(53,905)		(284,816)		(113,697)
Operating netback after realized financial derivatives	$	324,808	$	232,713	$	1,022,615	$	634,686

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 16 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2022 for further information.

Free cash flow

We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties and payments on lease obligations.

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2022		2021		2022		2021
Cash flows from operating activities	$	310,423	$	178,961	$	869,431	$	471,817
Change in non-cash working capital	(30,734)		17,631		29,560		$	54,830
Additions to exploration and evaluation assets	—		(89)		(5,897)		(733)
Additions to oil and gas properties	(167,453)		(94,146)		(412,011)		(238,575)
Payments on lease obligations	(668)		(1,142)		(2,881)		(3,143)
Free cash flow	$	111,568	$	101,215	$	478,202	$	284,196

Non-GAAP Financial Ratios

Heavy oil, net of blending and other expense per bbl

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

Total sales, net of blending and other expense per boe

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

Average royalty rate

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

Baytex Energy Corp.

Q3 2022 MD&A 23

Operating netback per boe

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

Capital Management Measures

Net debt

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

The following table summarizes our calculation of net debt.


($ thousands)	September 30, 2022		December 31, 2021
Credit facilities	$	447,475	$	505,171
Unamortized debt issuance costs - Credit facilities (1)	2,576		1,343
Long-term notes	639,679		874,527
Unamortized debt issuance costs - Long-term notes (1)	8,528		11,393
Trade and other payables	271,400		190,692
Cash	(4,410)		—
Trade and other receivables	(251,689)		(173,409)
Net debt	$	1,113,559	$	1,409,717
Net debt to adjusted funds flow	1.0		1.9

(1)Unamortized debt issuance costs were obtained from Note 6 - Credit Facilities and Note 7 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2022. These amounts represent the remaining balance of costs that were paid by Baytex at the inception of the contract.

Adjusted funds flow

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

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


	Three Months Ended September 30				Nine Months Ended September 30
($ thousands)	2022		2021		2022		2021
Cash flow from operating activities	$	310,423	$	178,961	$	869,431	$	471,817
Change in non-cash working capital	(30,734)		17,631		29,560		54,830
Asset retirement obligations settled	4,599		1,805		10,608		4,215

Adjusted funds flow	$	284,288	$	198,397	$	909,599	$	530,862

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, 2022.

Baytex Energy Corp.

Q3 2022 MD&A 24

FORWARD-LOOKING STATEMENTS

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

Specifically, this document contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; our 2022 guidance with respect to exploration and development expenditures, average daily production, royalty rate and operating, transportation, general and administrative and interest expenses; the existence, operation and strategy of our risk management program; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; and the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; we may issue debt or equity securities, sell assets or adjust capital spending.

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

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

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

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