Baytex Energy Corp.                                            

Q1 2023 MD&A    1

Exhibit 99.2

BAYTEX ENERGY CORP. 

Management’s Discussion and Analysis

For the three months ended March 31, 2023 and 2022

Dated May 4, 2023

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three months ended March 31, 2023. This information is provided as of May 4, 2023. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months ended March 31, 2023 ("Q1/2023") have been compared with the results for the three months ended March 31, 2022 ("Q1/2022"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three months ended March 31, 2023, its audited comparative consolidated financial statements for the years ended December 31, 2022 and 2021, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2022. 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", "total debt", "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.

PROPOSED BUSINESS COMBINATION

On February 28, 2023, Baytex announced that it has entered into a definitive agreement (the “Agreement”) to acquire Ranger Oil Corporation (“Ranger”), an oil and gas exploration and production company with operations in the Eagle Ford (the "Merger Transaction"). The Merger Transaction has been unanimously approved by the Boards of Directors of Baytex and Ranger and is expected to close in the second quarter of 2023, subject to approval by the shareholders of both companies and the satisfaction of other customary closing conditions. The Merger Transaction materially increases our Eagle Ford scale and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford while enhancing per share metrics.

The Merger Transaction creates a more resilient and sustainable business with higher revenues, improved margins and enhanced inventory which will allow for a more robust shareholder return framework. Upon closing, we intend to increase direct returns to shareholders to 50% of free cash flow generated by the combined company, including the expected introduction of a quarterly $0.0225 per share dividend. To meet our shareholder return commitment, we intend to include 25% of the free cash flow generated from January 1, 2023 until closing in our 2023 share buyback program.

The Agreement provides that, upon the occurrence of certain termination events, either of the parties may be required to pay the other party their respective termination fees, being the Ranger termination fee of US$60 million and the Baytex termination fee of US$100 million.

The Merger Transaction will be funded with a combination of cash and shares. Baytex will issue 7.49 common shares for each Ranger share and pay US$13.31 per Ranger share along with assuming Ranger’s net debt. The cash portion of the transaction will be funded with Baytex’s expanded credit facility which will increase to US$1.1 billion upon the closing of the transaction, up to US$250 million from a two-year term loan facility and the proceeds from the issuance of US$800 million senior unsecured notes

Baytex Energy Corp.                                            

Q1 2023 MD&A    2

due 2030. Baytex closed the US$800 million principal amount senior unsecured note offering on April 27, 2023 with the proceeds deposited into escrow subject to completion of the Merger Transaction.

During the three months ended March 31, 2023, Baytex incurred $8.9 million of transaction costs, including consulting, financial advisory, legal and filing fees related to the Merger. The results of operations and the MD&A do not include the results of Ranger. The Company will include the results of Ranger after closing the Merger Transaction and will update guidance at that time.

FIRST QUARTER HIGHLIGHTS

In addition to entering into the Merger Transaction with Ranger, Baytex delivered strong operating and financial results in Q1/2023. Production of 86,760 boe/d increased 7% from Q1/2022 and reflects growth from our Canadian heavy oil assets along with strong well results from our successful development programs in the U.S. and Canada. We invested $233.6 million on exploration and development expenditures and generated adjusted funds flow(1) of $237.0 million during Q1/2023.

Our capital program for the first half of 2023 is weighted towards Q1/2023 as we complete the majority of our first half drilling in Q1 prior to seasonal conditions which limit our ability to operate in Canada. Our exploration and development expenditures totaled $233.6 million in Q1/2023 and were consistent with our expectations as part of our $575-$650 million annual capital program. We invested $184.6 million in Canada in Q1/2023 and brought 25 (24.8 net) heavy oil wells and 64 (59.6 net) light oil wells on production. Production in Canada averaged 60,651 boe/d during Q1/2023 compared to 53,385 boe/d in Q1/2022 due to the continued strength of our Clearwater assets at Peavine and the overall growth of our heavy oil portfolio. In the U.S. we invested $49.0 million during Q1/2023 and brought 24 (6.4 net) wells on production. Production in the U.S. averaged 26,109 boe/d in Q1/2023 compared to 27,482 boe/d in Q1/2022. Production in the U.S. declined slightly with overall activity decreasing on our non-operated acreage.

Oil prices decreased in Q1/2023 on concerns of an economic slowdown causing lower demand for crude oil as central banks continued to increase interest rates to combat inflation. The WTI and WCS differential benchmarks averaged US$76.13/bbl and US $24.77/bbl during Q1/2023 compared to US$94.29/bbl and US$14.53/bbl respectively in Q1/2022. Adjusted funds flow(1) of $237.0 million and cash flows from operating activities of $184.9 million for Q1/2023 reflect commodity prices that were lower relative to Q1/2022 when we generated adjusted funds flow of $279.6 million and cash flows from operating activities of $199.0 million.

With our active Q1/2023 capital program and lower commodity prices, net debt(1) of $995.2 million at March 31, 2023 was consistent with $987.4 million at December 31, 2022. On closing of the Merger Transaction, we intend to allocate 50% of the free cash flowgenerated by the combined company to shareholder returns including an expected $0.0225 per share quarterly dividend. To meet our shareholder return commitment, we intend to contribute 25% of free cash flow generated from January 1, 2023 until closing of the merger to our 2023 share buyback program.

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

2023 GUIDANCE

The following table compares our 2023 annual guidance to our Q1/2023 results and does not include Ranger. We will provide updated 2023 guidance once we close the Merger Transaction. Our 2023 production guidance range is unchanged at 86,000 to 89,000 boe/d with budgeted exploration and development expenditures of $575-$650 million.

	2023 Annual Guidance (1)	Q1/2023 Results
Exploration and development expenditures	$575 - $650 million	$233.6 million
Production (boe/d)	86,000 - 89,000	86,760
Expenses:
Average royalty rate (2)	20.0% - 22.0%	18.8%
Operating (3)	$14.00 - $14.75/boe	$14.40/boe
Transportation (3)	$1.90 - $2.10/boe	$2.18/boe
General and administrative (3)	$52 million ($1.63/boe)	$11.7 million ($1.50/boe)
Cash Interest (3)	$65 million ($2.04/boe)	$18.4 million ($2.35/boe)
Leasing expenditures	$4 million	$1.2 million
Asset retirement obligations	$25 million	$4.1 million

(1)As announced on December 7, 2022.

(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.

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

Baytex Energy Corp.                                            

Q1 2023 MD&A    3

RESULTS OF OPERATIONS

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

Production

	Three Months Ended March 31
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Daily Production
Liquids (bbl/d)
Light oil and condensate	16,398		15,280		31,678		17,573		16,492		34,065
Heavy oil	34,191		—		34,191		25,236		—		25,236
Natural Gas Liquids (NGL)	1,875		5,338		7,213		1,935		5,701		7,636
Total liquids (bbl/d)	52,464		20,618		73,082		44,744		22,193		66,937
Natural gas (mcf/d)	49,120		32,946		82,066		51,843		31,731		83,574
Total production (boe/d)	60,651		26,109		86,760		53,385		27,482		80,867
Production Mix
Segment as a percent of total	70	%	30	%	100	%	66	%	34	%	100	%
Light oil and condensate	27	%	59	%	37	%	33	%	60	%	42	%
Heavy oil	56	%	—	%	39	%	47	%	—	%	31	%
NGL	3	%	20	%	8	%	4	%	21	%	9	%
Natural gas	14	%	21	%	16	%	16	%	19	%	18	%

Production was 86,760 boe/d for Q1/2023 compared to 80,867 boe/d for Q1/2022. Total production was higher in Q1/2023 compared to Q1/2022 due to our successful development program in Canada which includes strong well results from our Clearwater development program.

In Canada, production was 60,651 boe/d for Q1/2023 compared to 53,385 boe/d for Q1/2022. Our successful development program and strong well performance from our Clearwater assets at Peavine resulted in a 7,266 boe/d increase in production for Q1/2023 relative to Q1/2022. Production at Peavine averaged 11,760 boe/d in Q1/2023 compared to 3,154 boe/d in Q1/2022.

In the U.S., production was 26,109 boe/d for Q1/2023 compared to 27,482 boe/d for Q1/2022. Production in the U.S. was lower during Q1/2023 as a result of lower activity on our lands along with a greater proportion of wells were brought on production later in the quarter as compared to Q1/2022. We initiated production from 24 (6.4 net) wells during Q1/2023 compared to 17 (4.8 net) wells during Q1/2022.

Total production of 86,760 boe/d for Q1/2023 is consistent with expectations and is within our annual guidance of approximately 86,000 - 89,000 boe/d for 2023.

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 was lower during Q1/2023 as central banks continued to raise interest rates to combat inflation which resulted in expectations for slower economic activity and demand for crude oil. As a result, the WTI benchmark price averaged US$76.13/bbl for Q1/2023 compared to Q1/2022 when WTI was higher due to uncertainty around supply caused by geopolitical factors and averaged US$94.29/bbl.

Baytex Energy Corp.                                            

Q1 2023 MD&A    4

We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas which is a representative benchmark for light oil pricing at the U.S. Gulf coast. The MEH benchmark averaged US$77.42/bbl during Q1/2023 which is lower than US$96.72/bbl during Q1/2022. 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$1.29/bbl for Q1/2023 compared to a premium of US$2.43/bbl for Q1/2022. The MEH benchmark traded at a lower premium to WTI in Q1/2023 compared to Q1/2022 as a result of refinery turnarounds and power outages that disrupted processing capacity at the Gulf Coast in Q1/2023.

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 $99.04/bbl during Q1/2023 compared to $115.66/bbl during Q1/2022. Edmonton par traded at a discount to WTI of US$2.88/bbl for Q1/2023 which is consistent with a discount of US$2.94/bbl for Q1/2022.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS heavy oil price for Q1/2023 averaged $69.44/bbl compared to $100.99/bbl for the same period of 2022. The WCS heavy oil differential was US$24.77/bbl in Q1/2023 which is wider than US$14.53/bbl for Q1/2022 due to refinery turnarounds which reduced demand for Canadian heavy oil in 2023.

Natural Gas

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. Reduced global demand from milder winter temperatures as well as export terminal disruptions resulted in a decrease in the NYMEX natural gas benchmark that averaged US$3.42/mmbtu for Q1/2023 compared to US$4.95/mmbtu for Q1/2022.

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. The AECO benchmark averaged $4.34/mcf during Q1/2023 which is relatively consistent with $4.59/mcf for Q1/2022.

The following tables compare select benchmark prices and our average realized selling prices for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
	2023	2022	Change
Benchmark Averages
WTI oil (US$/bbl) (1)	76.13	94.29	(18.16)
MEH oil (US$/bbl) (2)	77.42	96.72	(19.30)
MEH oil differential to WTI (US$/bbl)	1.29	2.43	(1.14)
Edmonton par oil ($/bbl) (3)	99.04	115.66	(16.62)
Edmonton par oil differential to WTI (US$/bbl)	(2.88)	(2.94)	0.06
WCS heavy oil ($/bbl) (4)	69.44	100.99	(31.55)
WCS heavy oil differential to WTI (US$/bbl)	(24.77)	(14.53)	(10.24)
AECO natural gas ($/mcf) (5)	4.34	4.59	(0.25)
NYMEX natural gas (US$/mmbtu) (6)	3.42	4.95	(1.53)
CAD/USD average exchange rate	1.3520	1.2661	0.0859

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

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

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

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

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

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

Baytex Energy Corp.                                            

Q1 2023 MD&A    5

	Three Months Ended March 31
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	99.23	$	103.27	$	101.18	$	113.91	$	121.82	$	117.74
Heavy oil, net of blending and other expense ($/bbl) (2)	51.15		—		51.15		89.38		—		89.38
NGL ($/bbl) (1)	35.90		32.83		33.63		42.96		42.89		42.91
Natural gas ($/mcf) (1)	3.53		4.02		3.73		4.64		6.06		5.17
Total sales, net of blending and other expense ($/boe) (2)	$	59.71	$	72.22	$	63.48	$	85.81	$	89.00	$	86.89

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

(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.

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe(1) was $63.48/boe for Q1/2023 compared to $86.89/boe for Q1/2022. In Canada, our realized price of $59.71/boe for Q1/2023 was $26.10/boe lower than $85.81/boe for Q1/2022. Our realized price in the U.S. was $72.22/boe in Q1/2023 which is $16.78/boe lower than $89.00/boe in Q1/2022. The decrease in our realized price in Canada and the U.S. for Q1/2023 was a result of lower North American benchmark prices relative to the same period of 2022.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) was $99.23/bbl for Q1/2023 compared to $113.91/bbl for Q1/2022. Our realized light oil and condensate price for Q1/2023 decreased with the decline in the benchmark price and represents a premium to the Edmonton par price of $0.19/bbl for Q1/2023 compared to a discount of $1.75/bbl in Q1/2022. We realized a premium to the Edmonton par price due to strong price realizations on certain marketing arrangements within our Viking business unit for Q1/2023.

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 $103.27/bbl for Q1/2023 compared to $121.82/bbl for Q1/2022. Expressed in U.S. dollars, our realized light oil and condensate price of US$76.38/bbl for Q1/2023 represents a discount to MEH of US$1.04/bbl for Q1/2023, which is consistent with a discount of US$0.50/bbl for Q1/2022.

Our realized heavy oil price, net of blending and other expense(1) averaged $51.15/bbl in Q1/2023 compared to $89.38/bbl in Q1/2022. This was $38.23/bbl lower than Q1/2022, compared to a $31.55/bbl decrease in the WCS benchmark price over the same period. Our realized price decreased more than the benchmark price as the cost of condensate purchased for blending was higher relative to sales of the blended product based on the WCS benchmark in Q1/2023 compared to Q1/2022.

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 $33.63/bbl in Q1/2023 or 33% of WTI (expressed in Canadian dollars) compared to $42.91/bbl or 36% of WTI (expressed in Canadian dollars) in Q1/2022. The decrease in our realized price is primarily a result of lower WTI pricing in Q1/2023 relative to Q1/2022 as our realized price as a percentage of WTI was relatively consistent in both periods.

We compare our realized natural gas price in Canada to the AECO benchmark price and to the NYMEX benchmark in the U.S. A portion of our natural gas in Canada and the U.S. is based on the respective daily index pricing which fluctuates independently from the associated monthly index. In the U.S., our realized natural gas price(2) was US$2.97/mcf for Q1/2023 compared to US$4.79/mcf for Q1/2022 which is primarily the result of the decrease in the NYMEX benchmark over the same period. In Canada our realized natural gas price was $3.53/mcf for Q1/2023 compared to $4.64/mcf in Q1/2022 which declined more than the decline in the AECO benchmark over the same periods due to certain spot sales below the monthly index.

(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.                                            

Q1 2023 MD&A    6

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended March 31
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Oil sales
Light oil and condensate	$	146,456	$	142,011	$	288,467	$	180,156	$	180,820	$	360,976
Heavy oil	217,085		—		217,085		244,439		—		244,439
NGL	6,059		15,774		21,833		7,483		22,007		29,490
Total oil sales	369,600		157,785		527,385		432,078		202,827		634,905
Natural gas sales	16,022		11,929		27,951		21,626		17,294		38,920
Total petroleum and natural gas sales	385,622		169,714		555,336		453,704		220,121		673,825
Blending and other expense	(59,681)		—		(59,681)		(41,440)		—		(41,440)
Total sales, net of blending and other expense (1)	$	325,941	$	169,714	$	495,655	$	412,264	$	220,121	$	632,385

(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.

Total sales, net of blending and other expense, of $495.7 million for Q1/2023 decreased $136.7 million from $632.4 million reported for Q1/2022. The decrease in total sales is primarily the result of lower realized prices in Q1/2023 relative to Q1/2022.

In Canada, total sales, net of blending and other expense, of $325.9 million for Q1/2023 decreased $86.3 million from $412.3 million reported for Q1/2022. The decrease was primarily a result of lower realized pricing for Q1/2023 relative to Q1/2022 which resulted in a $142.4 million decrease in total sales, net of blending and other expense. The impact of lower pricing was partially offset by higher production, which contributed to a $56.1 million increase in total sales, net of blending and other expense, relative to Q1/2022.

In the U.S., total petroleum and natural gas sales of $169.7 million for Q1/2023 decreased $50.4 million from $220.1 million reported for Q1/2022. Total petroleum and natural gas sales decreased $39.4 million due to lower realized pricing and $11.0 million from lower production in Q1/2023 relative to Q1/2022.

ROYALTIES

Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction. The following table summarizes our royalties and royalty rates for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	43,855		$	49,398		$	93,253		$	57,676		$	65,044		$	122,720
Average royalty rate (1)(2)	13.5		%	29.1		%	18.8		%	14.0		%	29.5		%	19.4		%
Royalties per boe (3)	$	8.03		$	21.02		$	11.94		$	12.00		$	26.30		$	16.86

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

(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.

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

Royalties for Q1/2023 were $93.3 million or 18.8% of total sales, net of blending and other expense, compared to $122.7 million or 19.4% for Q1/2022. Royalties were lower for Q1/2023 due to lower total sales, net of blending and other expense, relative to Q1/2022. Our average royalty rate of 18.8% for Q1/2023 was lower than 19.4% for Q1/2022 due to our heavy oil production growth which caused a higher proportion of our production being generated in Canada. Our average royalty rate of 18.8% for Q1/2023 is near the low end of our annual guidance range of 20.0% - 22.0% for 2023 which reflects lower realized heavy oil pricing in Q1/2023.

Our average royalty rate in Canada of 13.5% for Q1/2023 was slightly lower than 14.0% for Q1/2022 as a result of lower benchmark commodity prices. In the U.S., royalties averaged 29.1% of total sales for Q1/2023, which is consistent with 29.5% for Q1/2022 as the royalty rate on our U.S. production does not vary with price but can vary across our acreage.

OPERATING EXPENSE

	Three Months Ended March 31
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	91,180	$	21,228	$	112,408	$	78,540	$	22,226	$	100,766
Operating expense per boe (1)	$	16.70	$	9.03	$	14.40	$	16.35	$	8.99	$	13.85

(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 $112.4 million ($14.40/boe) for Q1/2023 compared to $100.8 million ($13.85/boe) for Q1/2022. The increase in total operating expenses is primarily due to higher production in Q1/2023 relative to Q1/2022. Our per unit operating expense was slightly higher in Q1/2023 due to a greater proportion of our production being generated in Canada relative to Q1/2022. Per unit operating expense of $14.40/boe for Q1/2023 was consistent with our annual guidance range of $14.00 - $14.75/boe for 2023.

In Canada, total operating expense was $91.2 million ($16.70/boe) for Q1/2023 which was higher than $78.5 million ($16.35/boe) for Q1/2022 due to higher production as our per unit operating expense was relatively consistent in both periods. In the U.S., operating expense was $21.2 million ($9.03/boe or US$6.68/boe expressed in U.S. dollars) for Q1/2023 and was fairly consistent with $22.2 million ($8.99/boe or US$7.10/boe expressed in U.S. dollars) for Q1/2022.

TRANSPORTATION EXPENSE

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

The following table compares our transportation expense for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	17,005	$	—	$	17,005	$	9,215	$	—	$	9,215
Transportation expense per boe (1)	$	3.12	$	—	$	2.18	$	1.92	$	—	$	1.27

(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 $17.0 million ($2.18/boe) for Q1/2023 compared to $9.2 million ($1.27/boe) for Q1/2022. Total transportation expense and per unit costs were higher in Q1/2023 as a result of additional heavy oil production in Canada along with higher trucking rates relative to Q1/2022. Per unit transportation expense of $2.18/boe for Q1/2023 is consistent with expectations and is marginally higher than our annual guidance range of $1.90 - $2.10/boe for 2023.

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 $59.7 million for Q1/2023 compared to $41.4 million for Q1/2022. Higher blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in Q1/2023 relative to Q1/2022.

Baytex Energy Corp.                                            

Q1 2023 MD&A    7

FINANCIAL DERIVATIVES

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our 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 months ended March 31, 2023 and 2022.

	Three Months Ended March 31
($ thousands)	2023		2022		Change
Realized financial derivatives gain (loss)
Crude oil	$	5,415	$	(79,526)	$	84,941
Natural gas	—		(4,840)		4,840
Total	$	5,415	$	(84,366)	$	89,781
Unrealized financial derivatives gain (loss)
Crude oil	$	9,210	$	(139,318)	$	148,528
Natural gas	—		(16,634)		16,634
Equity total return swap ("Equity TRS")	—		(309)		309
Total	$	9,210	$	(156,261)	$	165,471
Total financial derivatives gain (loss)
Crude oil	$	14,625	$	(218,844)	$	233,469
Natural gas	—		(21,474)		21,474
Equity TRS	—		(309)		309
Total	$	14,625	$	(240,627)	$	255,252

We recorded a total financial derivative gain of $14.6 million for Q1/2023 compared to a loss of $240.6 million for Q1/2022. The realized financial derivatives gain of $5.4 million for Q1/2023 was primarily a result of the market prices for crude oil settling at levels below those set in our derivative contracts. The unrealized gain of $9.2 million for Q1/2023 reflects changes in forecasted crude oil pricing used to revalue the unsettled notional volume on our crude oil contracts in place at March 31, 2023 relative to December 31, 2022.The fair value of our financial derivative contracts resulted in a net asset of $19.3 million at March 31, 2023 compared to a net asset of $10.1 million at December 31, 2022.

We had the following commodity financial derivative contracts as at May 4, 2023.

	Remaining Period	Volume	Price/Unit (1)	Index
Oil
Basis differential (2)	May 2023 to Dec 2023	1,500 bbl/d	Baytex pays: MSW Baytex receives: WTI less US$2.50/bbl	MSW
Basis differential (2)	May 2023 to Dec 2023	5,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.10/bbl	WCS
Collar (3)(4)	May 2023 to Dec 2023	14,500 bbl/d	US$60.00/US$100.00	WTI
Put option (4)	May 2023 to Dec 2023	5,000 bbl/d	US$60.00	WTI

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

(2)Contracts that fix the basis differential between certain oil reference prices.

(3)As of March 31, 2023, Baytex had 3-way option contracts with a total volume of 9,500 bbl/d with an average sold put price of US$61.58/bbl, an average bought put price of US$78.37/bbl and an average sold call price of US$96.12/bbl along with a 5,000 bbl/d collar contract with a bought put price of US$60.00/bbl and sold call price US$94.00/bbl. On May 3, 2023 the Company restructured these hedges into a collar with a bought put price of US$60.00/bbl and sold call price US$100.00/bbl and received US$11.3 million.

(4)Contract entered subsequent to March 31, 2023.

Baytex Energy Corp.                                            

Q1 2023 MD&A    8

OPERATING NETBACK

The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
	2023						2022
($ per boe except for volume)	Canada		U.S.		Total		Canada		U.S.		Total
Total production (boe/d)	60,651		26,109		86,760		53,385		27,482		80,867
Operating netback:
Total sales, net of blending and other expense (1)	$	59.71	$	72.22	$	63.48	$	85.81	$	89.00	$	86.89
Less:
Royalties (2)	(8.03)		(21.02)		(11.94)		(12.00)		(26.30)		(16.86)
Operating expense (2)	(16.70)		(9.03)		(14.40)		(16.35)		(8.99)		(13.85)
Transportation expense (2)	(3.12)		—		(2.18)		(1.92)		—		(1.27)
Operating netback (1)	$	31.86	$	42.17	$	34.96	$	55.54	$	53.71	$	54.91
Realized financial derivatives gain (loss) (3)	—		—		0.69		—		—		(11.59)
Operating netback after financial derivatives (1)	$	31.86	$	42.17	$	35.65	$	55.54	$	53.71	$	43.32

(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)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.

Total operating netback of $34.96/boe for Q1/2023 was lower than $54.91/boe for Q1/2022 due to decreases in benchmark pricing which resulted in lower per unit sales net of royalties during Q1/2023 relative to Q1/2022. Total operating and transportation expense of $16.58/boe for Q1/2023 was higher than $15.12/boe for Q1/2022 due to increases in trucking rates period over period. Our operating netback net of realized gains and losses on financial derivatives was $35.65/boe for Q1/2023 compared to $43.32/boe for Q1/2022.

GENERAL AND ADMINISTRATIVE EXPENSE

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

The following table summarizes our G&A expense for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
($ thousands except for per boe)	2023		2022		Change
Gross general and administrative expense	$	14,416	$	13,507	$	909
Overhead recoveries	(2,682)		(1,825)		(857)
General and administrative expense	$	11,734	$	11,682	$	52
General and administrative expense per boe (1)	$	1.50	$	1.61	$	(0.11)

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

G&A expense was $11.7 million ($1.50/boe) for Q1/2023 which is consistent with $11.7 million ($1.61/boe) for Q1/2022. Gross G&A increased $0.9 million in Q1/2023 from Q1/2022 which reflects the impacts of inflation and was offset by higher overhead recoveries from additional exploration and development expenditures in Q1/2023. G&A expense of $1.50/boe for Q1/2023 is slightly below our 2023 annual guidance of $1.63/boe as Q1/2023 reflects higher overhead recoveries from our active exploration and development.

Baytex Energy Corp.                                            

Q1 2023 MD&A    9

FINANCING AND INTEREST EXPENSE

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

The following table summarizes our financing and interest expense for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
($ thousands except for per boe)	2023		2022		Change
Interest on credit facilities	$	6,216	$	3,039	$	3,177
Interest on long-term notes	12,094		17,344		(5,250)
Interest on lease obligations	65		44		21
Cash interest	$	18,375	$	20,427	$	(2,052)
Accretion of debt issue costs	524		695		(171)
Accretion of asset retirement obligations	4,826		3,122		1,704
Financing and interest expense	$	23,725	$	24,244	$	(519)
Cash interest per boe (1)	$	2.35	$	2.81	$	(0.46)
Financing and interest expense per boe (1)	$	3.04	$	3.33	$	(0.29)

(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 $23.7 million ($3.04/boe) for Q1/2023 compared to $24.2 million ($3.33/boe) for Q1/2022.

Cash interest of $18.4 million ($2.35/boe) for Q1/2023 was lower than $20.4 million ($2.81/boe) for Q1/2022 and is primarily a result of decreased interest on our long-term notes following the repurchase and redemption of US$290.2 million of principal amount during 2022. The decrease in interest due to reduced long-term notes principal outstanding was partially offset by the increase in benchmark borrowing rates which resulted in higher interest on our credit facilities in Q1/2023 relative to Q1/2022. The weighted average interest rate applicable on our credit facilities was 6.0% for Q1/2023 compared to 2.4% for Q1/2022.

Accretion of asset retirement obligations of $4.8 million for Q1/2023 was higher than $3.1 million for Q1/2022 due to a higher discount rate used in Q1/2023.

Cash interest expense of $2.35/boe for Q1/2023 is higher than our 2023 annual guidance of $2.04/boe which is consistent with expectations as we expect to reduce debt and increase production throughout the remainder of 2023.

EXPLORATION AND EVALUATION EXPENSE

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense was $0.2 million for Q1/2023 compared to $3.6 million for Q1/2022.

Baytex Energy Corp.                                            

Q1 2023 MD&A    10

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved plus probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three months ended March 31, 2023 and 2022.

	Three Months Ended March 31
($ thousands except for per boe)	2023		2022		Change
Depletion	$	164,435	$	139,446	$	24,989
Depreciation	1,564		1,345		219
Depletion and depreciation	$	165,999	$	140,791	$	25,208
Depletion and depreciation per boe (1)	$	21.26	$	19.34	$	1.92

(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 $166.0 million ($21.26/boe) for Q1/2023 compared to $140.8 million ($19.34/boe) for Q1/2022. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q1/2023 relative to Q1/2022 as a result of the $245.2 million impairment reversal that was recorded at December 31, 2022 and the increase in future development costs attributed to proved plus probable reserves which resulted in a higher depletable base for our Canadian oil and gas properties as at March 31, 2023.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at March 31, 2023.

2022 Impairment Reversal

At December 31, 2022, we identified indicators of impairment reversal for oil and gas properties in five of our six CGUs due to the increase in forecasted commodity prices in addition to changes in proved plus probable reserves, which resulted in an impairment reversal of $245.2 million. At December 31, 2022, we identified indicators of impairment reversal for E&E assets in the Peace River CGU due to an increase in land sale values and recorded an impairment reversal of $22.5 million. The total impairment reversal recorded at December 31, 2022 was $267.7 million.

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 equity-settled awards 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 cash-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding financial liability included in trade and other payables, and includes gains or losses on equity total return swaps. The liability is re-measured at each reporting date and results in either a SBC expense or recovery based on changes in our share price.

We recorded SBC expense of $9.8 million for Q1/2023 which is higher than $3.9 million for Q1/2022 as we received Board approval for the application of a 1.5x performance factor for 2022 that was applied to performance awards at Q1/2023. The total expense for Q1/2023 is considered cash compensation as we expect all future awards to be settled in cash while the Company is repurchasing shares as part of its shareholder return program. SBC expense of $3.9 million recorded in Q1/2022 was comprised of $2.2 million cash compensation expense and $1.7 million non-cash compensation expense.

In Q1/2023 we reduced the notional amount of the equity total return swaps to match the number of awards outstanding under the Deferred Share Unit Plan where we previously had targeted an amount equivalent to approximately 90-100% of all cash settled awards outstanding, including incentive awards and certain awards outstanding under the Share Award Incentive Plan.

FOREIGN EXCHANGE

Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and 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.

Baytex Energy Corp.                                            

Q1 2023 MD&A    11

	Three Months Ended March 31
($ thousands except for exchange rates)	2023		2022		Change
Unrealized foreign exchange gain	$	(213)	$	(14,548)	$	14,335
Realized foreign exchange loss	150		203		(53)
Foreign exchange gain	$	(63)	$	(14,345)	$	14,282
CAD/USD exchange rates:
At beginning of period	1.3534		1.2656
At end of period	1.3528		1.2484

We recorded a foreign exchange gain of $0.1 million for Q1/2023 compared to a gain of $14.3 million for Q1/2022.

The unrealized foreign exchange gain of $0.2 million for Q1/2023 is related to changes in the reported amount of our long-term notes and credit facilities and reflects a CAD/USD exchange rate of 1.3534 at March 31, 2023 which is consistent with 1.3528 at December 31, 2022. The unrealized foreign exchange gain of $14.5 million for Q1/2022 is primarily related to changes in the reported amount of our long-term notes due to a strengthening of the Canadian dollar relative to the U.S. dollar at March 31, 2022 compared to December 31, 2021.

Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange loss of $0.2 million for Q1/2023 which is consistent with Q1/2022.

INCOME TAXES

	Three Months Ended March 31
($ thousands)	2023		2022		Change
Current income tax expense	$	1,120	$	910	$	210
Deferred income tax expense (recovery)	15,523		(67,332)		82,855
Total income tax expense (recovery)	$	16,643	$	(66,422)	$	83,065

Current income tax expense was $1.1 million for Q1/2023 compared to $0.9 million for Q1/2022.

We recorded deferred tax expense of $15.5 million for Q1/2023 compared to a recovery of $67.3 million for Q1/2022. The deferred tax expense recorded in Q1/2023 is the result of income generated for the period. The deferred tax recovery recorded in Q1/2022 was primarily related to the effect of an internal debt restructuring offset by the income generated in our U.S. operations for the period.

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

Baytex Energy Corp.                                            

Q1 2023 MD&A    12

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income for the three months ended March 31, 2023 and 2022 are set forth in the following table.

	Three Months Ended March 31
($ thousands)	2023		2022		Change
Petroleum and natural gas sales	$	555,336	$	673,825	$	(118,489)
Royalties	(93,253)		(122,720)		29,467
Revenue, net of royalties	462,083		551,105		(89,022)
Expenses
Operating	(112,408)		(100,766)		(11,642)
Transportation	(17,005)		(9,215)		(7,790)
Blending and other	(59,681)		(41,440)		(18,241)
Operating netback (1)	$	272,989	$	399,684	$	(126,695)
General and administrative	(11,734)		(11,682)		(52)
Cash interest	(18,375)		(20,427)		2,052
Realized financial derivatives gain (loss)	5,415		(84,366)		89,781
Realized foreign exchange loss	(150)		(203)		53
Other expense	(213)		(250)		37
Current income tax expense	(1,120)		(910)		(210)
Cash share-based compensation	(9,823)		(2,239)		(7,584)
Adjusted funds flow (2)	$	236,989	$	279,607	$	(42,618)
Transaction costs	(8,871)		—		(8,871)
Exploration and evaluation	(163)		(3,570)		3,407
Depletion and depreciation	(165,999)		(140,791)		(25,208)
Non-cash share-based compensation	—		(1,706)		1,706
Non-cash financing and interest	(5,350)		(3,817)		(1,533)
Non-cash other income	1,271		1,282		(11)
Unrealized financial derivatives gain (loss)	9,210		(156,261)		165,471
Unrealized foreign exchange gain	213		14,548		(14,335)
(Loss) gain on dispositions	(336)		234		(570)
Deferred income tax (expense) recovery	(15,523)		67,332		(82,855)
Net income	$	51,441	$	56,858	$	(5,417)

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

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

We generated adjusted funds flow of $237.0 million for Q1/2023 compared to $279.6 million for Q1/2022. The decrease in adjusted funds flow was primarily due to lower operating netback in Q1/2023 which decreased $126.7 million relative to Q1/2022 as a result of lower commodity prices that decreased revenue, net of royalties. The decrease in operating netback was partially offset by the realized gain on financial derivatives of $5.4 million for Q1/2023 which increased $89.8 million relative to Q1/2022 when we recorded a realized loss on financial derivatives of $84.4 million. We reported net income of $51.4 million for Q1/2023 which is relatively consistent with $56.9 million reported for Q1/2022.

OTHER COMPREHENSIVE INCOME (LOSS)

Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation loss of $0.5 million for Q1/2023 relates to the change in value of our U.S. net assets and reflects a CAD/USD exchange rate of 1.3528 CAD/USD as at March 31, 2023 which is consistent with 1.3534 CAD/USD at December 31, 2022.

Baytex Energy Corp.                                            

Q1 2023 MD&A    13

CAPITAL EXPENDITURES

Capital expenditures for the three months ended March 31, 2023 and 2022 are summarized as follows.

	Three Months Ended March 31
	2023						2022
($ thousands)	Canada		U.S.		Total		Canada		U.S.		Total
Drilling, completion and equipping	$	154,953	$	48,836	$	203,789	$	107,000	$	27,138	$	134,138
Facilities	16,985		—		16,985		7,764		386		8,150
Land, seismic and other	12,668		184		12,852		11,366		168		11,534
Exploration and development expenditures	$	184,606	$	49,020	$	233,626	$	126,130	$	27,692	$	153,822
Property acquisitions	$	506	$	—	$	506	$	59	$	—	$	59
Proceeds from dispositions	$	(235)	$	—	$	(235)	$	(27)	$	—	$	(27)

Exploration and development expenditures were $233.6 million for Q1/2023 compared to $153.8 million for Q1/2022. Exploration and development expenditures in Q1/2023 were higher compared to Q1/2022 as a result of increased development activity along with inflationary pressures that resulted in higher costs relative to 2022.

In Canada, exploration and development expenditures were $184.6 million in Q1/2023 compared to $126.1 million in Q1/2022. Drilling and completion spending of $155.0 million in Q1/2023 reflects higher light and heavy oil development activity relative to Q1/2022 when we spent $107.0 million. We also invested $17.0 million on facilities and $12.7 million on land, seismic and other expenditures during Q1/2023.

Total U.S. exploration and development expenditures were $49.0 million for Q1/2023 compared to $27.7 million in Q1/2022. Exploration and development expenditures for Q1/2023 included costs associated with drilling 24 (6.5 net) wells along with 24 (6.4 net) wells brought on production compared to drilling 16 (2.5 net) wells along with 17 (4.8 net) wells brought on production during Q1/2022.

Exploration and development expenditures of $233.6 million for Q1/2023 were consistent with expectations as activity was planned to be weighted early in the year. Our annual guidance of $575 - $650 million reflects moderated activity levels over the remainder of 2023.

CAPITAL RESOURCES AND LIQUIDITY

Our objective for capital management is to maintain a flexible capital structure and sufficient sources of liquidity to execute our capital programs, while meeting our short and long-term commitments. We strive to actively manage our capital structure in response to changes in economic conditions. At March 31, 2023, 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 Baytex in order to sustain operations and support our long-term plans. At March 31, 2023, net debt(1) of $995.2 million was consistent with $987.4 million at December 31, 2022 as approximately 40% of our planned 2023 annual exploration and development expenditures occurred during Q1/2023.

We monitor our capital structure and liquidity requirements using a net debt to adjusted funds flow ratio calculated on a trailing twelve-month basis. At March 31, 2023, our net debt to adjusted funds flow ratio(1) was 0.9 compared to a ratio of 0.8 as at December 31, 2022. The increase in the net debt to adjusted funds flow ratio relative to December 31, 2022 is attributed to lower adjusted funds flow for the trailing twelve months ended March 31, 2023 compared to the twelve months ended December 31, 2022.

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

Credit Facilities

At March 31, 2023, we had $409.7 million of principal amount outstanding under our revolving credit facilities which total US$850 million and mature on April 1, 2026 (the "Credit Facilities"). The Credit Facilities are comprised of a US$50 million operating loan and a US$600 million syndicated revolving loan for Baytex and a US$10 million operating loan and a US$190 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.

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 6.0% for Q1/2023 compared to 2.4% for Q1/2022. The interest rate on our Credit Facilities has increased with higher government benchmark rates in 2023 relative to the same period in 2022.

At March 31, 2023, Baytex had $15.7 million of outstanding letters of credit under a $20 million uncommitted unsecured demand revolving letter of credit facility (December 31, 2022 - $15.7 million outstanding). Letters of credit under this facility are guaranteed by Export Development Canada and do not use capacity available under the Credit Facilities.

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

In connection with the Merger Transaction, we have entered into credit facility commitments with a syndicate of banks to provide aggregate debt commitments of US$1.75 billion comprised of a US$1.0 billion revolving credit facility (an increase from the committed amount of US$850 million in aggregate as of April 1, 2022), a US$250 million two-year term loan and 364-day bridge loan facility in an aggregate principal amount of US$500 million (the "Bridge Loan"). The Bridge Loan was cancelled as of April 28, 2023. At closing of the merger with Ranger we expect to increase the capacity of the revolving credit facilities to US$1.1 billion. The amended agreement will contain an additional financial covenant of a maximum Total Debt(1) to EBITDA(2) ratio of 4.0:1.0.

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

(2)Calculated in accordance with the Credit Facilities Agreement.

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and our compliance therewith at March 31, 2023.

Covenant Description	Position as at March 31, 2023	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.3:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	15.4:1.0	2.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at March 31, 2023, the Company's Senior Secured Debt totaled $409.7 million.

(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended March 31, 2023 was $1.2 billion.

(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expense, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expense for the twelve months ended March 31, 2023 was $78.1 million.

Long-Term Notes

We have one series of long-term notes outstanding with a total principal amount of $554.4 million as at March 31, 2023. The long-term notes do not contain any financial maintenance covenants.

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.

On April 27, 2023, we closed a private offering of the US$800 million aggregate principal amount of senior unsecured notes due 2030 ("8.5% Senior Notes"). The 8.5% Senior Notes were priced at 98.709% of par and will bear interest at a rate of 8.5% per annum and mature on April 30, 2030. Proceeds from the 8.5% Senior Notes will initially be deposited into escrow and will be released at closing of the merger with Ranger and will be used, in part, to fund a portion of the costs and expenses for the merger with Ranger.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the three months ended March 31, 2023, we issued 0.6 million common shares pursuant to our share-based compensation program. As at March 31, 2023, we had 545.6 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 March 31, 2023 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	$	271,022	$	269,177	$	1,845	$	—	$	—
Credit facilities - principal	409,653		—		—		409,653		—
Long-term notes - principal	554,351		—		—		554,351		—
Interest on long-term notes (1)	194,288		48,506		97,011		48,771		—
Lease obligations - principal	8,570		4,914		3,336		320		—
Processing agreements	6,093		941		1,051		698		3,403
Transportation agreements	188,698		39,293		76,525		65,349		7,531
Total	$	1,632,675	$	362,831	$	179,768	$	1,079,142	$	10,934

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

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

Baytex Energy Corp.                                            

Q1 2023 MD&A    14

QUARTERLY FINANCIAL INFORMATION

	2023	2022				2021
($ thousands, except per common share amounts)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Petroleum and natural gas sales	555,336	648,986	712,065	854,169	673,825	552,403	488,736	442,354
Net income	51,441	352,807	264,968	180,972	56,858	563,239	32,713	1,052,999
Per common share - basic	0.09	0.65	0.48	0.32	0.10	1.00	0.06	1.87
Per common share - diluted	0.09	0.64	0.47	0.32	0.10	0.98	0.06	1.85
Adjusted funds flow (1)	236,989	255,552	284,288	345,704	279,607	214,766	198,397	175,883
Per common share - basic	0.43	0.47	0.51	0.61	0.49	0.38	0.35	0.31
Per common share - diluted	0.43	0.46	0.51	0.60	0.49	0.37	0.35	0.31
Free cash flow (2)	(1,918)	143,324	111,568	245,316	121,318	137,133	101,215	112,486
Per common share - basic	—	0.26	0.20	0.43	0.21	0.24	0.18	0.20
Per common share - diluted	—	0.26	0.20	0.43	0.21	0.24	0.18	0.20
Cash flows from operating activities	184,938	303,441	310,423	360,034	198,974	240,567	178,961	171,876
Per common share - basic	0.34	0.56	0.56	0.63	0.35	0.43	0.32	0.30
Per common share - diluted	0.34	0.55	0.56	0.63	0.35	0.42	0.31	0.30
Exploration and development	233,626	103,634	167,453	96,633	153,822	73,995	94,235	61,485
Canada	184,606	85,641	117,150	51,881	126,130	59,821	75,499	30,387
U.S.	49,020	17,993	50,303	44,752	27,692	14,174	18,736	31,098
Property acquisitions	506	1,085	—	208	59	1,443	89	—
Proceeds from dispositions	(235)	(148)	(25,460)	(14)	(27)	(6,857)	(701)	(18)
Net debt (1)	995,170	987,446	1,113,559	1,123,297	1,275,680	1,409,717	1,564,658	1,629,629
Total assets	5,180,059	5,103,769	4,923,617	4,870,432	4,917,811	4,834,643	4,453,971	4,438,162
Common shares outstanding	545,553	544,930	547,615	560,139	569,214	564,213	564,213	564,182
Daily production
Total production (boe/d)	86,760	86,864	83,194	83,090	80,867	80,789	79,872	81,162
Canada (boe/d)	60,651	56,946	55,803	54,919	53,385	50,362	48,124	47,205
U.S. (boe/d)	26,109	29,918	27,391	28,170	27,482	30,428	31,748	33,957
Benchmark prices
WTI oil (US$/bbl)	76.13	82.64	91.56	108.41	94.29	77.19	70.56	66.07
WCS heavy oil ($/bbl)	69.44	77.37	93.62	122.05	100.99	78.82	71.81	67.03
Edmonton par oil ($/bbl)	99.04	109.57	116.79	137.79	115.66	93.29	83.78	77.28
CAD/USD avg exchange rate	1.3520	1.3577	1.3059	1.2766	1.2661	1.2600	1.2601	1.2279
AECO natural gas ($/mcf)	4.34	5.58	5.81	6.27	4.59	4.94	3.54	2.85
NYMEX natural gas (US$/mmbtu)	3.42	6.26	8.20	7.17	4.95	5.83	4.01	2.83
Total sales, net of blending and other expense ($/boe) (2)	63.48	74.93	87.68	105.44	86.89	70.42	63.85	57.19
Royalties ($/boe) (3)	(11.94)	(15.23)	(19.21)	(22.69)	(16.86)	(13.47)	(12.32)	(11.04)
Operating expense ($/boe) (3)	(14.40)	(13.06)	(14.39)	(14.21)	(13.85)	(12.83)	(11.46)	(11.22)
Transportation expense ($/boe) (3)	(2.18)	(1.85)	(1.67)	(1.56)	(1.27)	(1.10)	(1.06)	(1.01)
Operating netback ($/boe) (2)	34.96	44.79	52.41	66.98	54.91	43.02	39.01	33.92
Financial derivatives (loss) gain ($/boe) (3)	0.69	(6.21)	(9.98)	(16.41)	(11.59)	(9.49)	(7.34)	(5.28)
Operating netback after financial derivatives ($/boe) (2)	35.65	38.58	42.43	50.57	43.32	33.53	31.67	28.64

(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.

(3)Calculated as royalties, 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.                                            

Q1 2023 MD&A    15

Our results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have strengthened. Production steadily increased from 81,162 boe/d in Q2/2021 to 86,760 boe/d in Q1/2023 as a result of strong well performance and increased development activity as commodity prices improved.

Commodity prices strengthened to multi-year highs in 2022 following Russia's invasion of Ukraine which created elevated uncertainty surrounding the global supply of oil and natural gas and is reflected in our realized sales price of $105.44/boe for Q2/2022. Our realized price of $63.48/boe for Q1/2023 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 $237.0 million for Q1/2023 reflects strong 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) decreased from $1.6 billion at Q2/2021 to $995.2 million at Q1/2023 as free cash flow(2) of $970.4 million generated over the last eight quarters has been primarily directed towards debt repayment. The decrease in net debt is partially offset by $159.0 million in shareholder returns and an increase in the CAD/USD exchange rate.

(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.

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, 2022 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, 2022, additional information related to our emissions and sustainability initiatives is available on our website.

Reporting Regulations

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

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at March 31, 2023, nor are any such arrangements outstanding as of the date of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

There have been no changes in our critical accounting estimates in the three months ended March 31, 2023. 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, 2022.

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", "total debt", "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.

Baytex Energy Corp.                                            

Q1 2023 MD&A    16

Non-GAAP Financial Measures

Total sales, net of blending and other expense and heavy oil, net of blending and other expense

Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated as heavy oil sales less 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.

The following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements in the following table.

	Three Months Ended March 31
($ thousands)	2023		2022
Petroleum and natural gas sales	$	555,336	$	673,825
Light oil and condensate (1)	(288,467)		(360,976)
NGL (1)	(21,833)		(29,490)
Natural gas sales (1)	(27,951)		(38,920)
Heavy oil sales	$	217,085	$	244,439
Blending and other expense (2)	(59,681)		(41,440)
Heavy oil, net of blending and other expense	$	157,404	$	202,999

(1)Component of petroleum and natural gas sales. See Note 13 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three months ended March 31, 2023 for further information.

(2)The portion of blending and other expense that relates to heavy oil sales for the applicable period.

Operating netback

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

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

	Three Months Ended March 31
($ thousands)	2023		2022
Petroleum and natural gas sales	$	555,336	$	673,825
Blending and other expense	(59,681)		(41,440)
Total sales, net of blending and other expense	$	495,655	$	632,385
Royalties	(93,253)		(122,720)
Operating expense	(112,408)		(100,766)
Transportation expense	(17,005)		(9,215)
Operating netback	$	272,989	$	399,684
Realized financial derivatives gain (loss) (1)	5,415		(84,366)
Operating netback after realized financial derivatives	$	278,404	$	315,318

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three months ended March 31, 2023 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, payments on lease obligations, and transaction costs.

Baytex Energy Corp.                                            

Q1 2023 MD&A    17

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

	Three Months Ended March 31
($ thousands)	2023		2022
Cash flows from operating activities	$	184,938	$	198,974
Change in non-cash working capital	39,054		77,340
Additions to exploration and evaluation assets	(490)		(3,559)
Additions to oil and gas properties	(233,136)		(150,263)
Payments on lease obligations	(1,155)		(1,174)
Transaction costs	8,871		—
Free cash flow	$	(1,918)	$	121,318

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

Total sales, net of blending and other expense per boe

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

Average royalty rate

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

Operating netback per boe

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

Capital Management Measures

Total debt and Net debt

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

Baytex Energy Corp.                                            

Q1 2023 MD&A    18

The following table summarizes our calculation of total debt and net debt.

($ thousands)	March 31, 2023		December 31, 2022
Credit facilities	$	407,473	$	383,031
Unamortized debt issuance costs - Credit facilities (1)	2,180		2,363
Long-term notes	547,698		547,598
Unamortized debt issuance costs - Long-term notes (1)	6,653		6,999
Total debt	$	964,004	$	939,991
Trade and other payables	271,022		281,404
Cash	(6,445)		(5,464)
Trade and other receivables	(233,411)		(228,485)
Net debt	$	995,170	$	987,446
Net debt to adjusted funds flow	0.9		0.8

(1)Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three months ended March 31, 2023. 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, asset retirement obligations settled during the applicable period, and transaction costs.

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

	Three Months Ended March 31
($ thousands)	2023		2022
Cash flow from operating activities	$	184,938	$	198,974
Change in non-cash working capital	39,054		77,340
Asset retirement obligations settled	4,126		3,293
Transaction costs	8,871		—
Adjusted funds flow	$	236,989	$	279,607

INTERNAL CONTROL OVER FINANCIAL REPORTING

We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no such weaknesses were identified in, or changes were made to, internal controls over financial reporting during the three months ended March 31, 2023.

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: that the Merger Transaction creates a more resilient and sustainable business with higher revenues, improved margins and enhanced inventory which will allow for a more robust shareholder return framework; that following the Merger Transaction we intend to increase direct shareholder returns to 50% of free cash flow, including implementation of a quarterly dividend of $0.0225 per share ($0.09 per share annualized) and the timing thereof; the expected closing date of the Merger Transaction; our 2023 guidance on a stand-alone basis (excluding Ranger) 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; that we expect to cash settle share awards; the reassessment of our tax filings by the Canada Revenue Agency; our intention to defend the reassessments; our view of our tax filing position; the manner in which we fund our planned capital expenditures and monitor and manage our capital resources and liquidity; that we may issue debt or equity securities, sell assets or adjust capital spending; and the expected composition of our credit facilities on closing of the Merger Transaction.

Baytex Energy Corp.                                            

Q1 2023 MD&A    19

These forward-looking statements are based on certain key assumptions regarding, among other things: the consummation and success of the Merger Transaction and our ability to successfully integrate the acquired business into our existing operations; the timing of receipt of regulatory and shareholder and stockholder approvals; the ability of the combined business to realize the anticipated benefits of the transaction; 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 ability to obtain stockholder, shareholder, and regulatory approvals, if any, of the Merger Transaction; the ability to complete the Merger Transaction on anticipated terms and timetable; the possibility that various closing conditions for the transaction may not be satisfied or waived; risks relating to any unforeseen liabilities of Baytex and Ranger; 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, 2022, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings.

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.

Dividend Advisory

Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board of Directors of Baytex. There can be no assurance that Baytex will pay dividends following closing of the Merger Transaction.