Form 6-K - Report of foreign issuer [Rules 13a-16 and 15d-16]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 Under the

Securities Exchange Act of 1934

For the month of August 2023

Commission File Number: 1-32754

BAYTEX ENERGY CORP.

(Exact name of registrant as specified in its charter)

2800, 520 – 3^rd AVENUE S.W.

CALGARY, ALBERTA, CANADA

T2P 0R3

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F

Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

The following document attached as an exhibit hereto is incorporated by reference herein:

Exhibit No.	Document
99.1	Baytex Energy Corp. Q2 2023 Report

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BAYTEX ENERGY CORP.

	/s/ James R. Maclean
	Name:	James R. Maclean
	Title:	Chief Legal Officer and Corporate Secretary

Dated: August 1, 2023

Exhibit 99.1

BAYTEX ANNOUNCES SECOND QUARTER 2023 RESULTS

CALGARY, ALBERTA (July 27, 2023) - Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2023 (all amounts are in Canadian dollars unless otherwise noted).

“We continue to execute on our base business, and following the Ranger transaction, have emerged as a well-capitalized and diversified North American exploration and production company. We have a strong portfolio of high-quality oil weighted assets in Western Canada and the Eagle Ford shale in Texas and we are poised to deliver a powerful combination of free cash flow and increased shareholder returns on a per-share basis. We have initiated our share buyback program (repurchased 4.7 million shares to-date in July) and declared a quarterly dividend of $0.0225 per share ($0.09 per share annualized). We are committed to operational excellence and delivering long-term value and enhanced shareholder returns," commented Eric T. Greager, President and Chief Executive Officer.

Highlights

	·	Completed the acquisition of Ranger Oil Corporation ("Ranger") on June 20, 2023.
	·	Generated production of 89,761 boe/d (86% oil and NGLs) in Q2/2023.
	·	Reported cash flows from operating activities of $192 million ($0.33 per basic share) in Q2/2023.
	·	Delivered adjusted funds flow⁽¹⁾ of $274 million ($0.47 per basic share) in Q2/2023.
	·	Generated free cash flow⁽²⁾ of $96 million ($0.17 per basic share) in Q2/2023.
	·	Exploration and development expenditures totaled $171 million in Q2/2023, consistent with our full-year plan.
	·	Completed six-well Duvernay program with wells onstream in Q3/2023.
	·	New heavy oil exploration success in Waseca near Cold Lake, Alberta.

On June 20, 2023, we closed the acquisition of Ranger, adding quality scale in the Eagle Ford and reinforcing a resilient and sustainable business. The total consideration paid by Baytex, including assumption of net debt⁽¹⁾, was US$2.4 billion (C$3.2 billion). Under the terms of the agreement, Ranger shareholders received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger common stock. Our second quarter results include 11 days of operations from Ranger.

In conjunction with closing of the acquisition, we increased our direct shareholder returns to 50% of free cash flow⁽²⁾ which will allow us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow continues to be allocated to debt reduction.

On June 23, 2023, we renewed our Normal Course Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Through July 26, 2023, we have repurchased 4.7 million common shares at an average price of $4.59 per share.

The Board of Directors has declared a quarterly cash dividend of $0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023⁽³⁾

(1)	Capital management measure. Refer to the Specified Financial Measures in this press release 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 press release for further information.
(3)	Refer to the dividend advisory section in this press release for further information.

2023 Outlook

Following the Ranger transaction, Baytex has emerged as a well-capitalized, diversified oil-weighted North American E&P company with a strong free cash flow profile. Based on the forward strip⁽¹⁾, we expect to generate over $400 million of free cash flow⁽²⁾ in the second half of 2023, and approximately $500 million of free cash flow for the full-year 2023.

For 2023, we continue to forecast exploration and development expenditures of $1,005 to $1,045 million, which are expected to generate an average production rate of 120,500 to 122,500 boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production mix for the second half of 2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.

The following table summarizes our 2023 guidance for production and exploration and development expenditures.

	H1/2023 Actual			H2/2023 Guidance		2023 Guidance
Production (boe/d)		88,269	⁽³⁾		153,000-157,000		120,500-122,500
Exploration and development expenditures ($ millions)	$	404			$601-$641		$1,005-$1,045

We have updated our full-year 2023 cost assumptions to reflect the Ranger acquisition. Guidance for unit operating expenses decreased by 13% to reflect the lower cost structure of the Ranger asset base, while unit general and administrative expenses increased by 10% to reflect costs associated with Ranger personnel, and interest expense is higher due to the incremental debt associated with the Ranger acquisition as well as higher interest rates on the credit facility due to the rising interest rate environment.

The following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.

	2023 Original Guidance ⁽⁴⁾	2023 Revised Guidance ⁽⁵⁾
Expenses:
Average royalty rate ⁽²⁾	20.0 - 22.0%	21.0 - 22.0%
Operating ⁽⁶⁾	$14.00 - $14.75/boe	$12.25 - $12.75/boe
Transportation ⁽⁶⁾	$1.90 - $2.10/boe	$2.00 - $2.10/boe
General and administrative ⁽⁶⁾	$52 million ($1.63/boe)	$80 million ($1.80/boe)
Interest ⁽⁶⁾	$65 million ($2.04/boe)	$150 million ($3.38/boe)

Leasing expenditures	$4 million	$13 million
Asset retirement obligations	$25 million	$25 million

	(1)	H2/2023 commodity prices: WTI - US$75/bbl, WCS differential to WTI - US$14/bbl, NYMEX Gas - US$2.85/MMbtu; Exchange Rate (CAD/USD) - 1.32.
	(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 press release for further information.
	(3)	H1/2023 actual production is comprised of 33,510 bbl/d of light crude oil and medium crude oil (including condensate), 33,502 bbl/d of heavy crude oil, 7,920 bbl/d of natural gas liquids and 80,017 mcf/d of conventional natural gas.
	(4)	As announced on December 7, 2022.
	(5)	Includes Ranger from the closing date of the transaction (June 20, 2023).
	(6)	Calculated as operating, transportation, general and administrative or cash interest expense divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp. Second Quarter Report 2023

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
	2023			2023			2022			2023			2022
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales	$	598,760		$	555,336		$	854,169		$	1,154,096		$	1,527,994
Adjusted funds flow ⁽¹⁾		273,590			236,989			345,704			510,579			625,311
Per share – basic		0.47			0.43			0.61			0.90			1.10
Per share – diluted		0.47			0.43			0.60			0.90			1.10
Free cash flow ⁽²⁾		96,313			(1,918	)		245,316			94,395			366,634
Per share – basic		0.17			—			0.43			0.17			0.65
Per share – diluted		0.16			—			0.43			0.17			0.64
Cash flows from operating activities		192,308			184,938			360,034			377,246			559,008
Per share – basic		0.33			0.34			0.63			0.67			0.99
Per share – diluted		0.33			0.34			0.63			0.66			0.98
Net income		213,603			51,441			180,972			265,044			237,830
Per share – basic		0.37			0.09			0.32			0.47			0.42
Per share – diluted		0.36			0.09			0.32			0.47			0.42

Capital Expenditures
Exploration and development expenditures	$	170,704		$	233,626		$	96,633		$	404,330		$	250,455
Acquisitions and divestitures		(112	)		271			194			159			226
Total oil and natural gas capital expenditures	$	170,592		$	233,897		$	96,827		$	404,489		$	250,681

Net Debt
Credit facilities	$	986,903		$	409,653		$	496,917		$	986,903		$	496,917
Long-term notes		1,601,468			554,351			643,600			1,601,468			643,600
Long-term debt		2,588,371			964,004			1,140,517			2,588,371			1,140,517
Working capital		226,473			31,166			(17,220	)		226,473			(17,220	)
Net debt ⁽¹⁾	$	2,814,844		$	995,170		$	1,123,297		$	2,814,844		$	1,123,297

Shares Outstanding - basic (thousands)
Weighted average		583,365			545,062			566,997			564,319			566,262
End of period		862,192			545,553			560,139			862,192			560,139

BENCHMARK PRICES
Crude oil
WTI (US$/bbl)	$	73.78		$	76.13		$	108.41		$	74.96		$	101.35
MEH oil (US$/bbl)		75.01			77.42			112.41			76.22			104.56
MEH oil differential to WTI (US$/bbl)		1.23			1.29			4.00			1.26			3.21
Edmonton par ($/bbl)		95.13			99.04			137.79			97.09			126.72
Edmonton par differential to WTI (US$/bbl)		(2.95	)		(2.88	)		(0.47	)		(2.91	)		(1.68	)
WCS heavy oil ($/bbl)		78.85			69.44			122.05			74.16			111.48
WCS differential to WTI (US$/bbl)		(15.07	)		(24.77	)		(12.80	)		(19.92	)		(13.67	)
Natural gas
NYMEX (US$/mmbtu)	$	2.10		$	3.42		$	7.17		$	2.76		$	6.06
AECO ($/mcf)		2.35			4.34			6.27			3.34			5.43

CAD/USD average exchange rate		1.3431			1.3520			1.2766			1.3475			1.2714

Baytex Energy Corp. Second Quarter Report 2023

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
	2023			2023			2022			2023			2022
OPERATING
Daily Production
Light oil and condensate (bbl/d)		35,322			31,678			33,007			33,510			33,533
Heavy oil (bbl/d)		32,821			34,191			28,586			33,502			26,921
NGL (bbl/d)		8,620			7,213			7,468			7,920			7,552
Total liquids (bbl/d)		76,763			73,082			69,061			74,932			68,006
Natural gas (mcf/d)		77,989			82,066			84,169			80,017			83,873
Oil equivalent (boe/d @ 6:1) ⁽³⁾		89,761			86,760			83,090			88,269			81,985

Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense ⁽²⁾	$	545,765		$	495,655		$	797,274		$	1,041,420		$	1,429,659
Royalties		(107,920	)		(93,253	)		(171,559	)		(201,173	)		(294,279	)
Operating expense		(119,438	)		(112,408	)		(107,426	)		(231,846	)		(208,192	)
Transportation expense		(14,574	)		(17,005	)		(11,758	)		(31,579	)		(20,973	)
Operating netback ⁽²⁾	$	303,833		$	272,989		$	506,531		$	576,822		$	906,215
General and administrative		(15,240	)		(11,734	)		(11,640	)		(26,974	)		(23,322	)
Cash financing and interest		(28,255	)		(18,375	)		(20,474	)		(46,630	)		(40,901	)
Realized financial derivatives gain (loss)		16,365			5,415			(124,042	)		21,780			(208,408	)
Other ⁽⁴⁾		(3,113	)		(11,306	)		(4,671	)		(14,419	)		(8,273	)
Adjusted funds flow ⁽¹⁾	$	273,590		$	236,989		$	345,704		$	510,579		$	625,311

Netback (per boe) ⁽⁵⁾
Total sales, net of blending and other expense ⁽²⁾	$	66.82		$	63.48		$	105.44		$	65.18		$	96.34
Royalties		(13.21	)		(11.94	)		(22.69	)		(12.59	)		(19.83	)
Operating expense		(14.62	)		(14.40	)		(14.21	)		(14.51	)		(14.03	)
Transportation expense		(1.78	)		(2.18	)		(1.56	)		(1.98	)		(1.41	)
Operating netback ⁽²⁾	$	37.21		$	34.96		$	66.98		$	36.10		$	61.07
General and administrative		(1.87	)		(1.50	)		(1.54	)		(1.69	)		(1.57	)
Cash financing and interest		(3.46	)		(2.35	)		(2.71	)		(2.92	)		(2.76	)
Realized financial derivatives gain (loss)		2.00			0.69			(16.41	)		1.36			(14.04	)
Other ⁽⁴⁾		(0.39	)		(1.45	)		(0.60	)		(0.89	)		(0.56	)
Adjusted funds flow ⁽¹⁾	$	33.49		$	30.35		$	45.72		$	31.96		$	42.14

Notes:

(1)	Capital management measure. Refer to the Specified Financial Measures section in this press release 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 press release for further information.
(3)	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. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(4)	Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and cash share-based compensation. Refer to the Q2/2023 MD&A for further information on these amounts.
(5)	Calculated as royalties, operating, transportation, general and administrative, cash financing and interest expense or realized financial derivatives loss divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp. Second Quarter Report 2023

Q2/2023 Results

We continue to execute on our base business. Production In Q2/2023 was 89,761 boe/d (86% oil and NGLs), which includes production from Ranger for the 11 days following closing of the acquisition. Production exceeded the high end of our Q2/2023 guidance range of 88,500 to 89,000 boe/d due to the timing of operated Eagle Ford wells brought onstream late in the second quarter.

Production in Q2/2023 was reduced by approximately 4,500 boe/d due to the temporary curtailment of production caused by wildfires in Alberta. For the month of July, we expect production to be curtailed by approximately 2,000 boe/d. Wildfires continue to burn in northwest Alberta and we could see further interruptions through the summer and into the fall. We are incredibly proud of how our personnel have responded with sound, safety-focused decision making.

We delivered adjusted funds flow⁽¹⁾ of $274 million ($0.47 per basic share) and net income of $214 million ($0.37 per basic share) in Q2/2023. Exploration and development expenditures totaled $171 million in Q2/2023 and we brought 43 (34.9 net) wells onstream. During the second quarter, we generated free cash flow⁽²⁾ of $96 million ($0.17 per basic share).

Operating Results

Light Oil - United States

Our light oil assets in the United States are located in the liquids-rich Eagle Ford formation, in the Texas Gulf Coast Basin. The Ranger acquisition materially increased the scale of our Eagle Ford operations, adding 162,000 net acres in the crude oil window and on-trend with our non-operated position in the Karnes Trough. The transaction increased our exposure to premium U.S. Gulf Coast pricing and included substantial infrastructure in place with low operating and transportation costs.

Production in the Eagle Ford averaged 33,887 boe/d (82% oil and NGLs) during Q2/2023, and includes 11 days of production from the Ranger assets. During the second quarter, we brought 13 (4.9 net) wells onstream, including 2 (2.0 net) operated wells. We expect to bring approximately 24 net operated wells and 8 net non-operated wells to sales in H2/2023.

Light Oil - Canada

Our light oil production and development in Canada occurs from the Viking formation in west-central Saskatchewan and east-central Alberta, and the Duvernay formation in the Pembina area of central Alberta. The Viking is a shallow and highly repeatable light oil resource play with some of the highest operating netbacks in North America. Our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating netbacks, with the potential for strong economics and organic growth.

Our light oil production in Canada averaged 17,029 boe/d (86% oil and NGLs) during Q2/2023. In the Viking, we brought 28 (28.0 net) wells onstream in Q2/2023 and expect to bring another 46 net wells onstream in H2/2023. In the Pembina Duvernay, we commenced completion activities for the six wells (two-three well pads) drilled this year. Our completions and facility execution tracked ahead of plan, which allowed for an acceleration of the on-streaming of wells. Four of the six wells are in the early stages of flow back and are tracking to type curve initial rate expectations. The remaining two wells are expected to be onstream by mid-August.

Heavy Oil - Canada

Our heavy oil production and development in Canada occurs within the Bluesky and Spirit River (Clearwater) formations in the Peace River area of northwest Alberta and the Mannville group of formations in the greater Lloydminster region of east central Alberta and west central Saskatchewan. Our heavy oil business includes the use of innovative multi-lateral horizontal drilling with strong capital efficiencies. The core of our Clearwater play is located on the Peavine Métis settlement.

Our heavy oil assets produced a combined 34,955 boe/d (94% oil and NGLs) during Q2/2023. We brought onstream two net wells during the second quarter, which typically has lower activity due to spring breakup. Our heavy oil development program has ramped up in the third quarter with four rigs running, two at Peavine, one at Peace River and one at Lloydminster. In H2/2023, we expect to bring 40 net heavy oil wells onstream, 19 at Peavine, 18 at Lloydminster and 3 at Peace River.

In Q1/2023 we successfully drilled a six-leg Upper Waseca multi-lateral horizontal exploration well at Cold Lake, Alberta. The well was brought onstream in April and achieved a 30-day initial production rate of 165 bbl/d of 12.5° API crude oil. The Waseca formation is analogous to Clearwater reservoirs across the fairway and is highly amenable to open-hole development which drives strong returns and capital efficiencies. We are encouraged by this initial test result and are planning 3 follow-up wells in the second half of 2023, including a Lower Waseca test. We hold 20 prospective sections across the play. In addition, we will follow up our successful Q4/2022 Clearwater test well at Morinville, Alberta with two additional wells in the second half of 2023.

	(1)	Capital management measure. Refer to the Specified Financial Measures section in this press release 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 press release for further information.

Baytex Energy Corp. Second Quarter Report 2023

Financial Liquidity

We are well capitalized and have significant liquidity on our credit facilities. We have a US$1.1 billion revolving credit facility with a maturity date of April 1, 2026, and a US$150 million two-year term loan.

Our total debt⁽¹⁾, which includes our two series of long-term notes, is $2.6 billion as at June 30, 2023 and we maintain strong liquidity with approximately 40% undrawn capacity on our revolving credit facility.

Risk Management

We employ a hedge program to help mitigate the volatility in revenue due to changes in commodity prices.

For Q3/2023 and Q4/2023, we have entered into hedges on approximately 40% and 35% of our net crude oil exposure, respectively, utilizing a combination of two-way collars with a floor price of US$60/bbl and a ceiling price of US$100/bbl and a 5,000 bbl/d purchased put at US$60/bbl. For the first half of 2024, we have entered into hedges on approximately 22% of our net crude oil exposure utilizing two-way collars with a floor price of US$60/bbl and a ceiling price of US$99/bbl.

A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2023 financial statements.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2023 and the related Management's Discussion and Analysis of the operating and financial results can be accessed on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/ edgar.shtml.

(1) Calculated in accordance with the amended credit facilities agreement which is available on SEDAR at www.sedar.com.

Baytex Energy Corp. Second Quarter Report 2023

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex’s shareholders and potential investors with information regarding Baytex, including management’s assessment of Baytex’s future plans and operations, certain statements in this press release 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 "believe", "continue", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to but not limited to: that we are poised to deliver a powerful combination of free cash flow and increased shareholder returns on a per-share basis; we are committed to operational excellence and delivering long-term value and enhanced shareholder returns; expectations regarding our intention to further strengthen our balance sheet and the allocation of free cash flow, including with respect to debt repayment and shareholder returns; we expect to generate over $400 million of free cash flow in the second half of 2023, and approximately $500 million of free cash flow for the full-year 2023; our guidance for 2023 exploration and development expenditures, production (including production mix by product type), royalty rate, operating, transportation, general and administration and interest expense and leasing expenditures and asset retirement obligations; we could be impacted by Alberta wildfires through summer and fall; our plans and expectations in respect of our drilling program, including the number of net wells to be brought on line in H2/2023 and the location of such wells and follow up wells to be drilled at Cold Lake, Alberta and Morinville, Alberta; and our hedging plans.

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; the future impact of wildfires on our production; that our core assets have more than 10 years development inventory at the current pace of development; 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, including operating and transportation costs; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our hedging program; 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: risks relating to any unforeseen liabilities of Baytex; that Baytex fails to meet its guidance; the volatility of oil and natural gas prices and price differentials (including the impacts of Covid-19); risks related to ongoing wildfires; 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, including transportation costs; 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, 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.

This press release contains information that may be considered a financial outlook under applicable securities laws about Baytex’s pro forma capitalization upon completion of the Merger, which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth herein. The actual capitalization of Baytex will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, Baytex undertakes no obligation to update such financial outlook. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about Baytex’s potential future capitalization upon completion of the Merger. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.

Baytex Energy Corp. Second Quarter Report 2023

Dividend Advisory

Future dividends and share buybacks, 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) 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.

Specified Financial Measures

In this press release, we refer to certain financial measures (such as free cash flow, operating netback, average royalty rate and total sales, net of blending and other expense) 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 for other issuers. In addition, this press release contains the terms "adjusted funds flow" and "net debt" which are considered capital management measures.

Non-GAAP Financial Measures

Total sales, net of blending and other expense

Total sales, net of blending and other expense is not a measurement based on GAAP in Canada and 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 is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense. Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We believe that this measure assists in characterizing our ability to generate cash margin on a unit of production basis and is a key measure used to evaluate our operating performance.

The following table reconciles total sales, net of blending and other expense and operating netback to petroleum and natural gas sales.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023			2022			2023			2022
Petroleum and natural gas sales	$	598,760		$	854,169		$	1,154,096		$	1,527,994
Blending and other expense		(52,995	)		(56,895	)		(112,676	)		(98,335	)
Total sales, net of blending and other expense		545,765			797,274			1,041,420			1,429,659
Royalties		(107,920	)		(171,559	)		(201,173	)		(294,279	)
Operating expense		(119,438	)		(107,426	)		(231,846	)		(208,192	)
Transportation expense		(14,574	)		(11,758	)		(31,579	)		(20,973	)
Operating netback	$	303,833		$	506,531		$	576,822		$	906,215

Free cash flow

Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as 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. Our determination of free cash flow may not be comparable to other issuers. We use free cash flow to evaluate funds available for debt repayment, common share repurchases, potential future dividends and acquisition and disposition opportunities.

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

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023			2022			2023			2022
Cash flows from operating activities	$	192,308		$	360,034		$	377,246		$	559,008
Change in non-cash working capital		40,795			(17,046	)		79,849			60,294
Additions to exploration and evaluation assets		(741	)		(2,338	)		(1,231	)		(5,897	)
Additions to oil and gas properties		(169,963	)		(94,295	)		(403,099	)		(244,558	)
Payments on lease obligations		(1,181	)		(1,039	)		(2,336	)		(2,213	)
Transaction costs		32,832			—			41,703			—
Cash premiums on derivatives		2,263			—			2,263			—
Free cash flow	$	96,313		$	245,316		$	94,395		$	366,634

Baytex Energy Corp. Second Quarter Report 2023

Non-GAAP Financial Ratios

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 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. 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 equal to operating netback divided by barrels of oil equivalent sales volume for the applicable period and is used to assess our operating performance on a unit of production basis.

Capital Management Measures

Net debt

We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We define net debt to be the sum of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs adjusted for trade and other payables, cash, and trade and other receivables. We believe that this measure assists in providing a more complete understanding of our cash liabilities and provide a key measure to assess our liquidity. We use the principal amounts of the credit facilities and long-term notes outstanding in the calculation of net debt as these amounts represent our ultimate repayment obligation at maturity. The carrying amount of debt issue costs associated with the credit facilities and long-term notes is excluded on the basis that these amounts have already been paid by Baytex at inception of the contract and do not represent an additional source of capital or repayment obligation.

The following table summarizes our calculation of net debt.

($ thousands)	June 30, 2023			December 31, 2022
Credit facilities	$	964,332		$	383,031
Unamortized debt issuance costs - Credit facilities ⁽¹⁾		22,571			2,363
Long-term notes		1,563,897			547,598
Unamortized debt issuance costs - Long-term notes ⁽¹⁾		37,571			6,999
Trade and other payables		616,608			281,404
Cash		(19,637	)		(5,464	)
Trade and other receivables		(370,498	)		(228,485	)
Net debt	$	2,814,844		$	987,446

(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 and six months ended June 30, 2023.

Adjusted funds flow

Adjusted funds flow is a financial term commonly used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating working capital and asset retirement obligations settled. Our determination of adjusted funds flow may not be comparable to other issuers. We consider adjusted funds flow a key measure that provides a more complete understanding of operating performance and our ability to generate funds for exploration and development expenditures, debt repayment, settlement of our abandonment obligations and potential future dividends.

Baytex Energy Corp. Second Quarter Report 2023

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

	Three Months Ended June 30					Six Months Ended June 30
($ thousands)	2023		2022			2023		2022
Cash flow from operating activities	$	192,308	$	360,034		$	377,246	$	559,008
Change in non-cash working capital		40,795		(17,046	)		79,849		60,294
Asset retirement obligations settled		5,392		2,716			9,518		6,009
Transaction costs		32,832		—			41,703		—
Cash premiums on derivatives		2,263		—			2,263		—
Adjusted funds flow	$	273,590	$	345,704		$	510,579	$	625,311

Advisory Regarding Oil and Gas Information

Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

References herein to average 30-day initial production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

Throughout this press release, “oil and NGL” refers to heavy oil, bitumen, light and medium oil, tight oil, condensate and natural gas liquids (“NGL”) product types as defined by NI 51-101. The following table shows Baytex’s disaggregated production volumes for the three and six months ended June 30, 2023. The NI 51-101 product types are included as follows: “Heavy Crude Oil” - heavy crude oil and bitumen, “Light and Medium Crude Oil” - light and medium crude oil, tight oil and condensate, “NGL” - natural gas liquids and “Natural Gas” - shale gas and conventional natural gas.

	Three Months Ended June 30, 2023										Three Months Ended June 30, 2022
	Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)		Heavy Crude Oil (bbl/d)		Light and Medium Crude Oil (bbl/d)		NGL (bbl/d)		Natural Gas (Mcf/d)		Oil Equivalent (boe/d)
Canada – Heavy
Peace River		9,801		6		49		11,117		11,708		10,216		10		31		12,471		12,336
Lloydminster		11,398		23		—		1,228		11,625		11,051		8		—		1,729		11,347
Peavine		11,622		—		—		—		11,622		7,319		—		—		—		7,319

Canada - Light
Viking		—		13,265		181		12,105		15,464		—		14,103		184		13,202		16,487
Duvernay		—		675		566		1,946		1,565		—		801		620		2,007		1,756
Remaining Properties		—		643		638		15,647		3,890		—		753		983		23,627		5,674

United States
Eagle Ford		—		20,710		7,186		35,946		33,887		—		17,332		5,650		31,133		28,170

Total		32,821		35,322		8,620		77,989		89,761		28,586		33,007		7,468		84,169		83,090

Baytex Energy Corp. Second Quarter Report 2023

	Six Months Ended June 30, 2023						Six Months Ended June 30, 2022
		Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)		Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada – Heavy
Peace River		10,289	9	51	11,191	12,215		10,898	8	30	11,801	12,902
Lloydminster		11,522	17	—	1,223	11,743		10,775	11	—	1,758	11,079
Peavine		11,691	—	—	—	11,691		5,248	—	—	—	5,248

Canada - Light
Viking		—	13,948	187	11,864	16,113		—	14,894	186	12,552	17,172
Duvernay		—	868	754	2,283	2,002		—	896	705	2,174	1,963
Remaining Properties		—	658	661	19,001	4,485		—	810	956	24,158	5,792

United States
Eagle Ford		—	18,010	6,267	34,455	30,020		—	16,914	5,675	31,430	27,828

Total		33,502	33,510	7,920	80,017	88,269		26,921	33,533	7,552	83,873	81,985

Baytex Energy Corp.

Baytex Energy Corp. is an energy company with headquarters based in Calgary, Alberta and offices in Houston, Texas. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Baytex’s common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit our website at www.baytexenergy.com or contact:

Brian Ector, Senior Vice President, Capital Markets and Investor Relations

Toll Free Number: 1-800-524-5521

Email: investor@baytexenergy.com

Baytex Energy Corp. Second Quarter Report 2023

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2023 and 2022

Dated July 27, 2023

The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2023. This information is provided as of July 27, 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 and six months ended June 30, 2023 ("Q2/2023" and "YTD 2023") have been compared with the results for the three and six months ended June 30, 2022 ("Q2/2022" and "YTD 2022"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) as at June 30, 2023, and for the three and six months ended June 30, 2023 and 2022, 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" and "net debt" 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.

SECOND QUARTER HIGHLIGHTS

Business Combination

On June 20, 2023, Baytex and Ranger Oil Corporation ("Ranger") completed the merger of the two companies (the "Merger") whereby Baytex acquired all of the issued and outstanding common shares of Ranger. The Merger increases our Eagle Ford scale and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford. Production from the Ranger assets is approximately 70% weighted towards high netback light oil and is primarily operated which increases our ability to effectively allocate capital.

Operating and financial results for Q2/2023 include Ranger operations from the closing date of June 20, 2023 to June 30, 2023. Production from the properties contributed approximately 7,500 boe/d and 3,800 boe/d of production to Q2/2023 and YTD 2023, respectively. The companies began integration in Q2/2023 and operations have continued in-line with expectations for both the legacy Baytex and Ranger assets. The Merger was primarily funded with a combination of cash and shares.

We issued 311.4 million common shares and paid cash consideration of $732.8 million in addition to the assumption of $1.1 billion of Ranger's net debt. The cash portion of the transaction was funded with our expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. We closed the US$800 million principal amount senior unsecured note offering on April 27, 2023 with the proceeds released from escrow at completion of the Merger.

Baytex Energy Corp. Second Quarter Report 2023

Second Quarter Operating and Financial Results

Baytex delivered strong operating and financial results in Q2/2023. Production of 89,761 boe/d for Q2/2023 reflects the production contribution from the Merger with Ranger in addition to our successful development programs in the U.S. and Canada. Wildfires impacted our operations in Alberta and resulted in the temporary curtailment of production which reduced production for Q2/2023 by approximately 4,500 boe/d. We invested $170.7 million on exploration and development expenditures and generated free cash flow⁽¹⁾ of $96.3 million during Q2/2023.

Exploration and development expenditures totaled $170.7 million in Q2/2023. In the U.S. we invested $74.3 million during Q2/2023 which included $34.1 million of expenditures on our operated Eagle Ford properties subsequent to acquisition on June 20, 2023 to June 30, 2023. Production in the U.S. averaged 33,887 boe/d in Q2/2023 compared to 28,170 boe/d in Q2/2022. The increase in U.S. production is due to the production contribution from the properties acquired from Ranger which added 7,500 boe/d for Q2/2023. Production on our non-operated properties in the U.S. declined slightly relative to Q2/2022 with overall activity decreasing on our acreage. We invested $96.4 million in Canada in Q2/2023 that was primarily directed towards light oil development and included completion activities for six Duvernay wells expected to come on production during the third quarter. Production in Canada averaged 55,874 boe/d during Q2/2023 compared to 54,919 boe/d in Q2/2022. Production for Q2/2023 reflects the temporary curtailment of production due to Alberta wildfires which reduced production for the period by approximately 4,500 boe/d. There was no significant physical damage to our operations or assets as a result of the wildfires.

Oil prices decreased in Q2/2023 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$73.78/bbl and US $15.07/bbl during Q2/2023 compared to US$108.41/bbl and US$12.80/bbl respectively in Q2/2022. Adjusted funds flow⁽²⁾ of $273.6 million and cash flows from operating activities of $192.3 million for Q2/2023 reflect commodity prices that were lower relative to Q2/2022 when we generated adjusted funds flow of $345.7 million and cash flows from operating activities of $360.0 million.

Net debt⁽²⁾ of $2.8 billion at June 30, 2023 increased from $987.4 million at December 31, 2022 due to the cash consideration paid and net debt assumed in conjunction with the Merger with Ranger. We increased our shareholder returns to 50% of free cash flow in conjunction with the closing of the Merger which will allow us to increase our share buyback program and introduce a dividend. The remainder of our free cash flow will be allocated to debt reduction.

On June 23, 2023, we renewed our Normal Course Issuer Bid with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. Subsequent to June 30, 2023 and through to July 26, 2023, we repurchased 4.7 million common shares at an average price of $4.59 per share. The Board of Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”

(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.

2023 GUIDANCE

Following the Merger with Ranger, Baytex has emerged as a well-capitalized, diversified oil-weighted North American exploration and production company with a strong free cash flow profile. For 2023, we continue to forecast exploration and development expenditures of $1,005 to $1,045 million, which are expected to generate production of 120,500 to 122,500 boe/d. For the second half of 2023, we expect production to average 153,000 to 157,000 boe/d. Our production mix for the second half of 2023 is forecast to be 84% oil and NGLs (50% light oil, 22% heavy oil and 12% NGLs) and 16% natural gas.

The following tables summarizes our 2023 guidance for production and exploration and development expenditures.

	H1/2023 Actual		H2/2023 Guidance		2023 Guidance
Production (boe/d)		88,269		153,000-157,000		120,500-122,500
Exploration and development expenditures ($ millions)	$	404		$601-$641		$1,005-$1,045

We have updated our full-year 2023 cost assumptions to reflect the Ranger acquisition. Operating expense guidance decreased by 13% to reflect the low cash cost structure of the Ranger assets, general and administrative expenses increased by 10% on a boe basis to reflect costs associated with Ranger personnel and interest expense guidance is higher due to the incremental debt associated with the Ranger acquisition and higher interest rates on our credit facilities.

Baytex Energy Corp. Second Quarter Report 2023

The following table summarizes our 2023 guidance for expenses, leasing expenditures and asset retirement obligations.

	2023 Original Guidance ⁽¹⁾		2023 Revised Guidance
Expenses:
Average royalty rate ⁽²⁾		20.0 - 22.0%		21.0 - 22.0%
Operating ⁽³⁾		$14.00 - $14.75/boe		$12.25 - $12.75/boe
Transportation ⁽³⁾		$1.90 - $2.10/boe		$2.00 - $2.10/boe
General and administrative ⁽³⁾		$52 million ($1.63/boe)		$80 million ($1.80/boe)
Interest ⁽³⁾		$65 million ($2.04/boe)		$150 million ($3.38/boe)

Leasing expenditures		$4 million		$13 million
Asset retirement obligations		$25 million		$25 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. Second Quarter Report 2023

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 June 30
	2023									2022
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		14,612			20,710			35,322			15,675			17,332			33,007
Heavy oil		32,821			—			32,821			28,586			—			28,586
Natural Gas Liquids (NGL)		1,434			7,186			8,620			1,818			5,650			7,468
Total liquids (bbl/d)		48,867			27,896			76,763			46,079			22,982			69,061
Natural gas (mcf/d)		42,043			35,946			77,989			53,036			31,133			84,169
Total production (boe/d)		55,874			33,887			89,761			54,919			28,170			83,090

Production Mix
Segment as a percent of total		62	%		38	%		100	%		66	%		34	%		100	%

Light oil and condensate		26	%		61	%		39	%		29	%		62	%		40	%
Heavy oil		59	%		—	%		37	%		52	%		—	%		34	%
NGL		3	%		21	%		10	%		3	%		20	%		9	%
Natural gas		12	%		18	%		14	%		16	%		18	%		17	%

	Six Months Ended June 30
	2023									2022
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		15,500			18,010			33,510			16,619			16,914			33,533
Heavy oil		33,502			—			33,502			26,921			—			26,921
Natural Gas Liquids (NGL)		1,653			6,267			7,920			1,877			5,675			7,552
Total liquids (bbl/d)		50,655			24,277			74,932			45,417			22,589			68,006
Natural gas (mcf/d)		45,562			34,455			80,017			52,443			31,430			83,873
Total production (boe/d)		58,249			30,020			88,269			54,156			27,828			81,985

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

Light oil and condensate		27	%		60	%		38	%		31	%		61	%		41	%
Heavy oil		58	%		—	%		38	%		50	%		—	%		33	%
NGL		3	%		21	%		9	%		3	%		20	%		9	%
Natural gas		12	%		19	%		15	%		16	%		19	%		17	%

Production was 89,761 boe/d for Q2/2023 and 88,269 boe/d for YTD 2023 compared to 83,090 boe/d for Q2/2022 and 81,985 boe/d for YTD 2022. Production for Q2/2023 and YTD 2023 was higher than the same periods of 2022 primarily due to the Merger with Ranger which closed on June 20, 2023 and added approximately 7,500 boe/d to Q2/2023 production and 3,800 boe/d to YTD 2023 production.

Baytex Energy Corp. Second Quarter Report 2023

In Canada, production was 55,874 boe/d for Q2/2023 and 58,249 boe/d for YTD 2023 compared to 54,919 boe/d for Q2/2022 and 54,156 boe/d for YTD 2022. Our successful development program and strong well performance from our Clearwater assets at Peavine resulted in a 955 boe/d increase in production for Q2/2023 and 4,093 boe/d for YTD 2023 relative to the comparative periods of 2022. Production for Q2/2023 reflects the impact of wildfires in northwest Alberta which resulted in temporary shut-ins that reduced production by approximately 4,500 boe/d for Q2/2023.

In the U.S., production was 33,887 boe/d for Q2/2023 and 30,020 boe/d for YTD 2023 compared to 28,170 boe/d for Q2/2022 and 27,828 boe/d for YTD 2022. The increase in production in 2023 relative to 2022 is primarily due to the production contribution from the Merger with Ranger which added approximately 7,500 boe/d to Q2/2023 production and 3,800 boe/d to YTD 2023 production. Production from the acquired Eagle Ford assets is approximately 70% weighted towards high netback light oil and is primarily operated. U.S. results, excluding the Merger with Ranger, for Q2/2023 and YTD 2023 were in line with expectations and reflect reduced development activity on our non-operated Eagle Ford properties.

Total production of 88,269 boe/d for YTD 2023 is consistent with expectations and we expect production of 153,000-157,000 boe/d for the second half of 2023 and 120,500-122,500 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 prices for crude oil were lower during Q2/2023 and YTD 2023 as central banks continue to raise interest rates to combat inflation combined with expectations for slower economic activity and demand for crude oil. As a result, the WTI benchmark price averaged US$73.78/bbl for Q2/2023 and US$74.96/bbl for YTD 2023 compared to Q2/2022 and YTD 2022 when WTI was higher due to uncertainty around global supply caused by Russia's invasion of Ukraine and averaged US$108.41/bbl and US$101.35/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$75.01/bbl during Q2/2023 and US$76.22/bbl during YTD 2023 which is lower than US$112.41/bbl during Q2/2022 and US$104.56/bbl during YTD 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$1.23/bbl and US$1.26/bbl for Q2/2023 and YTD 2023 compared to premiums of US$4.00/bbl and US$3.21/bbl for Q2/2022 and YTD 2022, respectively. The MEH benchmark traded at a lower premium to WTI in both periods of 2023 as a result of reduced refinery demand on the Gulf Coast relative to the same periods of 2022.

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 levels in Western Canada along with North American refinery demand. Canadian oil differentials were wider in 2023 relative to 2022 due to reduced demand caused by planned and unplanned refinery maintenance along with increased supply following record releases from the U.S. Strategic Petroleum Reserve.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $95.13/bbl during Q2/2023 and $97.09/bbl during YTD 2023 compared to $137.79/bbl during Q2/2022 and $126.72/bbl during YTD 2022. Edmonton par traded at a discount to WTI of US$2.95/bbl for Q2/2023 and US$2.91/bbl for YTD 2023 compared to a discount of US$0.47/bbl for Q2/2022 and US$1.68/bbl for YTD 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 Q2/2023 and YTD 2023 averaged $78.85/bbl and $74.16/bbl, respectively, compared to $122.05/bbl and $111.48/bbl for the same periods of 2022. The WCS heavy oil differential was US$15.07/bbl in Q2/2023 and US$19.92/bbl in YTD 2023 compared to discounts of US$12.80/bbl for Q2/2022 and US$13.67/bbl for YTD 2022.

Natural Gas

Reduced demand for North American gas resulted in lower prices relative to 2022 which was impacted by geopolitical factors that caused higher global natural gas prices due to uncertainty of supply to Europe.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$2.10/mmbtu for Q2/2023 and US$2.76/mmbtu for YTD 2023 compared to US$7.17/ mmbtu for Q2/2022 and US$6.06/mmbtu for YTD 2022.

Baytex Energy Corp. Second Quarter Report 2023

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 $2.35/mcf during Q2/2023 and $3.34/mcf during YTD 2023 which is lower than $6.27/mcf for Q2/2022 and $5.43/mcf for YTD 2022.

The following tables compare select benchmark prices and our average realized selling prices for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30									Six Months Ended June 30
	2023			2022			Change			2023			2022			Change
Benchmark Averages
WTI oil (US$/bbl) ⁽¹⁾		73.78			108.41			(34.63	)		74.96			101.35			(26.39	)
MEH oil (US$/bbl) ⁽²⁾		75.01			112.41			(37.40	)		76.22			104.56			(28.34	)
MEH oil differential to WTI (US$/bbl)		1.23			4.00			(2.77	)		1.26			3.21			(1.95	)
Edmonton par oil ($/bbl) ⁽³⁾		95.13			137.79			(42.66	)		97.09			126.72			(29.63	)
Edmonton par oil differential to WTI (US$/bbl)		(2.95	)		(0.47	)		(2.48	)		(2.91	)		(1.68	)		(1.23	)
WCS heavy oil ($/bbl) ⁽⁴⁾		78.85			122.05			(43.20	)		74.16			111.48			(37.32	)
WCS heavy oil differential to WTI (US$/bbl)		(15.07	)		(12.80	)		(2.27	)		(19.92	)		(13.67	)		(6.25	)
AECO natural gas ($/mcf) ⁽⁵⁾		2.35			6.27			(3.92	)		3.34			5.43			(2.09	)
NYMEX natural gas (US$/mmbtu) ⁽⁶⁾		2.10			7.17			(5.07	)		2.76			6.06			(3.30	)
CAD/USD average exchange rate		1.3431			1.2766			0.0665			1.3475			1.2714			0.0761

(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 June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) ⁽¹⁾	$	93.98	$	97.55	$	96.07	$	135.29	$	141.14	$	138.36
Heavy oil, net of blending and other expense ($/bbl) ⁽²⁾		66.45		—		66.45		111.18		—		111.18
NGL ($/bbl) ⁽¹⁾		28.92		25.07		25.71		50.09		48.42		48.83
Natural gas ($/mcf) ⁽¹⁾		2.64		2.52		2.58		7.01		8.99		7.74
Total sales, net of blending and other expense ($/boe) ⁽²⁾	$	66.34	$	67.60	$	66.82	$	104.91	$	106.48	$	105.44

	Six Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) ⁽¹⁾	$	96.74	$	99.96	$	98.47	$	124.05	$	131.77	$	127.95
Heavy oil, net of blending and other expense ($/bbl) ⁽²⁾		58.69		—		58.69		101.01		—		101.01
NGL ($/bbl) ⁽¹⁾		32.86		28.35		29.29		46.43		45.66		45.85
Natural gas ($/mcf) ⁽¹⁾		3.12		3.23		3.17		5.84		7.52		6.47
Total sales, net of blending and other expense ($/boe) ⁽²⁾	$	62.91	$	69.60	$	65.18	$	95.55	$	97.90	$	96.34

(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.

Baytex Energy Corp. Second Quarter Report 2023

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe⁽¹⁾ was $66.82/boe for Q2/2023 and $65.18/bbl for YTD 2023 compared to $105.44/boe for Q2/2022 and $96.34/boe for YTD 2022. In Canada, our realized price of $66.34/boe for Q2/2023 was $38.57/ boe lower than $104.91/boe for Q2/2022. Our realized price in the U.S. was $67.60/boe in Q2/2023 which is $38.88/boe lower than $106.48/boe in Q2/2022. Lower North American benchmark oil prices was the primary factor that resulted in lower realized pricing for our operations in Canada and the U.S. in Q2/2023 and YTD 2023 relative to the same periods 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 $93.98/bbl for Q2/2023 and $96.74/bbl for YTD 2023 compared to $135.29/bbl for Q2/2022 and $124.05/bbl for YTD 2022. The decrease in our realized light oil and condensate price for Q2/2023 and YTD 2023 was primarily a result of lower benchmark prices and represents discounts to the Edmonton par price of $1.15/bbl and $0.35/bbl for Q2/2023 and YTD 2023, respectively, which are narrower than discounts of $2.50/bbl in Q2/2022 and $2.67/bbl in YTD 2022 due to strong realized pricing for our Viking light oil production in Saskatchewan.

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 $97.55/bbl for Q2/2023 and $99.96/bbl for YTD 2023 compared to $141.14/bbl for Q2/2022 and $131.77/bbl for YTD 2022. Expressed in U.S. dollars, our realized light oil and condensate price of US$72.63/bbl for Q2/2023 and US$74.18/bbl for YTD 2023 represents discounts to MEH of US$2.38/bbl and US$2.04/bbl for Q2/2023 and YTD 2023, respectively, compared to discounts of US$1.85/bbl for Q2/2022 and US$0.92/bbl for YTD 2022.

Our realized heavy oil price, net of blending and other expense⁽¹⁾ averaged $66.45/bbl in Q2/2023 and $58.69/bbl in YTD 2023 compared to $111.18/bbl in Q2/2022 and $101.01/bbl in YTD 2022. Our realized heavy oil, net of blending and other expense for Q2/2023 and YTD 2023 was $44.73/bbl and $42.32/bbl lower relative to Q2/2022 and YTD 2022, respectively, compared with a $43.20/bbl and $37.32/bbl decrease in the WCS benchmark price over the same periods. Our realized price decreased more than the benchmark price due to higher per unit blending costs relative to the WCS benchmark in both periods of 2023 compared to same periods of 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 $25.71/bbl in Q2/2023 or 26% of WTI (expressed in Canadian dollars) and $29.29/bbl in YTD 2023 or 29% of WTI (expressed in Canadian dollars) compared to $48.83/ bbl or 35% of WTI (expressed in Canadian dollars) in Q2/2022 and $45.85/bbl or 36% of WTI (expressed in Canadian dollars) in YTD 2022. Our realized NGL price in Canada and the U.S. was lower as a percentage of WTI in Q2/2023 and YTD 2023 due to lower demand for NGL products relative to the same periods of 2022.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. A portion of our natural gas sales in Canada and the U.S. are based on the respective daily index prices which fluctuate independently from the associated monthly index prices. Our realized natural gas price⁽²⁾ in Canada was $2.64/mcf for Q2/2023 and $3.12/mcf for YTD 2023 compared to $7.01/mcf in Q2/2022 and $5.84/mcf for YTD 2022. In the U.S., our realized natural gas price was US$1.88/mcf for Q2/2023 and US$2.40/mcf for YTD 2023 compared to US$7.04/mcf for Q2/2022 and US$5.91/mcf for YTD 2022. The decrease in our realized gas price in Canada and the U.S. is relatively consistent with the decreases in the AECO monthly and NYMEX monthly benchmark prices in 2023 compared to the same periods of 2022.

(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. Second Quarter Report 2023

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended June 30
	2023								2022
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	124,965		$	183,845	$	308,810		$	192,986		$	222,606	$	415,592
Heavy oil		251,449			—		251,449			346,101			—		346,101
NGL		3,772			16,391		20,163			8,288			24,895		33,183
Total oil sales		380,186			200,236		580,422			547,375			247,501		794,876
Natural gas sales		10,106			8,232		18,338			33,822			25,471		59,293
Total petroleum and natural gas sales		390,292			208,468		598,760			581,197			272,972		854,169
Blending and other expense		(52,995	)		—		(52,995	)		(56,895	)		—		(56,895	)
Total sales, net of blending and other
expense ⁽¹⁾	$	337,297		$	208,468	$	545,765		$	524,302		$	272,972	$	797,274

	Six Months Ended June 30
	2023								2022
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	271,420		$	325,855	$	597,275		$	373,141		$	403,426	$	776,567
Heavy oil		468,534			—		468,534			590,539			—		590,539
NGL		9,832			32,165		41,997			15,772			46,902		62,674
Total oil sales		749,786			358,020		1,107,806			979,452			450,328		1,429,780
Natural gas sales		26,128			20,162		46,290			55,449			42,765		98,214
Total petroleum and natural gas sales		775,914			378,182		1,154,096			1,034,901			493,093		1,527,994
Blending and other expense		(112,676	)		—		(112,676	)		(98,335	)		—		(98,335	)
Total sales, net of blending and other
expense ⁽¹⁾	$	663,238		$	378,182	$	1,041,420		$	936,566		$	493,093	$	1,429,659

(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 $545.8 million for Q2/2023 decreased $251.5 million from $797.3 million reported for Q2/2022 while total sales, net of blending and other expense, of $1.0 billion for YTD 2023 decreased $388.2 million from $1.4 billion reported for YTD 2022. The decrease in total sales in both periods of 2023 relative to the same periods of 2022 reflects lower benchmark prices which more than offset the increase in production from our successful development programs along with the contribution of the Ranger assets.

In Canada, total sales, net of blending and other expense, was $337.3 million for Q2/2023 which is a decrease of $187.0 million from $524.3 million reported for Q2/2022. The decrease in total petroleum and natural gas sales was the result of lower realized pricing for Q2/2023 relative to Q2/2022 which resulted in a $196.1 million decrease in total sales, net of blending and other expense while higher production resulted in a $9.1 million increase in total sales, net of blending and other expense, relative to Q2/2022. Lower benchmark prices was the primary factor contributing to our total sales, net of blending and other expense, decreasing to $663.2 million in YTD 2023 from $936.6 million in YTD 2022.

In the U.S., petroleum and natural gas sales were $208.5 million for Q2/2023 which is a decrease of $64.5 million from $273.0 million reported for Q2/2022. Higher production in Q2/2023 relative to Q2/2022 contributed to a $55.4 million increase in total sales which was more than offset by lower realized pricing which resulted in a $119.9 million decrease in total sales for Q2/2023 relative to Q2/2022. The decrease in realized pricing in YTD 2023 resulted in petroleum and natural gas sales of $378.2 million for YTD 2023 compared to $493.1 million in YTD 2022 despite higher production in YTD 2023 relative to YTD 2022.

Baytex Energy Corp. Second Quarter Report 2023

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 six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	47,309		$	60,611		$	107,920		$	91,133		$	80,426		$	171,559
Average royalty rate ⁽¹⁾⁽²⁾		14.0	%		29.1	%		19.8	%		17.4	%		29.5	%		21.5	%
Royalties per boe ⁽³⁾	$	9.30		$	19.66		$	13.21		$	18.24		$	31.37		$	22.69

	Six Months Ended June 30
	2023									2022
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	91,164		$	110,009		$	201,173		$	148,809		$	145,470		$	294,279
Average royalty rate ⁽¹⁾⁽²⁾		13.7	%		29.1	%		19.3	%		15.9	%		29.5	%		20.6	%
Royalties per boe ⁽³⁾	$	8.65		$	20.25		$	12.59		$	15.18		$	28.88		$	19.83

(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 Q2/2023 were $107.9 million or 19.8% of total sales, net of blending and other expense, compared to $171.6 million or 21.5% for Q2/2022. Total royalties for YTD 2023 were $201.2 million or 19.3% of total sales, net of blending and other expense, compared to $294.3 million or 20.6% for YTD 2022. The decrease in total royalties in both periods of 2023 is primarily a result of lower benchmark prices along with a lower royalty rate on our Canadian production relative to the same periods of 2022. Our royalty rates of 19.8% for Q2/2023 and 19.3% for YTD 2023 were lower than 21.5% for Q2/2022 and 20.6% for YTD 2022.

Our Canadian royalty rates of 14.0% for Q2/2023 and 13.7% for YTD 2023 were lower than 17.4% for Q2/2022 and 15.9% for YTD 2022 due to lower benchmark commodity prices which resulted in a lower royalty rate on our Canadian properties in 2023 relative to 2022. In the U.S., royalties averaged 29.1% of total sales for Q2/2023 and YTD 2023 respectively, which is slightly lower than 29.5% for Q2/2022 and YTD 2022 due to the production contributed by the acquired Ranger assets which has a lower royalty rate relative to our legacy non-operated Eagle Ford assets.

Our average royalty rate of 19.3% for YTD 2023 is consistent with expectations and we have updated our annual guidance to 21.0 - 22.0% for 2023 which reflects the royalty rate on the properties acquired from Ranger which has a higher royalty rate than our corporate average.

OPERATING EXPENSE

	Three Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	91,354	$	28,084	$	119,438	$	82,471	$	24,955	$	107,426
Operating expense per boe ⁽¹⁾	$	17.97	$	9.11	$	14.62	$	16.50	$	9.73	$	14.21

	Six Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	182,534	$	49,312	$	231,846	$	161,011	$	47,181	$	208,192
Operating expense per boe ⁽¹⁾	$	17.31	$	9.08	$	14.51	$	16.43	$	9.37	$	14.03

(1)

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

Baytex Energy Corp. Second Quarter Report 2023

Total operating expense was $119.4 million ($14.62/boe) for Q2/2023 and $231.8 million ($14.51/boe) for YTD 2023 compared to $107.4 million ($14.21/boe) for Q2/2022 and $208.2 million ($14.03/boe) for YTD 2022. Operating expense for both periods of 2023 increased in total and per boe reflecting increased production and cost inflation throughout our operations in 2023 relative to 2022.

In Canada, operating expense was $91.4 million ($17.97/boe) for Q2/2023 and $182.5 million ($17.31/boe) for YTD 2023 compared to $82.5 million ($16.50/boe) for Q2/2022 and $161.0 million ($16.43/boe) for YTD 2022. Total operating expenses were higher in Canada as a result of higher production along with slightly higher per boe costs due to inflation.

U.S. operating expense was $28.1 million ($9.11/boe) for Q2/2023 and $49.3 million ($9.08/boe) for YTD 2023 compared to $25.0 million ($9.73/boe) for Q2/2022 and $47.2 million ($9.37/boe) in YTD 2022. Our U.S. operating expenses expressed in U.S. dollars, per unit operating expense was US$6.78/boe in Q2/2023 and US$6.74/boe in YTD 2023 which was lower than US$7.62/ boe for Q2/2022 and US$7.37/boe in YTD 2022 as a result of lower workover activity in 2023.

Operating expense of $14.51 for YTD 2023 is consistent with expectations and we have updated our annual guidance range to $12.25 - $12.75/boe for 2023 which reflects the lower operating cost structure of the Ranger assets.

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. Transportation expense in our U.S. operations is primarily the costs incurred to deliver our production via truck or pipeline to a centralized sales point.

The following table compares our transportation expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	13,240	$	1,334	$	14,574	$	11,758	$	—	$	11,758
Transportation expense per boe ⁽¹⁾	$	2.60	$	0.43	$	1.78	$	2.35	$	—	$	1.56

	Six Months Ended June 30
	2023						2022
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	30,245	$	1,334	$	31,579	$	20,973	$	—	$	20,973
Transportation expense per boe ⁽¹⁾	$	2.87	$	0.25	$	1.98	$	2.14	$	—	$	1.41

(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 $14.6 million ($1.78/boe) for Q2/2023 and $31.6 million ($1.98/boe) for YTD 2023 compared to $11.8 million ($1.56/boe) for Q2/2022 and $21.0 million ($1.41/boe) for YTD 2022. In Canada, total transportation expense and per unit costs are higher in Q2/2023 and YTD 2023 as a result of additional heavy oil production along with higher trucking rates relative to the same periods of 2022. Transportation expense in the U.S. is consistent with expectations for Q2/2023 and YTD 2023 and reflects trucking and pipeline transportation costs on our Eagle Ford operations acquired from Ranger. Per unit transportation expense of $1.98/boe for YTD 2023 is consistent with expectations and we have updated our annual guidance range to $2.00 - $2.10/boe to reflect the incremental transportation costs associated with the properties acquired from Ranger.

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 $53.0 million for Q2/2023 and $112.7 million for YTD 2023 compared to $56.9 million for Q2/2022 and $98.3 million for YTD 2022. The increase in blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in YTD 2023 relative to YTD 2022, while Q2/2023 was consistent with Q2/2022 due to curtailed heavy oil production from the wildfires in Alberta.

Baytex Energy Corp. Second Quarter Report 2023

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 revenue. 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 six months ended June 30, 2023 and 2022.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2023			2022			Change			2023			2022			Change
Realized financial derivatives gain (loss)
Crude oil	$	16,363		$	(112,071	)	$	128,434		$	21,778		$	(191,597	)	$	213,375
Natural gas		2			(11,971	)		11,973			2			(16,811	)		16,813
Total	$	16,365		$	(124,042	)	$	140,407		$	21,780		$	(208,408	)	$	230,188
Unrealized financial derivatives gain (loss)
Crude oil	$	(17,124	)	$	47,816		$	(64,940	)	$	(7,914	)	$	(91,502	)	$	83,588
Natural gas		(2,279	)		9,363			(11,642	)		(2,279	)		(7,271	)		4,992
Equity total return swap ("Equity TRS")		—			1,589			(1,589	)		—			1,280			(1,280	)
Total	$	(19,403	)	$	58,768		$	(78,171	)	$	(10,193	)	$	(97,493	)	$	87,300
Total financial derivatives gain (loss)
Crude oil	$	(761	)	$	(64,255	)	$	63,494		$	13,864		$	(283,099	)	$	296,963
Natural gas		(2,277	)		(2,608	)		331			(2,277	)		(24,082	)		21,805
Equity TRS		—			1,589			(1,589	)		—			1,280			(1,280	)
Total	$	(3,038	)	$	(65,274	)	$	62,236		$	11,587		$	(305,901	)	$	317,488

We recorded a total financial derivative loss of $3.0 million for Q2/2023 and a gain of $11.6 million for YTD 2023 compared to a loss of $65.3 million for Q2/2022 and $305.9 million for YTD 2022. The realized financial derivatives gain of $16.4 million for Q2/2023 and $21.8 million for YTD 2023 were primarily a result of the market prices for crude oil and natural gas settling at levels below those set in our derivative contracts. The unrealized loss of $19.4 million for Q2/2023 and $10.2 million for YTD 2023 reflect changes in forecasted crude oil pricing used to revalue the unsettled notional volume outstanding on our crude oil contracts in place at June 30, 2023 relative to March 31, 2023 and December 31, 2022. The fair value of our financial derivative contracts resulted in a net asset of $24.6 million at June 30, 2023 compared to a net asset of $19.3 million at March 31, 2023 and a net liability of $10.1 million at December 31, 2022.

Baytex Energy Corp. Second Quarter Report 2023

We had the following commodity financial derivative contracts as at July 27, 2023.

	Period	Volume	Price/Unit ⁽¹⁾	Index
Oil
Basis differential ⁽²⁾	July 2023 to Dec 2023	1,500 bbl/d	WTI less US$2.50/bbl	MSW
Basis differential ⁽²⁾⁽³⁾	Jan 2024 to Dec 2024	1,500 bbl/d	WTI less US$2.65/bbl	MSW
Basis differential ⁽²⁾	July 2023 to Dec 2023	2,000 bbl/d	WTI less US$14.98/bbl	WCS
Basis differential ⁽²⁾	Aug 2023 to Dec 2023	6,000 bbl/d	WTI less US$13.62/bbl	WCS
			Baytex pays: WCS differential at Hardisty
			Baytex receives: WCS differential at Houston less
Basis differential ⁽²⁾	July 2023 to Dec 2023	5,000 bbl/d	US$8.10/bbl	WCS
			Baytex pays: WCS differential at Hardisty
			Baytex receives: WCS differential at Houston less
Basis differential ⁽²⁾	Jan 2024 to Jun 2024	4,000 bbl/d	US$8.10/bbl	WCS
Put option	July 2023 to Dec 2023	5,000 bbl/d	US$60.00	WTI
Collar	July 2023 to Dec 2023	15,500 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2023 to Sep 2023	19,862 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2023 to Dec 2023	15,089 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Mar 2024	8,400 bbl/d	US$60.00/US$100.00	WTI
Collar	Apr 2024 to Jun 2024	1,750 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Jun 2024	14,500 bbl/d	US$60.00/US$100.00	WTI
Collar ⁽³⁾	Jan 2024 to Jun 2024	2,500 bbl/d	US$60.00/US$90.00	WTI

Natural Gas
				HSC
			Baytex pays: NYMEX	IFERC
Basis differential ⁽²⁾	July 2023 to Dec 2023	11,413 mmbtu/d	Baytex receives: HSC less US$0.1525/mmbtu	FOM
Fixed Sell	Oct 2023 to Mar 2024	3,500 mmbtu/d	US$3.5025/mmbtu	NYMEX
Collar	July 2023 to Dec 2023	11,413 mmbtu/d	US$2.50/US$2.68	NYMEX
Collar	Jan 2024 to Mar 2024	11,538 mmbtu/d	US$2.50/US$3.65	NYMEX
Collar	Apr 2024 to Jun 2024	11,538 mmbtu/d	US$2.33/US$3.00	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.06	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.09	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.10	NYMEX
Collar	Jan 2024 to Dec 2024	8,500 mmbtu/d	US$3.00/US$4.15	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.19	NYMEX

Natural Gas Liquids
				Mt. Belvieu
				Non-TET
Fixed Sell	Jul 2023 to Mar 2024	34,364 gallon/d	US$0.2280/gallon	Ethane

(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)

Contract entered subsequent to June 30, 2023.

Baytex Energy Corp. Second Quarter Report 2023

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 six months ended June 30, 2023 and 2022.

	Three Months Ended June 30
	2023									2022
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		55,874			33,887			89,761			54,919			28,170			83,090
Operating netback:
Total sales, net of blending and other expense ⁽¹⁾	$	66.34		$	67.60		$	66.82		$	104.91		$	106.48		$	105.44
Less:
Royalties ⁽²⁾		(9.30	)		(19.66	)		(13.21	)		(18.24	)		(31.37	)		(22.69	)
Operating expense ⁽²⁾		(17.97	)		(9.11	)		(14.62	)		(16.50	)		(9.73	)		(14.21	)
Transportation expense ⁽²⁾		(2.60	)		(0.43	)		(1.78	)		(2.35	)		—			(1.56	)
Operating netback ⁽¹⁾	$	36.47		$	38.40		$	37.21		$	67.82		$	65.38		$	66.98
Realized financial derivatives gain (loss) ⁽³⁾		—			—			2.00			—			—			(16.41	)
Operating netback after financial derivatives ⁽¹⁾	$	36.47		$	38.40		$	39.21		$	67.82		$	65.38		$	50.57

	Six Months Ended June 30
	2023									2022
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		58,249			30,020			88,269			54,156			27,828			81,985
Operating netback:
Total sales, net of blending and other expense ⁽¹⁾	$	62.91		$	69.60		$	65.18		$	95.55		$	97.90		$	96.34
Less:
Royalties ⁽²⁾		(8.65	)		(20.25	)		(12.59	)		(15.18	)		(28.88	)		(19.83	)
Operating expense ⁽²⁾		(17.31	)		(9.08	)		(14.51	)		(16.43	)		(9.37	)		(14.03	)
Transportation expense ⁽²⁾		(2.87	)		(0.25	)		(1.98	)		(2.14	)		—			(1.41	)
Operating netback ⁽¹⁾	$	34.08		$	40.02		$	36.10		$	61.80		$	59.65		$	61.07
Realized financial derivatives gain (loss) ⁽³⁾		—			—			1.36			—			—			(14.04	)
Operating netback after financial derivatives ⁽¹⁾	$	34.08		$	40.02		$	37.46		$	61.80		$	59.65		$	47.03

	(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.

Our operating netback was $37.21/boe for Q2/2023 and $36.10/boe for YTD 2023 compared to $66.98/boe for Q2/2022 and $61.07/boe for YTD 2022 due to lower benchmark pricing in Canada and the U.S. which resulted in a decrease in per unit sales net of royalties. Total operating and transportation expense of $16.40/boe for Q2/2023 and $16.49/boe for YTD 2023 were higher than $15.77/boe for Q2/2022 and $15.44/boe for YTD 2022 due to inflation which resulted in higher per boe operating and transportation costs. Operating netback including realized gains (losses) on financial derivatives was $39.21/boe for Q2/2023 and $37.46/boe for YTD 2023 compared to $50.57/boe for Q2/2022 and $47.03/boe for YTD 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.

Baytex Energy Corp. Second Quarter Report 2023

The following table summarizes our G&A expense for the three and six months ended June 30, 2023 and 2022.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands except for per boe)	2023			2022			Change			2023			2022			Change
Gross general and administrative expense	$	16,476		$	12,223		$	4,253		$	30,893		$	25,729		$	5,164
Overhead recoveries		(1,236	)		(583	)		(653	)		(3,919	)		(2,407	)		(1,512	)
General and administrative expense	$	15,240		$	11,640		$	3,600		$	26,974		$	23,322		$	3,652
General and administrative expense per boe ⁽¹⁾	$	1.87		$	1.54		$	0.33		$	1.69		$	1.57		$	0.12

(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 $15.2 million ($1.87/boe) for Q2/2023 and $27.0 million ($1.69/boe) for YTD 2023 compared to $11.6 million ($1.54/boe) for Q2/2022 and $23.3 million ($1.57/boe) for YTD 2022. G&A expense for Q2/2023 and YTD 2023 is consistent with expectations and was higher than the comparative periods of 2022 due to the increase in staffing levels and integration costs associated with the Merger with Ranger. G&A expense of $1.69/boe during YTD 2023 is consistent with expectations and our annual guidance of $80 million ($1.80/boe) reflects the additional staffing levels and administrative costs associated with the Merger with Ranger.

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 accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, 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 six months ended June 30, 2023 and 2022.

	Three Months Ended June 30							Six Months Ended June 30
($ thousands except for per boe)	2023		2022		Change			2023		2022		Change
Interest on credit facilities	$	7,535	$	4,070	$	3,465		$	13,751	$	7,109	$	6,642
Interest on long-term notes		20,565		16,356		4,209			32,659		33,700		(1,041	)
Interest on lease obligations		155		48		107		$	220	$	92		128
Cash interest	$	28,255	$	20,474	$	7,781		$	46,630	$	40,901	$	5,729
Accretion of debt issue costs		1,847		2,734		(887	)		2,371		3,429		(1,058	)
Accretion of asset retirement obligations		4,395		3,869		526			9,221		6,991		2,230
Financing and interest expense	$	34,497	$	27,077	$	7,420		$	58,222	$	51,321	$	6,901
Cash interest per boe ⁽¹⁾	$	3.46	$	2.71	$	0.75		$	2.92	$	2.76	$	0.16
Financing and interest expense per boe ⁽¹⁾	$	4.22	$	3.58	$	0.64		$	3.64	$	3.46	$	0.18

(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 $34.5 million ($4.22/boe) for Q2/2023 and $58.2 million ($3.64/boe) for YTD 2023 compared to $27.1 million ($3.58/boe) for Q2/2022 and $51.3 million ($3.46/boe) for YTD 2022. Higher interest costs in 2023 relative to 2022 reflects the additional debt outstanding as a result of the Merger with Ranger in addition to an increase in interest rates.

Cash interest was $28.3 million ($3.46/boe) for Q2/2023 and $46.6 million ($2.92/boe) for YTD 2023 compared to $20.5 million ($2.71/boe) for Q2/2022 and $40.9 million ($2.76/boe) for YTD 2022. Cash interest was higher in both periods of 2023 relative to the same periods of 2022 which reflects the additional debt outstanding due to the Merger with Ranger including the issuance of US$800.0 million aggregate principal amount of long-term notes. Interest on our credit facilities in Q2/2023 and YTD 2023 was higher than the same periods of 2022 primarily due to the increase in benchmark borrowing rate along with an increase in the principal amounts outstanding. The weighted average interest rate applicable to our credit facilities was 6.8% for Q2/2023 and 6.5% for YTD 2023 which is higher than 2.6% for both Q2/2022 and YTD 2022.

Accretion of asset retirement obligations of $4.4 million for Q2/2023 and $9.2 million for YTD 2023 was higher than $3.9 million for Q2/2022 and $7.0 million for YTD 2022 due to a higher discount rate used in both periods of 2023. Accretion of debt issue costs was lower in both periods of 2023 relative to the comparative periods of 2022 due to lower debt issue costs outstanding for the majority of YTD 2023.

We have updated our cash interest annual guidance for 2023 to $150 million ($3.38/boe) which reflects the incremental debt associated with the Merger with Ranger in addition to higher interest rates on our credit facilities.

Baytex Energy Corp. Second Quarter Report 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 $0.4 million for Q2/2023 and $0.5 million for YTD 2023 compared to $7.2 million for Q2/2022 and $10.8 million for YTD 2022.

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 six months ended June 30, 2023 and 2022.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2023		2022		Change		2023		2022		Change
Depletion	$	174,473	$	140,809	$	33,664	$	338,908	$	280,255	$	58,653
Depreciation		1,671		1,477		194		3,235		2,822		413
Depletion and depreciation	$	176,144	$	142,286	$	33,858	$	342,143	$	283,077	$	59,066
Depletion and depreciation per boe ⁽¹⁾	$	21.56	$	18.82	$	2.74	$	21.42	$	19.08	$	2.34

(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 $176.1 million ($21.56/boe) for Q2/2023 and $342.1 million ($21.42/boe) for YTD 2023 compared to $142.3 million ($18.82/boe) for Q2/2022 and $283.1 million ($19.08/boe) for YTD 2022. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q2/2023 and YTD 2023 relative to Q2/2022 and YTD 2022 as a result of the $245.2 million impairment reversal that was recorded at December 31, 2022 and an increase in future development costs attributed to proved plus probable reserves which resulted in a higher depletable base for our oil and gas properties in 2023. Depletion expense for Q2/2023 and YTD 2023 also includes depletion on the oil and gas properties acquired from Ranger subsequent to closing on June 20, 2023.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at June 30, 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 along with the share based compensation plan assumed from Ranger in June 2023. 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 $16.9 million for Q2/2023 and $26.7 million for YTD 2023 compared to $2.9 million for Q2/2022 and $6.9 million for YTD 2022. SBC expense for Q2/2023 and YTD 2023 includes $16.2 million of non-cash expense related to awards assumed and settled in Baytex common shares in conjunction with the Merger with Ranger. Regular expensing of compensation awards is considered a cash expense as we intend to settle currently outstanding and future awards in cash while Baytex is repurchasing shares as part of its shareholder return program.

Baytex Energy Corp. Second Quarter Report 2023

Cash SBC expense of $0.7 million for Q2/2023 reflects a decline in our share price at June 30, 2023 compared to March 31, 2023 which resulted in lower cash SBC expense compared to $2.6 million for Q2/2022 when we had a higher notional amount outstanding under the equity total return swaps. 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. Cash SBC expense of $10.5 million for YTD 2023 was higher than $4.8 million for YTD 2022 as we applied a 1.5x performance factor for 2022 results to performance awards during Q1/2023.

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 June 30								Six Months Ended June 30
($ thousands except for exchange rates)	2023			2022		Change			2023			2022		Change
Unrealized foreign exchange (gain) loss	$	(12,880	)	$	27,499	$	(40,379	)	$	(13,093	)	$	12,951	$	(26,044	)
Realized foreign exchange loss		941			210		731			1,091			413		678
Foreign exchange (gain) loss	$	(11,939	)	$	27,709	$	(39,648	)	$	(12,002	)	$	13,364	$	(25,366	)
CAD/USD exchange rates:
At beginning of period		1.3528			1.2484					1.3534			1.2656
At end of period		1.3238			1.2872					1.3238			1.2872

We recorded a foreign exchange gain of $11.9 million for Q2/2023 and $12.0 million for YTD 2023 compared to a loss of $27.7 million for Q2/2022 and $13.4 million for YTD 2022.

The unrealized foreign exchange gain of $12.9 million for Q2/2023 and $13.1 million for YTD 2023 is related to changes in the reported amount of our long-term notes and credit facilities due to a strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and December 31, 2022. A weakening of the Canadian dollar relative to the U.S. dollar resulted in an unrealized foreign exchange loss for Q2/2022 and YTD 2022 related to changes in the reported amount of our long-term notes outstanding at June 30, 2022 compared to March 31, 2022 and 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 $0.9 million for Q2/2023 and $1.1 million for YTD 2023 compared to a loss of $0.2 million for Q2/2022 and $0.4 million for YTD 2022.

INCOME TAXES

	Three Months Ended June 30								Six Months Ended June 30
($ thousands)	2023			2022		Change			2023			2022			Change
Current income tax expense	$	1,350		$	1,140	$	210		$	2,470		$	2,050		$	420
Deferred income tax (recovery) expense		(178,360	)		39,920		(218,280	)		(162,837	)		(27,412	)		(135,425	)
Total income tax (recovery) expense	$	(177,010	)	$	41,060	$	(218,070	)	$	(160,367	)	$	(25,362	)	$	(135,005	)

Current income tax expense was $1.4 million for Q2/2023 and $2.5 million for YTD 2023 compared to $1.1 million for Q2/2022 and $2.1 million for YTD 2022.

We recorded deferred tax recovery of $178.4 million for Q2/2023 and $162.8 million for YTD 2023 compared to expense of $39.9 million for Q2/2022 and a recovery $27.4 million for YTD 2022. The deferred tax recovery in Q2/2023 and YTD 2023 is primarily related to the effects of the transaction restructuring for the Ranger acquisition in Q2/2023 partially offset by income generated on our Canadian and U.S. operations for the period.

As disclosed in the 2022 annual financial statements, certain indirect subsidiaries received reassessments from the Canada Revenue Agency (the "CRA”) in June 2016 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. In mid-July 2023 we received a letter from the Appeals Division of the CRA proposing to confirm the reassessments. We remain confident that our original tax filings are correct and intend to defend these tax filings through the appeals process.

Baytex Energy Corp. Second Quarter Report 2023

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income or loss for the three and six months ended June 30, 2023 and 2022 are set forth in the following table.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2023			2022			Change			2023			2022			Change
Petroleum and natural gas sales	$	598,760		$	854,169		$	(255,409	)	$	1,154,096		$	1,527,994		$	(373,898	)
Royalties		(107,920	)		(171,559	)		63,639			(201,173	)		(294,279	)		93,106
Revenue, net of royalties		490,840			682,610			(191,770	)		952,923			1,233,715			(280,792	)

Expenses
Operating		(119,438	)		(107,426	)		(12,012	)		(231,846	)		(208,192	)		(23,654	)
Transportation		(14,574	)		(11,758	)		(2,816	)		(31,579	)		(20,973	)		(10,606	)
Blending and other		(52,995	)		(56,895	)		3,900			(112,676	)		(98,335	)		(14,341	)
Operating netback ⁽¹⁾	$	303,833		$	506,531		$	(202,698	)	$	576,822		$	906,215		$	(329,393	)
General and administrative		(15,240	)		(11,640	)		(3,600	)		(26,974	)		(23,322	)		(3,652	)
Cash interest		(28,255	)		(20,474	)		(7,781	)		(46,630	)		(40,901	)		(5,729	)
Realized financial derivatives loss (gain)		16,365			(124,042	)		140,407			21,780			(208,408	)		230,188
Realized foreign exchange loss		(941	)		(210	)		(731	)		(1,091	)		(413	)		(678	)
Other expense		(141	)		(751	)		610			(354	)		(1,001	)		647
Current income tax expense		(1,350	)		(1,140	)		(210	)		(2,470	)		(2,050	)		(420	)
Cash share-based compensation		(681	)		(2,570	)		1,889			(10,504	)		(4,809	)		(5,695	)
Adjusted funds flow ⁽²⁾	$	273,590		$	345,704		$	(72,114	)	$	510,579		$	625,311		$	(114,732	)
Transaction costs		(32,832	)		—			(32,832	)		(41,703	)		—			(41,703	)
Exploration and evaluation		(369	)		(7,210	)		6,841			(532	)		(10,780	)		10,248
Depletion and depreciation		(176,144	)		(142,286	)		(33,858	)		(342,143	)		(283,077	)		(59,066	)
Non-cash share-based compensation		(16,237	)		(372	)		(15,865	)		(16,237	)		(2,078	)		(14,159	)
Non-cash financing and accretion		(6,242	)		(6,603	)		361			(11,592	)		(10,420	)		(1,172	)
Non-cash other income		—			183			(183	)		1,271			1,465			(194	)
Unrealized financial derivatives (loss) gain		(19,403	)		58,768			(78,171	)		(10,193	)		(97,493	)		87,300
Unrealized foreign exchange gain (loss)		12,880			(27,499	)		40,379			13,093			(12,951	)		26,044
Gain (loss) on dispositions		—			207			(207	)		(336	)		441			(777	)
Deferred income tax recovery (expense)		178,360			(39,920	)		218,280			162,837			27,412			135,425
Net income for the period	$	213,603		$	180,972		$	32,631		$	265,044		$	237,830		$	27,214

	(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 $273.6 million for Q2/2023 and $510.6 million for YTD 2023 compared to $345.7 million for Q2/2022 and $625.3 million for YTD 2022. The decrease in adjusted funds flow was primarily due to lower operating netback which was $202.7 million lower in Q2/2023 and $329.4 million lower in YTD 2023 relative to the same periods of 2022 as a result of lower commodity prices that resulted in decreased revenue, net of royalties. The decrease in operating netback was partially offset by realized gains on financial derivatives of $16.4 million for Q2/2023 and $21.8 million for YTD 2023 which increased $140.4 million and $230.2 million relative to Q2/2022 and YTD 2022, respectively, when we recorded realized losses. We reported net income of $213.6 million for Q2/2023 and $265.0 million for YTD 2023 compared to net income of $181.0 million reported for Q2/2022 and $237.8 million for YTD 2022.

Baytex Energy Corp. Second Quarter Report 2023

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 $46.5 million for Q2/2023 and $47.0 million for YTD 2023 relates to the change in value of our U.S. net assets and is due to the strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2023 compared to March 31, 2023 and December 31, 2022. The CAD/USD exchange rate was 1.3238 CAD/ USD as at June 30, 2023 compared to 1.3528 CAD/USD at March 31, 2023 and 1.3534 CAD/USD at December 31, 2022.

CAPITAL EXPENDITURES

Capital expenditures for the three and six months ended June 30, 2023 and 2022 are summarized as follows.

	Three Months Ended June 30
	2023								2022
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Drilling, completion and equipping	$	77,518		$	69,309	$	146,827		$	37,265		$	43,167	$	80,432
Facilities		11,324			857		12,181			6,912			1,414		8,326
Land, seismic and other		7,561			4,135		11,696			7,704			171		7,875
Exploration and development expenditures	$	96,403		$	74,301	$	170,704		$	51,881		$	44,752	$	96,633
Property acquisitions	$	(62	)	$	—	$	(62	)	$	208		$	—	$	208
Proceeds from dispositions	$	(50	)	$	—	$	(50	)	$	(14	)			$	(14	)

	Six Months Ended June 30
	2023								2022
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Drilling, completion and equipping	$	232,471		$	118,145	$	350,616		$	144,263		$	70,305	$	214,568
Facilities		28,309			857		29,166			14,678			1,800		16,478
Land, seismic and other		20,229			4,319		24,548			19,070			339		19,409
Exploration and development expenditures	$	281,009		$	123,321	$	404,330		$	178,011		$	72,444	$	250,455
Property acquisitions	$	444		$	—	$	444		$	267		$	—	$	267
Proceeds from dispositions	$	(285	)	$	—	$	(285	)	$	(41	)	$	—	$	(41	)

Exploration and development expenditures were $170.7 million for Q2/2023 and $404.3 million for YTD 2023 compared to $96.6 million for Q2/2022 and $250.5 million for YTD 2022. Exploration and development expenditures for Q2/2023 and YTD 2023 reflect increased development activity along with inflationary pressures that resulted in higher costs related to the same periods of 2022 and expenditures for development activity that occurred on the properties acquired from Ranger after the acquisition closed on June 20, 2023.

In Canada, exploration and development expenditures were $96.4 million in Q2/2023 and $281.0 million in YTD 2023 compared to $51.9 million in Q2/2022 and $178.0 million in YTD 2022. Drilling and completion spending of $77.5 million in Q2/2023 and $232.5 million in YTD 2023 reflects higher light and heavy oil development activity relative to Q2/2022 and YTD 2022 when we spent $37.3 million and $144.3 million, respectively. We also invested $28.3 million on facilities and $20.2 million on land, seismic and other expenditures during YTD 2023.

Total U.S. exploration and development expenditures were $74.3 million for Q2/2023 and $123.3 million for YTD 2023 compared to $44.8 million in Q2/2022 and $72.4 million during YTD 2022. Exploration and development activity for Q2/2023 and YTD 2023 includes $34.1 million of expenditures for development activity that occurred on the properties acquired from Ranger after the acquisition closed on June 20, 2023 to June 30, 2023. Excluding the Ranger acquisition, exploration and development expenditures in the U.S. were consistent for Q2/2023 and YTD 2023 and reflects slightly higher costs due to inflation along with a weaker Canadian dollar relative to the same periods of 2022.

Our exploration and development expenditures for YTD 2023 are consistent with expectations and we now expect full year expenditures of $1,005-$1,045 million for 2023 which reflects expenditures on our operated Eagle Ford properties acquired from Ranger.

Baytex Energy Corp. Second Quarter Report 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 June 30, 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 us in order to sustain operations and support our long-term plans. At June 30, 2023, net debt⁽¹⁾ was $2.8 billion compared to $987.4 million at December 31, 2022. The increase in net debt is primarily due to $732.8 million of cash consideration paid and the assumption of $1.1 billion of net debt assumed in conjunction with the Merger with Ranger. The cash portion of the transaction was funded with Baytex’s expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. Baytex closed the US$800 million principal amount senior unsecured note offering on April 27, 2023 with the proceeds released from escrow at completion of the Merger.

In June 2023, we renewed our normal course issuer bid ("NCIB") and began repurchasing our common shares in July 2023 as part of our shareholder return framework. Subsequent to Q2/2023 and through to July 26, 2023, we have spent $21.4 million to repurchase and cancel 4.7 million common shares. On July 27, 2023, the Board of Directors has declared a quarterly cash dividend of CDN$0.0225 per share to be paid on October 2, 2023 for shareholders of record on September 15, 2023. These dividends are designated as “eligible dividends” for Canadian income tax purposes. For U.S. income tax purposes, Baytex’s dividends are considered “qualified dividends.”

Credit Facilities

At June 30, 2023, the principal amount of borrowings outstanding under our credit facilities was $986.9 million. Our credit facilities include US$1.1 billion of revolving credit facilities (the "Revolving Facilities") and a US$150 million non-revolving term loan (the "Term Loan") (collectively, the "Credit Facilities").

On June 20, 2023, we amended our Credit Facilities to facilitate the cash consideration paid in conjunction with the Merger and to assume Ranger's net debt. The Revolving Facilities were increased to US$1.1 billion and mature on April 1, 2026. The Revolving Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The Term Loan is secured and matures on June 20, 2025. The amended Credit Facilities contain an additional financial covenant of a maximum Total Debt to Bank EBITDA ratio of 4.0:1.0 and increased the Interest Coverage minimum ratio to 3.5:1.0 (from 2.0:1.0).

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 Revolving 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. Advances under the Term Loan can be drawn in U.S. funds and bear interest at the bank’s secured overnight financing rates ("SOFR") plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.8% for Q2/2023 and 6.5% for YTD 2023 compared to 2.8% and 2.6% for Q2/2022 and YTD 2022, respectively. The interest rate on our Credit Facilities has increased with higher government benchmark rates in 2023 relative to 2022.

As at June 30, 2023, Baytex had $16.8 million of outstanding letters of credit, $15.5 million of which is 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.

(1)

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

Baytex Energy Corp. Second Quarter Report 2023

Financial Covenants

The following table summarizes the financial covenants applicable to the credit facilities and our compliance therewith at June 30, 2023.

	Position as at
Covenant Description	June 30, 2023		Covenant
Senior Secured Debt ⁽¹⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)		0.5:1.0		3.5:1.0
Interest Coverage ⁽³⁾ (Minimum Ratio)		13.3:1.0		3.5:1.0
Total Debt ⁽⁴⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)		1.2:1.0		4:0:1.0

(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 agreement. At June 30, 2023 our Senior Secured Debt was $986.9 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 June 30, 2023 was $2.1 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 expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis. Financing and interest expenses for the twelve months ended June 30, 2023 were $155.8 million.

(4)

"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade and other payables, asset retirement obligations, leases, deferred income tax liabilities, and financial derivative liabilities. At June 30, 2023 our Total Debt was $2.6 billion.

Long-Term Notes

We have two issuances of long-term notes outstanding with a total principal amount of $1.6 billion at June 30, 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 and will be redeemable at par from April 1, 2026 to maturity. At June 30, 2023 there was US$409.8 million aggregate principal amount of the 8.75% Senior Notes outstanding.

On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes were issued at 98.709% of par and are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be redeemable at par from April 30, 2028 to maturity. Net proceeds of $1.0 billion reflects $13.7 million for the original issue discount and Baytex also incurred transaction costs of $18.5 million in conjunction with the issuance.

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 six months ended June 30, 2023, we issued 5.9 million common shares pursuant to our share-based compensation programs and issued 311.4 million common shares on closing of the Merger with Ranger. As at June 30, 2023, we had 862.2 million common shares issued and outstanding and no preferred shares issued and outstanding.

Subsequent to June 30, 2023 and through to July 26, 2023, we repurchased 4.7 million common shares under our NCIB at an average price of $4.59 per share.

Baytex Energy Corp. Second Quarter Report 2023

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 June 30, 2023 and the expected timing for funding these obligations are noted in the table below.

			Less than
($ thousands)	Total		1 year		1-3 years		3-5 years Beyond 5 years
Trade and other payables	$	616,608	$	614,763	$	1,845	$	—	$	—
Financial derivatives		2,907		2,907		—		—		—
Credit facilities – principal ⁽¹⁾		986,903		—		986,903		—		—
Long-term notes – principal ⁽¹⁾		1,601,468		—		—		542,467		1,059,001
Interest on long-term notes ⁽²⁾		793,845		137,481		274,962		215,922		165,480
Lease obligations – principal		42,191		20,297		8,722		7,095		6,077
Processing agreements		5,812		810		1,022		640		3,340
Transportation agreements		256,920		60,462		108,994		66,937		20,527
Total	$	4,306,654	$	836,720	$	1,382,448	$	833,061	$	1,254,425

(1)

Principal amount of instruments.

(2)

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. Second Quarter Report 2023

QUARTERLY FINANCIAL INFORMATION

	2023						2022												2021
($ thousands, except per common share amounts)	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Petroleum and natural gas sales		598,760			555,336			648,986			712,065			854,169			673,825			552,403			488,736
Net income (loss)		213,603			51,441			352,807			264,968			180,972			56,858			563,239			32,713
Per common share – basic		0.37			0.09			0.65			0.48			0.32			0.10			1.00			0.06
Per common share – diluted		0.36			0.09			0.64			0.47			0.32			0.10			0.98			0.06
Adjusted funds flow ⁽¹⁾		273,590			236,989			255,552			284,288			345,704			279,607			214,766			198,397
Per common share – basic		0.47			0.43			0.47			0.51			0.61			0.49			0.38			0.35
Per common share – diluted		0.47			0.43			0.46			0.51			0.60			0.49			0.37			0.35
Free cash flow ⁽²⁾		96,313			(1,918	)		143,324			111,568			245,316			121,318			137,133			101,215
Per common share – basic		0.17			—			0.26			0.20			0.43			0.21			0.24			0.18
Per common share – diluted		0.16			—			0.26			0.20			0.43			0.21			0.24			0.18
Cash flows from operating activities		192,308			184,938			303,441			310,423			360,034			198,974			240,567			178,961
Per common share – basic		0.33			0.34			0.56			0.56			0.63			0.35			0.43			0.32
Per common share – diluted		0.33			0.34			0.55			0.56			0.63			0.35			0.42			0.31
Exploration and development		170,704			233,626			103,634			167,453			96,633			153,822			73,995			94,235
Canada		96,403			184,606			85,641			117,150			51,881			126,130			59,821			75,499
U.S.		74,301			49,020			17,993			50,303			44,752			27,692			14,174			18,736
Property acquisitions		(62	)		506			1,085			—			208			59			1,443			89
Proceeds from dispositions		(50	)		(235	)		(148	)		(25,460	)		(14	)		(27	)		(6,857	)		(701	)
Net debt ⁽¹⁾		2,814,844			995,170			987,446			1,113,559			1,123,297			1,275,680			1,409,717			1,564,658
Total assets ⁽³⁾		8,617,444			5,180,059			5,103,769			4,923,617			4,870,432			4,917,811			4,834,643			4,453,971
Common shares outstanding		862,192			545,553			544,930			547,615			560,139			569,214			564,213			564,213

Daily production
Total production (boe/d)		89,761			86,760			86,864			83,194			83,090			80,867			80,789			79,872
Canada (boe/d)		55,874			60,651			56,946			55,803			54,919			53,385			50,362			48,124
U.S. (boe/d)		33,887			26,109			29,918			27,391			28,170			27,482			30,428			31,748

Benchmark prices
WTI oil (US$/bbl)		73.78			76.13			82.64			91.56			108.41			94.29			77.19			70.56
WCS heavy oil ($/bbl)		78.85			69.44			77.37			93.62			122.05			100.99			78.82			71.81
Edmonton par oil ($/bbl)		95.13			99.04			109.57			116.79			137.79			115.66			93.29			83.78
CAD/USD avg exchange rate		1.3431			1.3520			1.3577			1.3059			1.2766			1.2661			1.2600			1.2601
AECO natural gas ($/mcf)		2.35			4.34			5.58			5.81			6.27			4.59			4.94			3.54
NYMEX natural gas (US$/mmbtu)		2.10			3.42			6.26			8.20			7.17			4.95			5.83			4.01
Total sales, net of blending and other
expense ($/boe) ⁽²⁾		66.82			63.48			74.93			87.68			105.44			86.89			70.42			63.85
Royalties ($/boe) ⁽⁴⁾		(13.21	)		(11.94	)		(15.23	)		(19.21	)		(22.69	)		(16.86	)		(13.47	)		(12.32	)
Operating expense ($/boe) ⁽⁴⁾		(14.62	)		(14.40	)		(13.06	)		(14.39	)		(14.21	)		(13.85	)		(12.83	)		(11.46	)
Transportation expense ($/boe) ⁽⁴⁾		(1.78	)		(2.18	)		(1.85	)		(1.67	)		(1.56	)		(1.27	)		(1.10	)		(1.06	)
Operating netback ($/boe) ⁽²⁾		37.21			34.96			44.79			52.41			66.98			54.91			43.02			39.01
Financial derivatives (loss) gain ($/boe) ⁽⁴⁾		2.00			0.69			(6.21	)		(9.98	)		(16.41	)		(11.59	)		(9.49	)		(7.34	)
Operating netback after financial derivatives ($/boe) ⁽²⁾		39.21			35.65			38.58			42.43			50.57			43.32			33.53			31.67

(1)

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

(2)

(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. Second Quarter Report 2023

Our results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have strengthened. Production of 89,761 boe/d for Q2/2023 has steadily increased from 79,872 boe/d in Q4/2020 which reflects strong well performance and increased development activity as commodity prices have improved along with the production contribution from the Merger with Ranger which closed on June 20, 2023.

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 in our realized sales price of $105.44/boe for Q2/2022. Our realized price of $66.82/boe for Q2/2023 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 $273.6 million for Q2/2023 reflects strong price realizations and production results from our development plans in the U.S. and Canada in addition to the Merger with Ranger.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, acquisitions and dispositions, changes in our free cash flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. The increase in net debt⁽¹⁾ from $1.6 billion at Q4/2020 to $2.8 billion at Q2/2023 is primarily a result of the Merger with Ranger which closed in Q2/2023 along with $159.0 million of shareholder returns. The change in net debt also reflects free cash flow⁽²⁾ of $954.3 million generated over the last eight quarters.

(1)

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

(2)

Baytex Energy Corp. Second Quarter Report 2023

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

In June 2023, the International Sustainability Standards Board ("ISSB") issued IFRS S1 General Requirements for Disclosure of Sustainability-related Financial Information and IFRS S2 Climate-related Disclosures which are effective for annual reporting periods beginning on or after January 1, 2024. These standards provide for transition relief in IFRS S1 that allow reporting entity to report on only climate-related risks and opportunities in the first year of reporting under the sustainability standards.

The Canadian Securities Administrators ("CSA") are responsible for determining the reporting requirements for public companies in Canada and are responsible for decisions related to the adoption of the sustainability disclosure standard, including the effective annual reporting dates. The CSA issued proposed National Instrument NI-51-107 – Disclosure of Climate-related Matters in October 2021. The CSA intends to consider the ISSB standards in addition to development in United States reporting requirements in its decision relating to development of climate-related disclosure requirements for Canadian reporting issuers. The CSA will involve the Canadian Sustainability Standards Board ("CSSB") for a combined review of the suitability of the adopting the ISSB standards in Canada. There is no requirement for public companies in Canada to adopt the ISSB standards until the CSA and CSSB have issued a decision on reporting requirements in Canada. While we are actively reviewing the ISSB standards we have not yet determined the impact on future financial statements nor have we quantified the costs to comply with such standards.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at June 30, 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 six months ended June 30, 2023 except for the critical accounting estimates related to the business combination with Ranger. 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" and "net debt" 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 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.

Baytex Energy Corp. Second Quarter Report 2023

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 June 30						Six Months Ended June 30
($ thousands)	2023			2022			2023			2022
Petroleum and natural gas sales	$	598,760		$	854,169		$	1,154,096		$	1,527,994
Light oil and condensate ⁽¹⁾		(308,810	)		(415,592	)		(597,275	)		(776,567	)
_NGL (1)		(20,163	)		(33,183	)		(41,997	)		(62,674	)
Natural gas sales ⁽¹⁾		(18,338	)		(59,293	)		(46,290	)		(98,214	)
Heavy oil sales	$	251,449		$	346,101		$	468,534		$	590,539
Blending and other expense ⁽²⁾		(52,995	)		(56,895	)		(112,676	)		(98,335	)
Heavy oil, net of blending and other expense	$	198,454		$	289,206		$	355,858		$	492,204

	(1)	Component of petroleum and natural gas sales. See Note 13 – Petroleum and Natural Gas Sales in the consolidated financial statements for the three and six months ended June 30, 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 June 30						Six Months Ended June 30
($ thousands)	2023			2022			2023			2022
Petroleum and natural gas sales	$	598,760		$	854,169		$	1,154,096		$	1,527,994
Blending and other expense		(52,995	)		(56,895	)		(112,676	)		(98,335	)
Total sales, net of blending and other expense		545,765			797,274			1,041,420			1,429,659
Royalties		(107,920	)		(171,559	)		(201,173	)		(294,279	)
Operating expense		(119,438	)		(107,426	)		(231,846	)		(208,192	)
Transportation expense		(14,574	)		(11,758	)		(31,579	)		(20,973	)
Operating netback		303,833			506,531			576,822			906,215
Realized financial derivatives gain (loss) ⁽¹⁾		16,365			(124,042	)		21,780			(208,408	)
Operating netback after realized financial derivatives	$	320,198		$	382,489		$	598,602		$	697,807

(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 and six months ended June 30, 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. Second Quarter Report 2023

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

	Three Months Ended June 30						Six Months Ended June 30
($ thousands)	2023			2022			2023			2022
Cash flows from operating activities	$	192,308		$	360,034		$	377,246		$	559,008
Change in non-cash working capital		40,795			(17,046	)		79,849		$	60,294
Additions to exploration and evaluation assets		(741	)		(2,338	)		(1,231	)		(5,897	)
Additions to oil and gas properties		(169,963	)		(94,295	)		(403,099	)		(244,558	)
Payments on lease obligations		(1,181	)		(1,039	)		(2,336	)		(2,213	)
Transaction costs		32,832			—			41,703			—
Cash premiums on derivatives		2,263			—			2,263			—
Free cash flow	$	96,313		$	245,316		$	94,395		$	366,634

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

Net debt

Baytex Energy Corp. Second Quarter Report 2023

The following table summarizes our calculation of net debt.

($ thousands)	June 30, 2023			December 31, 2022
Credit facilities	$	964,332		$	383,031
Unamortized debt issuance costs - Credit facilities ⁽¹⁾		22,571			2,363
Long-term notes		1,563,897			547,598
Unamortized debt issuance costs - Long-term notes ⁽¹⁾		37,571			6,999
Trade and other payables		616,608			281,404
Cash		(19,637	)		(5,464	)
Trade and other receivables		(370,498	)		(228,485	)
Net debt	$	2,814,844		$	987,446

(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 and six months ended June 30, 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, transaction costs and cash premiums on derivatives.

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

	Three Months Ended June 30					Six Months Ended June 30
($ thousands)	2023		2022			2023		2022
Cash flow from operating activities	$	192,308	$	360,034		$	377,246	$	559,008
Change in non-cash working capital		40,795		(17,046	)		79,849		60,294
Asset retirement obligations settled		5,392		2,716			9,518		6,009
Transaction costs		32,832		—			41,703		—
Cash premiums on derivatives		2,263		—			2,263		—
Adjusted funds flow	$	273,590	$	345,704		$	510,579	$	625,311

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 June 30, 2023, except for the matter described below.

On June 20, 2023, Baytex completed the acquisition of Ranger, a publicly traded oil and gas company that was listed on the NASDAQ exchange. Ranger's operations have been included in the consolidated financial statements of Baytex since June 20, 2023. However, Baytex has not had sufficient time to appropriately assess the disclosure controls and procedures and internal controls over financial reporting previously used by Ranger and integrate them with those of Baytex. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of Ranger (as permitted by applicable securities laws in Canada and the U.S.). Baytex has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by June 20, 2024.

During the three months ended June 30, 2023, the assets previously held by Ranger contributed revenues of $49.0 million (representing 8% of total revenues) and net income before tax of $0.9 million (representing 3% of total net income before tax). At June 30, 2023, current assets of $178.4 million, non-current assets of $3.3 billion, current liabilities of $321.7 million and non-current liabilities of $74.4 million were associated with the acquired entity.

Baytex Energy Corp. Second Quarter Report 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: expectations regarding our intention to further strengthen our balance sheet and the allocation of free cash flow, including with respect to debt repayment and shareholder returns; our 2023 guidance on a stand-alone basis 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 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.

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) 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.

Baytex Energy Corp. Second Quarter Report 2023

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Financial Position

(thousands of Canadian dollars) (unaudited)

			As at
	Notes		June 30, 2023			December 31, 2022
ASSETS
Current assets
Cash			$	19,637		$	5,464
Trade and other receivables				370,498			228,485
Financial derivatives		17		27,505			10,105
				417,640			244,054
Non-current assets
Exploration and evaluation assets		5		162,448			168,684
Oil and gas properties		6		7,759,725			4,620,766
Other plant and equipment				6,794			6,568
Lease assets				35,979			6,453
Deferred income tax asset		14		234,858			57,244
			$	8,617,444		$	5,103,769
LIABILITIES
Current liabilities
Trade and other payables			$	614,763		$	272,195
Financial derivatives		17		2,907			—
Lease obligations				24,289			3,521
Asset retirement obligations		9		12,965			12,813
				654,924			288,529
Non-current liabilities
Trade and other payables				1,845			9,209
Credit facilities		7		964,332			383,031
Long-term notes		8		1,563,897			547,598
Lease obligations				11,879			3,017
Asset retirement obligations		9		641,605			576,110
Deferred income tax liability		14		177,751			265,858
				4,016,233			2,073,352
SHAREHOLDERS’ EQUITY
Shareholders' capital		10		6,852,328			5,499,664
Contributed surplus				89,970			89,879
Accumulated other comprehensive income				709,190			756,195
Deficit				(3,050,277	)		(3,315,321	)
				4,601,211			3,030,417
			$	8,617,444		$	5,103,769

Subsequent events (note 10 and note 17)

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2023

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Income and Comprehensive Income

(thousands of Canadian dollars, except per common share amounts and weighted average common shares) (unaudited)

			Three Months Ended June 30						Six Months Ended June 30
	Notes		2023			2022			2023			2022
Revenue, net of royalties
Petroleum and natural gas sales		13	$	598,760		$	854,169		$	1,154,096		$	1,527,994
Royalties				(107,920	)		(171,559	)		(201,173	)		(294,279	)
				490,840			682,610			952,923			1,233,715
Expenses
Operating				119,438			107,426			231,846			208,192
Transportation				14,574			11,758			31,579			20,973
Blending and other				52,995			56,895			112,676			98,335
General and administrative				15,240			11,640			26,974			23,322
Transaction costs		3		32,832			—			41,703			—
Exploration and evaluation		5		369			7,210			532			10,780
Depletion and depreciation				176,144			142,286			342,143			283,077
Share-based compensation		11		16,918			2,942			26,741			6,887
Financing and interest		15		34,497			27,077			58,222			51,321
Financial derivatives (gain) loss		17		3,038			65,274			(11,587	)		305,901
Foreign exchange (gain) loss		16		(11,939	)		27,709			(12,002	)		13,364
(Gain) loss on dispositions				—			(207	)		336			(441	)
Other expense (income)				141			568			(917	)		(464	)
				454,247			460,578			848,246			1,021,247
Net income before income taxes				36,593			222,032			104,677			212,468
Income tax expense (recovery)		14
Current income tax expense				1,350			1,140			2,470			2,050
Deferred income tax expense (recovery)				(178,360	)		39,920			(162,837	)		(27,412	)
				(177,010	)		41,060			(160,367	)		(25,362	)
Net income			$	213,603		$	180,972		$	265,044		$	237,830
Other comprehensive income (loss)
Foreign currency translation adjustment				(46,457	)		58,917			(47,005	)		30,838
Comprehensive income			$	167,146		$	239,889		$	218,039		$	268,668

Net income per common share		12
Basic			$	0.37		$	0.32		$	0.47		$	0.42
Diluted			$	0.36		$	0.32		$	0.47		$	0.42

Weighted average common shares (000's)		12
Basic				583,365			566,997			564,319			566,262
Diluted				588,170			571,697			569,284			570,844

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2023

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Changes in Equity

(thousands of Canadian dollars) (unaudited)

									Accumulated
									other
			Shareholders’			Contributed			comprehensive
	Notes		capital			surplus			income (loss)			Deficit			Total equity
Balance at December 31, 2021			$	5,736,593		$	13,559		$	632,103		$	(4,170,926	)	$	2,211,329
Vesting of share awards				8,429			(8,429	)		—			—			—
Share-based compensation				—			2,078			—			—			2,078
Repurchase of common shares for cancellation				(91,139	)		28,675			—			—			(62,464	)
Comprehensive income				—			—			30,838			237,830			268,668
Balance at June 30, 2022			$	5,653,883		$	35,883		$	662,941		$	(3,933,096	)	$	2,419,611
Balance at December 31, 2022			$	5,499,664		$	89,879		$	756,195		$	(3,315,321	)	$	3,030,417
Issued on corporate acquisition		3		1,326,435			21,316			—			—			1,347,751
Vesting of share awards		10		26,229			(37,462	)		—			—			(11,233	)
Share-based compensation		11		—			16,237			—			—			16,237
Comprehensive (loss) income				—			—			(47,005	)		265,044			218,039
Balance at June 30, 2023			$	6,852,328		$	89,970		$	709,190		$	(3,050,277	)	$	4,601,211

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2023

Baytex Energy Corp.

Condensed Consolidated Interim Statements of Cash Flows

(thousands of Canadian dollars) (unaudited)

			Three Months Ended June 30						Six Months Ended June 30
	Notes		2023			2022			2023			2022
CASH PROVIDED BY (USED IN):
Operating activities
Net income			$	213,603		$	180,972		$	265,044		$	237,830
Adjustments for:
Non-cash share-based compensation		11		16,237			372			16,237			2,078
Unrealized foreign exchange (gain) loss		16		(12,880	)		27,499			(13,093	)		12,951
Exploration and evaluation		5		369			7,210			532			10,780
Depletion and depreciation				176,144			142,286			342,143			283,077
Non-cash financing and accretion		15		6,242			6,603			11,592			10,420
Non-cash other income		9		—			(183	)		(1,271	)		(1,465	)
Unrealized financial derivatives (gain) loss		17		19,403			(58,768	)		10,193			97,493
Cash premiums on derivatives				(2,263	)		—			(2,263	)		—
(Gain) loss on dispositions				—			(207	)		336			(441	)
Deferred income tax expense (recovery)		14		(178,360	)		39,920			(162,837	)		(27,412	)
Asset retirement obligations settled		9		(5,392	)		(2,716	)		(9,518	)		(6,009	)
Change in non-cash working capital				(40,795	)		17,046			(79,849	)		(60,294	)
				192,308			360,034			377,246			559,008
Financing activities
Increase (decrease) in credit facilities				577,428			62,791			601,979			(15,351	)
Decrease in acquired credit facilities		3		(373,608	)		—			(373,608	)		—
Debt issuance costs				(39,925	)		(1,832	)		(39,925	)		(1,832	)
Payments on lease obligations				(1,181	)		(1,039	)		(2,336	)		(2,213	)
Net proceeds from issuance of long-term notes		8		1,046,197			—			1,046,197			—
Redemption of long-term notes		8		—			(252,830	)		—			(252,830	)
Redemption of acquired long-term notes		3		(569,256	)		—			(569,256	)		—
Repurchase of common shares		10		—			(62,464	)		—			(62,464	)
				639,655			(255,374	)		663,051			(334,690	)
Investing activities
Additions to exploration and evaluation assets		5		(741	)		(2,338	)		(1,231	)		(5,897	)
Additions to oil and gas properties		6		(169,963	)		(94,295	)		(403,099	)		(244,558	)
Additions to other plant and equipment				(580	)		(260	)		(1,021	)		(634	)
Corporate acquisition, net of cash acquired		3		(662,579	)					(662,579	)
Property acquisitions				62			(208	)		(444	)		(267	)
Proceeds from dispositions				50			14			285			41
Change in non-cash working capital				14,980			(7,573	)		41,965			26,997
				(818,771	)		(104,660	)		(1,026,124	)		(224,318	)
Change in cash				13,192			—			14,173			—
Cash, beginning of period				6,445			—			5,464			—
Cash, end of period			$	19,637		$	—		$	19,637		$	—

Supplementary information
Interest paid			$	7,535		$	11,181		$	38,004		$	41,529
Income taxes paid			$	3,603		$	263		$	3,603		$	263

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2023

Baytex Energy Corp.

Notes to the Condensed Consolidated Interim Financial Statements

For the periods ended June 30, 2023 and 2022

(all tabular amounts in thousands of Canadian dollars, except per common share amounts) (unaudited)

1. REPORTING ENTITY

Baytex Energy Corp. (the “Company” or “Baytex”) is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and the state of Texas in the United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

2. BASIS OF PRESENTATION

The condensed consolidated interim financial statements ("consolidated financial statements") have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, under International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). These condensed consolidated financial statements do not include all the necessary annual disclosures as prescribed by IFRS and should be read in conjunction with the annual consolidated financial statements as at and for the year ended December 31, 2022.

The consolidated financial statements were approved by the Board of Directors of Baytex on July 27, 2023.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of derivative financial instruments which have been measured at fair value. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or when otherwise indicated.

The audited consolidated financial statements of the Company as at and for the year ended December 31, 2022 are available through its filings on SEDAR at www.sedar.com and through the U.S. Securities and Exchange Commission at www.sec.gov.

Estimation Uncertainty

Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities. There have been no changes in our key areas of judgement or estimation uncertainty for the six months ended June 30, 2023 except for the judgements and estimates related to Business Combinations as discussed below.

Business Combinations

Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition of a business in accordance with IFRS. The determination of the fair value assigned to assets acquired and liabilities assumed requires management to make assumptions and estimates. These assumptions or estimates used in determining the fair value of assets acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill. Oil and gas properties acquired represents the largest fair value estimate which is derived from the present value of expected future cash flows after-tax using estimates of reserves acquired prepared by an independent qualified reserve evaluator using forecasted commodity prices and applying a discount rate. Assumptions used to arrive at the fair value are further verified by way of market comparisons and third party sources.

Environmental Reporting Regulations

Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued two IFRS Sustainability Disclosure Standards 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. Baytex continues to monitor developments on these reporting requirements and has not yet quantified the cost to comply with these regulations.

Significant Accounting Policies

The accounting policies, critical accounting judgments (with the addition of Business Combinations) and significant estimates used in these consolidated financial statements are consistent with those used in the preparation of the 2022 annual financial statements.

Baytex Energy Corp. Second Quarter Report 2023

3. BUSINESS COMBINATION

On June 20, 2023, Baytex closed the previously announced acquisition whereby Baytex acquired, directly and indirectly, all of the issued and outstanding common shares of Ranger Oil Corporation (“Ranger”), a publicly traded oil and gas exploration and production company with operations in the Eagle Ford. Baytex is treated as the acquirer for accounting purposes. The acquisition increases Baytex's Eagle Ford scale and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford.

The acquisition was accounted for as a business combination whereby the net assets acquired and liabilities assumed were recorded at fair value at the acquisition date. The total consideration paid by Baytex was US$1.6 billion (C$2.1 billion) consisting of $732.8 million in cash consideration and the issuance of 311.4 million Baytex common shares valued at approximately $1.3 billion (based on the closing price of Baytex’s common shares of $4.26 per share on the Toronto Stock Exchange on June 20, 2023). Under the terms of the agreement, Ranger shareholders received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger common stock.

The fair value of oil and gas properties acquired is based on estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows include production volumes, royalty obligations, operating costs, capital costs, tax rates, forecasted commodity prices, along with inflation and discount rates used to estimate present value. These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves, the discount rate used to present value future cash flows, and assumptions regarding the timing and amount of capital expenditures and future abandonment and reclamation obligations. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. The fair value of oil and gas properties were determined using a discount rate of 12.5%.

Asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired using a credit-adjusted discount rate of 9%.

The total consideration paid and estimates of the fair value of the assets acquired and liabilities assumed as at the date of the acquisition are set forth in the table below. The preliminary purchase price allocation is based on Management's best estimate of the assets acquired and liabilities assumed. Adjustments to these initial estimates may be required upon finalizing the value of net assets acquired.

	USD			_CAD⁽¹⁾
Consideration
Cash	$	553,150		$	732,840
Common shares issued		1,001,196			1,326,435
Share based compensation ⁽²⁾		20,107			26,638
Total consideration	$	1,574,453		$	2,085,913

Fair value of net assets acquired
Oil and gas properties	$	2,325,996		$	3,081,596
Working capital deficiency excluding bank debt and financial derivatives ⁽³⁾		(108,147	)		(143,278	)
Financial derivatives		17,030			22,562
Lease assets		15,708			20,811
Lease obligations		(15,708	)		(20,811	)
Credit facilities		(282,000	)		(373,608	)
Long-term notes		(429,676	)		(569,256	)
Asset retirement obligations		(23,632	)		(31,310	)
Deferred income tax asset		74,882			99,207
Net assets acquired	$	1,574,453		$	2,085,913

	(1)	Exchange rate used to translate the U.S. denominated values above is the rate as at the closing date being CAD/USD 1.32485.
	(2)	Follow closing of the transaction, holders of awards outstanding under Ranger's share based compensation plans are entitled to Baytex common shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition date while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods (note 11).
	(3)	Includes $70.3 million (US$53.0 million) of cash. Accounts receivable acquired is net of a provision for expected credit losses of approximately $0.3 million.

Baytex Energy Corp. Second Quarter Report 2023

The cash portion of the transaction was funded with Baytex’s expanded credit facility which increased to US$1.1 billion at close of the transaction, US$150 million from a two-year term loan facility, and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. Baytex closed the US$800 million, senior unsecured note offering on April 27, 2023 and the net proceeds were released from escrow on June 20, 2023.

These consolidated financial statements include the results of operations of Ranger for the period following closing of the transaction on June 20, 2023. For the three months ended June 30, 2023, the acquisition contributed revenues and net income before tax of $49.0 million and $0.9 million respectively. Had the acquisition occurred on January 1, 2023, revenues and net income before income taxes would have increased by $848.4 million and $218.3 million, respectively, for the six months ended June 30, 2023. This pro-forma information is not necessarily indicative of the results of operations that would have resulted had the acquisition been reflected on the dates indicated, or that may be obtained in the future.

During the six months ended June 30, 2023, Baytex incurred $41.7 million of transaction costs, including consulting, financial advisory, legal and filing fees related to the acquisition of Ranger.

4. SEGMENTED FINANCIAL INFORMATION

Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:

Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada;

U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the Eagle Ford in Texas; and

Corporate includes corporate activities and items not allocated between operating segments.

	Canada						U.S.						Corporate						Consolidated
Three Months Ended June 30	2023			2022			2023			2022			2023			2022			2023			2022
Revenue, net of royalties
Petroleum and natural gas sales	$	390,292		$	581,197		$	208,468		$	272,972		$	—		$	—		$	598,760		$	854,169
Royalties		(47,309	)		(91,133	)		(60,611	)		(80,426	)		—			—			(107,920	)		(171,559	)
		342,983			490,064			147,857			192,546			—			—			490,840			682,610
Expenses
Operating		91,354			82,471			28,084			24,955			—			—			119,438			107,426
Transportation		13,240			11,758			1,334			—			—			—			14,574			11,758
Blending and other		52,995			56,895			—			—			—			—			52,995			56,895
General and administrative		—			—			—			—			15,240			11,640			15,240			11,640
Transaction costs		—			—			7,298			—			25,534			—			32,832			—
Exploration and evaluation		369			7,210			—			—			—			—			369			7,210
Depletion and depreciation		112,262			100,712			62,211			40,097			1,671			1,477			176,144			142,286
Share-based compensation		—			—			—			—			16,918			2,942			16,918			2,942
Financing and interest		—			—			—			—			34,497			27,077			34,497			27,077
Financial derivatives (gain) loss		—			—			—			—			3,038			65,274			3,038			65,274
Foreign exchange (gain) loss		—			—			—			—			(11,939	)		27,709			(11,939	)		27,709
Gain on dispositions		—			(207	)		—			—			—			—			—			(207	)
Other (income) expense		—			(183	)		—			—			141			751			141			568
		270,220			258,656			98,927			65,052			85,100			136,870			454,247			460,578
Net income (loss) before income taxes		72,763			231,408			48,930			127,494			(85,100	)		(136,870	)		36,593			222,032
Income tax (recovery) expense
Current income tax expense																				1,350			1,140
Deferred income tax (recovery) expense																				(178,360	)		39,920
																				(177,010	)		41,060
Net income (loss)	$	72,763		$	231,408		$	48,930		$	127,494		$	(85,100	)	$	(136,870	)	$	213,603		$	180,972

Additions to exploration and evaluation assets		741			2,338			—			—			—			—			741			2,338
Additions to oil and gas properties		95,662			49,543			74,301			44,752			—			—			169,963			94,295
Corporate acquisition, net of cash acquired		—			—			662,439			—			—			—			662,439			—
Property acquisitions		(62	)		208			—			—			—			—			(62	)		208
Proceeds from dispositions		(50	)		(14	)		—			—			—			—			(50	)		(14	)

Baytex Energy Corp. Second Quarter Report 2023

	Canada						U.S.						Corporate						Consolidated
Six Months Ended June 30	2023			2022			2023			2022			2023			2022			2023			2022
Revenue, net of royalties
Petroleum and natural gas sales	$	775,914		$	1,034,901		$	378,182		$	493,093		$	—		$	—		$	1,154,096		$	1,527,994
Royalties		(91,164	)		(148,809	)		(110,009	)		(145,470	)		—			—			(201,173	)		(294,279	)
		684,750			886,092			268,173			347,623			—			—			952,923			1,233,715
Expenses
Operating		182,534			161,011			49,312			47,181			—			—			231,846			208,192
Transportation		30,245			20,973			1,334			—			—			—			31,579			20,973
Blending and other		112,676			98,335			—			—			—			—			112,676			98,335
General and administrative		—			—			—			—			26,974			23,322			26,974			23,322
Transaction costs		—			—			7,298			—			34,405			—			41,703			—
Exploration and evaluation		532			10,780			—			—			—			—			532			10,780
Depletion and depreciation		231,733			201,794			107,175			78,461			3,235			2,822			342,143			283,077
Share-based compensation		—			—			—			—			26,741			6,887			26,741			6,887
Financing and interest		—			—			—			—			58,222			51,321			58,222			51,321
Financial derivatives (gain) loss		—			—			—			—			(11,587	)		305,901			(11,587	)		305,901
Foreign exchange (gain) loss		—			—			—			—			(12,002	)		13,364			(12,002	)		13,364
Loss (gain) on dispositions		336			(441	)		—			—			—			—			336			(441	)
Other (income) expense		(1,271	)		(1,465	)		—			—			354			1,001			(917	)		(464	)
		556,785			490,987			165,119			125,642			126,342			404,618			848,246			1,021,247
Net income (loss) before income taxes		127,965			395,105			103,054			221,981			(126,342	)		(404,618	)		104,677			212,468
Income tax (recovery) expense
Current income tax expense																				2,470			2,050
Deferred income tax (recovery) expense																				(162,837	)		(27,412	)
																				(160,367	)		(25,362	)
Net income (loss)	$	127,965		$	395,105		$	103,054		$	221,981		$	(126,342	)	$	(404,618	)	$	265,044		$	237,830
Additions to exploration and evaluation assets		1,231			5,897			—			—			—			—			1,231			5,897
Additions to oil and gas properties		279,778			172,114			123,321			72,444			—			—			403,099			244,558
Corporate acquisition, net of cash
acquired		—			—			662,439			—			—			—			662,439			—
Property acquisitions		444			267			—			—			—			—			444			267
Proceeds from dispositions		(285	)		(41	)		—			—			—			—			(285	)		(41	)

	June 30, 2023		December 31, 2022
Canadian assets	$	2,791,516	$	2,779,596
U.S. assets		5,755,650		2,301,047
Corporate assets		70,278		23,126
Total consolidated assets	$	8,617,444	$	5,103,769

Baytex Energy Corp. Second Quarter Report 2023

5. EXPLORATION AND EVALUATION ASSETS

	June 30, 2023			December 31, 2022
Balance, beginning of period	$	168,684		$	172,824
Capital expenditures		1,231			6,359
Property acquisitions		506			301
Divestitures		(788	)		(498	)
Property swaps		978			385
Impairment reversal		—			22,503
Exploration and evaluation expense		(532	)		(30,239	)
Transfer to oil and gas properties (note 6)		(5,887	)		(8,496	)
Foreign currency translation		(1,744	)		5,545
Balance, end of period	$	162,448		$	168,684

At June 30, 2023 there were no indicators of impairment or impairment reversal for exploration and evaluation assets in any of the Company's cash generating units ("CGUs").

At December 31, 2022, the Company identified indicators of impairment reversal for the exploration and evaluation assets within the Peace River CGU due to an increase in land sale values. The recoverable amount for the Peace River CGU exceeded its carrying value and an impairment reversal of $22.5 million was recorded at December 31, 2022. The recoverable amount was based on the CGU's fair value less costs of disposal ("FVLCD") and was estimated with reference to arm's length transactions in comparable locations and the discounted cash flows associated with the Company's future development plans.

6. OIL AND GAS PROPERTIES

				Accumulated
	Cost			depletion			Net book value
Balance, December 31, 2021	$	11,633,517		$	(7,169,146	)	$	4,464,371
Capital expenditures		515,183			—			515,183
Property acquisitions		1,173			—			1,173
Transfers from exploration and evaluation assets (note 5)		8,496			—			8,496
Change in asset retirement obligations (note 9)		(147,020	)		—			(147,020	)
Divestitures		(265,166	)		241,892			(23,274	)
Property swaps		—			—			—
Impairment reversal		—			245,241			245,241
Foreign currency translation		296,033			(158,404	)		137,629
Depletion		—			(581,033	)		(581,033	)
Balance, December 31, 2022	$	12,042,216		$	(7,421,450	)	$	4,620,766
Capital expenditures		403,099			—			403,099
Corporate acquisition (note 3)		3,081,596			—			3,081,596
Transfers from exploration and evaluation assets (note 5)		5,887			—			5,887
Change in asset retirement obligations (note 9)		37,017			—			37,017
Divestitures		(1,997	)		1,511			(486	)
Property swaps		(4,733	)		3,756			(977	)
Foreign currency translation		(104,963	)		56,694			(48,269	)
Depletion		—			(338,908	)		(338,908	)
Balance, June 30, 2023	$	15,458,122		$	(7,698,397	)	$	7,759,725

At June 30, 2023, there were no indicators of impairment or impairment reversal for oil and gas properties in any of the Company's CGUs.

Baytex Energy Corp. Second Quarter Report 2023

At December 31, 2022, the Company 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. The recoverable amounts for three CGUs exceeded their carrying values which resulted in an impairment reversal of $245.2 million recorded at December 31, 2022. The recoverable amount for each CGU was based on its FVLCD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2022. The after-tax discount rates applied to the cash flows were between 12% and 23%.

7. CREDIT FACILITIES

	June 30, 2023			December 31, 2022
Credit facilities - U.S. dollar denominated ⁽¹⁾	$	413,785		$	30,394
Credit facilities - Canadian dollar denominated		374,555			355,000
Term loan - U.S. dollar denominated ⁽¹⁾		198,563			—
Credit facilities - principal ⁽²⁾		986,903			385,394
Unamortized debt issuance costs		(22,571	)		(2,363	)
Credit facilities	$	964,332		$	383,031

	(1)	U.S. dollar denominated credit facilities balance was US$462.6 million as at June 30, 2023 (December 31, 2022 - US$22.5 million).
	(2)	The increase in the principal amount of the credit facilities outstanding from December 31, 2022 to June 30, 2023 is the result of net draws of $602.5 million as well as changes in the reported amount of U.S. denominated debt of $1.0 million due to foreign exchange.

At June 30, 2023, Baytex had US$1.1 billion of revolving credit facilities (the "Revolving Facilities) and a US$150 million term loan (the "Term Loan") (collectively the "Credit Facilities"). On June 20, 2023, in connection with the acquisition of Ranger, Baytex amended its Credit Facilities to increase the committed amount (previously US$850 million in aggregate as of April 1, 2022) and entered into a secured two-year term loan of US$150 million that will mature on June 20, 2025. The maturity date of the Revolving Facilities is April 1, 2026.

The Revolving Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The amended Credit Facilities contain an additional financial covenant of a maximum Total Debt to Bank EBITDA ratio of 4.0:1.0 and increased the Interest Coverage minimum ratio to 3.5:1.0 (from 2.0:1.0).

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 6.5% for the six months ended June 30, 2023 (2.6% for six months ended June 30, 2022).

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2023.

	Position as at
Covenant Description	June 30, 2023	Covenant
Senior Secured Debt ⁽¹⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)	0.5:1.0	3.5:1.0
Interest Coverage ⁽³⁾ (Minimum Ratio)	13.3:1.0	3.5:1.0
Total Debt ⁽⁴⁾ to Bank EBITDA ⁽²⁾ (Maximum Ratio)	1.2:1.0	4:0:1.0

	(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 June 30, 2023, the Company's Senior Secured Debt totaled $986.9 million of principal amounts outstanding.
	(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 June 30, 2023 was $2.1 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 June 30, 2023 was $155.8 million.
	(4)	"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade and other payables, asset retirement obligations, leases, deferred income tax liabilities, and financial derivative liabilities. As at June 30, 2023, the Company's Total Debt totaled $2.6 billion of principal amounts outstanding.

Baytex Energy Corp. Second Quarter Report 2023

At June 30, 2023, Baytex had $16.8 million of outstanding letters of credit, $15.5 million of which is 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.

8. LONG-TERM NOTES

	June 30, 2023			December 31, 2022
8.75% notes due April 1, 2027 ⁽¹⁾	$	542,467		$	554,597
8.50% notes due April 1, 2030 ⁽²⁾		1,059,001			—
Total long-term notes - principal ⁽³⁾		1,601,468			554,597
Unamortized debt issuance costs		(37,571	)		(6,999	)
Total long-term notes - net of discount and unamortized debt issuance costs	$	1,563,897		$	547,598

	(1)	The U.S. dollar denominated principal outstanding of the 8.75% notes was US$409.8 million as at June 30, 2023 (December 31, 2022 - US$409.8 million).
	(2)	The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million as at June 30, 2023 (December 31, 2022 - nil).
	(3)	The increase in the principal amount of long-term notes outstanding from December 31, 2022 to June 30, 2023 is the result of the issuance of the 8.50% notes for $1.1 billion partially offset by changes in the reported amount of U.S. denominated debt of $13.0 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.

The long-term notes do not contain any significant financial maintenance covenants but do contain standard commercial covenants for debt incurrence and restricted payments.

9. ASSET RETIREMENT OBLIGATIONS

	June 30, 2023			December 31, 2022
Balance, beginning of period	$	588,923		$	743,683
Liabilities incurred ⁽¹⁾		11,302			19,942
Liabilities settled		(9,518	)		(18,351	)
Liabilities assumed from corporate acquisition (note 3)		31,310			—
Liabilities acquired from property acquisitions		—			950
Liabilities divested		(590	)		(3,464	)
Accretion (note 15)		9,221			15,683
Government grants ⁽²⁾		(1,271	)		(4,009	)
Change in estimate ⁽¹⁾		4,958			6,124
Changes in discount rates and inflation rates ⁽¹⁾⁽³⁾		20,757			(173,086	)
Foreign currency translation		(522	)		1,451
Balance, end of period	$	654,570		$	588,923
Less current portion of asset retirement obligations		12,965			12,813
Non-current portion of asset retirement obligations	$	641,605		$	576,110

	(1)	Agrees to total change in asset retirement obligations of $37.0 million per Note 6 - Oil and Gas Properties.
	(2)	During the six months ended June 30, 2023, Baytex recognized $1.3 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($4.0 million for the year ended December 31, 2022).
	(3)	The discount and inflation rates used to calculate the liability for our Canadian operations at June 30, 2023 were 3.1% and 1.7%, respectively (December 31, 2022 - 3.3% and 2.1%). The discount and inflation rates used to calculate the liability for our U.S. operations at June 30, 2023 were 3.9% and 2.2%, respectively (December 31, 2022 - 3.3% and 2.1%). Baytex used a risk-free discount rate for the U.S operations liability at Q2 2023 (previously used a credit-adjusted rate).

Baytex Energy Corp. Second Quarter Report 2023

10. SHAREHOLDERS' CAPITAL

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. At June 30, 2023, no preferred shares have been issued by the Company and all common shares issued were fully paid.

The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.

In June 2023, the TSX accepted Baytex's notice of intention to renew its Normal Course Issuer Bid ("NCIB"). Under the terms of the NCIB, the Company may purchase for cancellation up to 68.4 million common shares over the 12-month period commencing June 29, 2023. The number of shares authorized for repurchase represents 10% of the Company's public float as at June 21, 2023. On June 21, 2023 Baytex had 856.9 million common shares outstanding. Purchases are made on the open market at prices prevailing at the time of the transaction. Subsequent to June 30, 2023 and through to July 26, 2023, Baytex repurchased 4.7 million common shares under the NCIB at an average price of $4.59 per share.

Subsequent to June 30, 2023, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 2, 2023 for shareholders of record as at September 15, 2023.

	Number of
	Common Shares
	(000s)			Amount
Balance, December 31, 2021		564,213		$	5,736,593
Vesting of share awards		5,035			8,501
Common shares repurchased and cancelled		(24,318	)		(245,430	)
Balance, December 31, 2022		544,930		$	5,499,664
Issued on corporate acquisition (note 3)		311,370			1,326,435
Vesting of share awards		5,892			26,229
Balance, June 30, 2023		862,192		$	6,852,328

11. SHARE-BASED COMPENSATION PLAN

For the three and six months ended June 30, 2023 the Company recorded total share-based compensation expense of $16.9 million and $26.7 million respectively ($2.9 million and $6.9 million for the three and six months ended June 30, 2022) which are comprised of $16.2 million of non-cash expense related to awards assumed in the acquisition of Ranger and were settled with Baytex common shares after closing of the business combination and the expense related to cash-settled awards and the associated equity total return swaps ($2.6 million and $4.8 million for the three and six months ended June 30, 2022).

The Company's closing share price on the Toronto Stock Exchange on June 30, 2023 was $4.32 (June 30, 2022 - $6.25).

Share Award Incentive Plan

Baytex has a Share Award Incentive Plan pursuant to which it issues restricted and performance awards. A restricted award entitles the holder of each award to receive one common share of Baytex or the equivalent cash value at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares or the cash equivalent value on vesting; the number of common shares issued is determined by a performance multiplier. The multiplier can range between zero and two and is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

On June 20, 2023, Baytex became the successor to Ranger's Share Award Plan. Although no new grants will be made under the Ranger Share Award Plan, awards that were outstanding at June 20, 2023 were converted to restricted awards that will be settled in shares of Baytex or with cash, with the quantity outstanding adjusted based on the exchange ratio for the business combination with Ranger.

The weighted average fair value of share awards granted during the six months ended June 30, 2023 was $5.41 per restricted and performance award ($5.68 for the six months ended June 30, 2022).

Baytex Energy Corp. Second Quarter Report 2023

The number of share awards outstanding is detailed below.

	Number of			Number of performance			Total number of
(000s)	restricted awards				awards			share awards
Balance, December 31, 2021		2,093			7,381			9,474
Granted		68			1,391			1,459
Added by performance factor		—			—			—
Vested		(1,377	)		(3,630	)		(5,007	)
Forfeited		(22	)		(346	)		(368	)
Balance, December 31, 2022		762			4,796			5,558
Granted		—			2,599			2,599
Assumed on corporate acquisition ⁽¹⁾		10,789			—			10,789
Vested		(9,302	)		(3,767	)		(13,069	)
Forfeited		(10	)		(234	)		(244	)
Balance, June 30, 2023		2,239			3,394			5,633

(1)

Follow closing of the transaction, holders of awards outstanding under Ranger's share based compensation plans are entitled to Baytex common shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition date (note 3) while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods.

Incentive Award Plan

Baytex has an Incentive Award Plan whereby the holder of each incentive award is entitled to receive a cash payment equal to the value of one Baytex common share at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in trade and other payables.

During the six months ended June 30, 2023, Baytex granted 2.4 million awards under the Incentive Award plan at a fair value of $5.39 per award (1.3 million awards at $5.68 per award for the six months ended June 30, 2022). At June 30, 2023 there were 4.6 million awards outstanding under the Incentive Award plan (5.1 million awards outstanding at December 31, 2022).

Deferred Share Unit Plan ("DSU Plan")

Baytex has a DSU Plan whereby each independent director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share per DSU award on the date at which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in trade and other payables.

During the six months ended June 30, 2023, Baytex granted 0.2 million awards under the DSU plan at a fair value of $5.49 per award (0.2 million awards at $5.68 per award for the six months ended June 30, 2022). At June 30, 2023, there were 1.2 million awards outstanding under the DSU plan.

Equity Total Return Swaps

The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix the aggregate cost of the Company's cash-settled DSU Plan, at the fair value determined on the grant date.

At June 30, 2023, an asset of $0.7 million associated with the equity return swap was included in trade and other receivables (December 31, 2022 - $21.2 million).

12. NET INCOME PER SHARE

Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the period.

Baytex Energy Corp. Second Quarter Report 2023

	Three Months Ended June 30
	2023					2022
			Weighted					Weighted
			average					average
			common					common
			shares	Net income				shares		Net income
	Net income		(000s)	per share		Net income		(000s)		per share
Net income - basic	$	213,603	583,365	$0.37		$	180,972	566,997		$0.32
Dilutive effect of share awards		—	4,805		—		—		4,700		—
Net income - diluted	$	213,603	588,170	$	0.36	$	180,972		571,697	$	0.32

	Six Months Ended June 30
	2023						2022
			Weighted
			average						Weighted
			common						average
			shares		Net income				common		Net income
	Net income		(000s)		per share		Net income		shares (000s)		per share
Net income - basic	$	265,044		564,319	$	0.47	$	237,830		566,262	$	0.42
Dilutive effect of share awards		—		4,965		—		—		4,582		—
Net income - diluted	$	265,044		569,284	$	0.47	$	237,830		570,844	$	0.42

For the three and six months ended June 30, 2023 and June 30, 2022 no share awards were excluded from the calculation of diluted income per share as all of their affects were dilutive.

13. PETROLEUM AND NATURAL GAS SALES

Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table.

	Three Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	124,965	$	183,845	$	308,810	$	192,986	$	222,606	$	415,592
Heavy oil		251,449		—		251,449		346,101		—		346,101
NGL		3,772		16,391		20,163		8,288		24,895		33,183
Natural gas sales		10,106		8,232		18,338		33,822		25,471		59,293
Total petroleum and natural gas sales	$	390,292	$	208,468	$	598,760	$	581,197	$	272,972	$	854,169

	Six Months Ended June 30
	2023						2022
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	271,420	$	325,855	$	597,275	$	373,141	$	403,426	$	776,567
Heavy oil		468,534		—		468,534		590,539		—		590,539
NGL		9,832		32,165		41,997		15,772		46,902		62,674
Natural gas sales		26,128		20,162		46,290		55,449		42,765		98,214
Total petroleum and natural gas sales	$	775,914	$	378,182	$	1,154,096	$	1,034,901	$	493,093	$	1,527,994

Included in accounts receivable at June 30, 2023 is $294.4 million of accrued production revenue related to delivered volumes (December 31, 2022 - $183.0 million).

Baytex Energy Corp. Second Quarter Report 2023

14. INCOME TAXES

The provision for income taxes has been computed as follows:

	Six Months Ended June 30
	2023			2022
Net income (loss) before income taxes		104,677		$	212,468
Expected income taxes at the statutory rate of 24.80% (2022 – 25.12%)		25,960			53,372
Change in income taxes resulting from:
Effect of foreign exchange		(1,612	)		984
Effect of rate adjustments for foreign jurisdictions		(2,883	)		(18,357	)
Effect of change in deferred tax benefit not recognized ⁽¹⁾		(1,613	)		(17,823	)
Effect of internal debt restructuring ⁽²⁾		(186,460	)		(45,182	)
Adjustments, assessments and other		6,241			1,644
Income tax expense (recovery)	$	(160,367	)	$	(25,362	)

	(1)	A deferred income tax asset of $13.6 million remains unrecognized due to uncertainty surrounding future capital gains (December 31, 2022-$14.4 million). The unrecognized deferred income tax asset relates to realized and unrealized foreign exchange losses arising from the repayment of previously issued U.S. dollar denominated long-term notes and from the translation of U.S. dollar denominated long-term notes currently outstanding.
	(2)	A deferred income tax asset has been recognized immediately after the closing of the Ranger acquisition due to effects of the transaction structuring.

As disclosed in the 2022 annual financial statements, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency (the “CRA”) in June 2016 that denied $591.0 million of non-capital loss deductions that relate to the calculation of income taxes for the years 2011 through 2015. In September 2016, Baytex filed notices of objection with the CRA appealing each reassessment received. In July 2023, Baytex received a letter from the Appeals Division of the CRA proposing to confirm the reassessments. Baytex remains confident that the original tax filings are correct and intends to defend these tax filings through the appeals process.

15. FINANCING AND INTEREST

	Three Months Ended June 30				Six Months Ended June 30
	2023		2022		2023		2022
Interest on Credit Facilities	$	7,535	$	4,070	$	13,751	$	7,109
Interest on long-term notes		20,565		16,356		32,659		33,700
Interest on lease obligations		155		48		220		92
Cash Interest	$	28,255	$	20,474	$	46,630	$	40,901
Amortization of debt issue costs		1,847		2,734		2,371		3,429
Accretion on asset retirement obligations (note 9)		4,395		3,869		9,221		6,991
Financing and interest	$	34,497	$	27,077	$	58,222	$	51,321

16. FOREIGN EXCHANGE

	Three Months Ended June 30					Six Months Ended June 30
	2023			2022		2023			2022
Unrealized foreign exchange gain - intercompany notes ⁽¹⁾	$	—		$	—	$	—		$	(2,674	)
Unrealized foreign exchange (gain) loss - long-term notes & Credit Facilities		(12,880	)		27,499		(13,093	)		15,625
Realized foreign exchange loss		941			210		1,091			413
Foreign exchange (gain) loss	$	(11,939	)	$	27,709	$	(12,002	)	$	13,364

(1)

Baytex had a series of intercompany notes totaling US$601.0 million outstanding at December 31, 2021 that were issued from a Canadian functional currency subsidiary to a U.S. functional currency subsidiary. These notes were eliminated upon consolidation within the Statement of Financial Position and were revalued at the relevant foreign exchange rate at each period end. Foreign exchange gains or losses incurred within the Canadian functional currency subsidiary were recognized in unrealized foreign exchange gain or loss whereas those within the U.S. functional currency subsidiary were recognized in other comprehensive income. In January 2022 the intercompany notes were transferred from the Canadian functional currency subsidiary to another U.S. functional currency subsidiary. As a result, foreign exchange gains and losses incurred on these notes after the transfer are recognized in other comprehensive income.

Baytex Energy Corp. Second Quarter Report 2023

17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company's financial assets and liabilities are comprised of cash, trade and other receivables, trade and other payables, financial derivatives, Credit Facilities, and long-term notes. The fair value of trade and other receivables and trade and other payables approximates carrying value due to the short term to maturity. The fair value of the Credit Facilities is equal to the principal amount outstanding as the Credit Facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.

The carrying value and fair value of the Company's financial instruments carried on the condensed consolidated statements of financial position are classified into the following categories:

	June 30, 2023						December 31, 2022
													Fair Value
													Measurement
	Carrying value			Fair value			Carrying value			Fair value			Hierarchy
Financial Assets
Fair value through profit and loss
Financial derivatives	$	27,505		$	27,505		$	10,105		$	10,105			Level 2
Total	$	27,505		$	27,505		$	10,105		$	10,105

Amortized cost
Cash	$	19,637		$	19,637		$	5,464		$	5,464			—
Trade and other receivables		370,498			370,498			228,485			228,485			—
Total	$	390,135		$	390,135		$	233,949		$	233,949

Financial Liabilities
Fair value through profit and loss
Financial derivatives	$	(2,907	)	$	(2,907	)	$	—		$	—			Level 2
Total	$	(2,907	)	$	(2,907	)	$	—		$	—

Amortized cost
Trade and other payables	$	(616,608	)	$	(616,608	)	$	(281,404	)	$	(281,404	)		—
Credit Facilities		(964,332	)		(986,903	)		(383,031	)		(385,394	)		—
Long-term notes		(1,563,897	)		(1,585,368	)		(547,598	)		(563,292	)		Level 1
Total	$	(3,144,837	)	$	(3,188,879	)	$	(1,212,033	)	$	(1,230,090	)

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2023 and 2022.

Foreign Currency Risk

The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:

Assets

Liabilities

June 30, 2023

December 31, 2022

June 30, 2023

December 31, 2022

U.S. dollar denominated

US$20,537

US$6,980

US$1,331,541

US$430,171

Baytex Energy Corp. Second Quarter Report 2023

Commodity Price Risk

Financial Derivative Contracts

Baytex had the following financial derivative contracts outstanding as of July 27, 2023:

	Remaining Period	Volume	Price/Unit ⁽¹⁾	Index
Oil
Basis differential ⁽²⁾	July 2023 to Dec 2023	1,500 bbl/d	WTI less US$2.50/bbl	MSW
Basis differential ⁽²⁾⁽³⁾	Jan 2024 to Dec 2024	1,500 bbl/d	WTI less US$2.65/bbl	MSW
Basis differential ⁽²⁾	July 2023 to Dec 2023	2,000 bbl/d	WTI less US$14.98/bbl	WCS
Basis differential ⁽²⁾	Aug 2023 to Dec 2023	6,000 bbl/d	WTI less US$13.62/bbl	WCS
			Baytex pays: WCS differential at Hardisty
Basis differential ⁽²⁾	July 2023 to Dec 2023	5,000 bbl/d	Baytex receives: WCS differential at Houston less US$8.10/bbl	WCS
Basis differential ⁽²⁾	Jan 2024 to Jun 2024	4,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.10/bbl	WCS
Put option	July 2023 to Dec 2023	5,000 bbl/d	US$60.00	WTI
Collar	July 2023 to Dec 2023	15,500 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2023 to Sep 2023	19,862 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2023 to Dec 2023	15,089 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Mar 2024	8,400 bbl/d	US$60.00/US$100.00	WTI
Collar	Apr 2024 to Jun 2024	1,750 bbl/d	US$60.00/US$100.00	WTI
Collar	Jan 2024 to Jun 2024	14,500 bbl/d	US$60.00/US$100.00	WTI
Collar ⁽³⁾	Jan 2024 to Jun 2024	2,500 bbl/d	US$60.00/US$90.00	WTI

Natural Gas
			Baytex pays: NYMEX	HSC IFERC
Basis differential ⁽²⁾	July 2023 to Dec 2023	11,413 mmbtu/d	Baytex receives: HSC less US$0.1525/mmbtu	FOM
Fixed Sell	Oct 2023 to Mar 2024	3,500 mmbtu/d	US$3.5025/mmbtu	NYMEX
Collar	July 2023 to Dec 2023	11,413 mmbtu/d	US$2.50/US$2.68	NYMEX
Collar	Jan 2024 to Mar 2024	11,538 mmbtu/d	US$2.50/US$3.65	NYMEX
Collar	Apr 2024 to Jun 2024	11,538 mmbtu/d	US$2.33/US$3.00	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.06	NYMEX
Collar	Jan 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.09	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.10	NYMEX
Collar	Jan 2024 to Dec 2024	8,500 mmbtu/d	US$3.00/US$4.15	NYMEX
Collar	Jan 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.19	NYMEX

Natural Gas Liquids
				Mt. Belvieu
				Non-TET
Fixed Sell	Jul 2023 to Mar 2024	34,364 gallon/d	US$0.2280/gallon	Ethane

	(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)	Contract entered subsequent to June 30, 2023.

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.

	Three Months Ended June 30						Six Months Ended June 30
	2023			2022			2023			2022
Realized financial derivatives (gain) loss	$	(16,365	)	$	124,042		$	(21,780	)	$	208,408
Unrealized financial derivatives (gain) loss		19,403			(58,768	)		10,193			97,493
Financial derivatives (gain) loss	$	3,038		$	65,274		$	(11,587	)	$	305,901

Baytex Energy Corp. Second Quarter Report 2023

18. CAPITAL MANAGEMENT

The Company's capital management objective is to maintain financial flexibility and sufficient sources of liquidity to execute its capital programs, while meeting short and long-term commitments. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At June 30, 2023, the Company's 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 its capital structure and liquidity, Baytex 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 Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of Adjusted Funds Flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity.

Net Debt

The Company uses net debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company defines net debt to be the sum 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. Baytex also uses net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.

The following table reconciles Net Debt to amounts disclosed in the primary financial statements.

	June 30, 2023			December 31, 2022
Credit Facilities	$	964,332		$	383,031
Unamortized debt issuance costs - Credit Facilities (note 7)		22,571			2,363
Long-term notes		1,563,897			547,598
Unamortized debt issuance costs - Long-term notes (note 8)		37,571			6,999
Trade and other payables		616,608			281,404
Cash		(19,637	)		(5,464	)
Trade and other receivables		(370,498	)		(228,485	)
Net Debt	$	2,814,844		$	987,446

Adjusted Funds Flow

Adjusted funds flow is used to monitor operating performance and the Company's 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 retirements obligations settled during the applicable period, transaction costs and cash premiums on derivatives.

Adjusted Funds Flow is reconciled to amounts disclosed in the primary financial statements in the following table.

	Three Months Ended June 30					Six Months Ended June 30
	2023		2022			2023		2022
Cash flows from operating activities	$	192,308	$	360,034		$	377,246	$	559,008
Change in non-cash working capital		40,795		(17,046	)		79,849		60,294
Asset retirement obligations settled		5,392		2,716			9,518		6,009
Transaction costs		32,832		—			41,703		—
Cash premiums on derivatives		2,263					2,263
Adjusted Funds Flow	$	273,590	$	345,704		$	510,579	$	625,311

Baytex Energy Corp. Second Quarter Report 2023

CORPORATE

INFORMATION

BOARD OF DIRECTORS

Mark R. Bly

Chairman of the Board

Eric T. Greager

Director

Tiffany (TJ) Thom Cepak

Director

Trudy M. Curran ^2,4

Director

Don G. Hrap ^1,3

Director

Angela S. Lekatsas ^1,4

Director

Jennifer A. Maki ^1,2

Director

David L. Pearce ^2,3

Director

Steve D.L. Reynish ^3,4

Director

Jeffrey E. Wojahn

Director

	(1)	Member of the Audit Committee
	(2)	Member of the Human Resources and Compensation Committee
	(3)	Member of the Reserves and Sustainability Committee
	(4)	Member of the Nominating and Governance Committee

HEAD OFFICE

Baytex Energy Corp.

Centennial Place, East Tower

2800, 520 - 3rd Avenue SW

Calgary, Alberta T2P 0R3

Toll-free 1.800.524.5521

T 587.952.3000

F 587.952.3001

WWW.BAYTEXENERGY.COM

OFFICERS

Eric T. Greager

President and

Chief Executive Officer

Chad L. Kalmakoff

Chief Financial Officer

Chad E. Lundberg

Chief Operating Officer

James R. Maclean

Chief Legal Officer and

Corporate Secretary

Brian G. Ector

Senior Vice President,

Capital Markets and Investor Relations

Kendall D. Arthur

Senior Vice President and

General Manager, Canadian

Heavy Oil Operations

Julia Gwaltney

Senior Vice President and

General Manager, U.S. Eagle

Ford Operations

Nicole M. Frechette

Vice President and General Manager,

Canadian Light Oil Operations

Chris Lessoway

Vice President, Finance

and Treasurer

Kayla D. Baird

Vice President, U.S. Accounting

and Corporate Services

AUDITORS

KPMG LLP

RESERVES ENGINEERS

McDaniel & Associates Consultants Ltd.

TRANSFER AGENT

Odyssey Trust Company

EXCHANGE LISTINGS

New York Stock Exchange

Toronto Stock Exchange

Symbol: BTE

Design: ARTHUR / HUNTER

Printing: Merrill Corporation

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Baytex Energy (PK) (USOTC:BTEGF)
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