Exhibit 99.1

 

BAYTEX ANNOUNCES SECOND QUARTER 2024 RESULTS

CALGARY, ALBERTA (July 25, 2024) - Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2024 (all amounts are in Canadian dollars unless otherwise noted).

"We delivered strong second quarter results with higher production, disciplined capital spending and meaningful free cash flow. Importantly and consistent with our full-year plan, we returned $97 million to shareholders through our share buyback program and quarterly dividend. In the Eagle Ford, we brought onstream one of our strongest performing oil-weighted pads to-date. As we continue to execute our plans for 2024, our free cash flow is expected to strengthen in the second half of the year allowing for increased shareholder returns and debt reduction," commented Eric T. Greager, President and Chief Executive Officer.

Highlights

· Generated production of 154,194 boe/d (85% oil and NGL) in Q2/2024, up 2% from Q1/2024. Crude oil production (light oil, condensate, and heavy oil) increased 4% from Q1/2024 to average 110,734 bbl/d.

· Increased production per basic share by 23% in Q2/2024, compared to Q2/2023.

· Reported cash flows from operating activities of $506 million ($0.62 per basic share) in Q2/2024.

· Delivered adjusted funds flow⁽¹⁾ of $533 million ($0.65 per basic share) in Q2/2024.

· Generated free cash flow⁽²⁾ of $181 million ($0.22 per basic share) in Q2/2024 and returned $97 million to shareholders.

· Repurchased 16.4 million common shares in Q2/2024 for $79 million, at an average price of $4.84 per share.

· Paid a quarterly cash dividend of $18 million ($0.0225 per share) on July 2, 2024.

· Executed a $340 million exploration and development program in Q2/2024, consistent with our full-year plan.

· Completed a US$575 million private placement offering of senior unsecured notes due 2032 that bear interest at a rate of 7.375% per annum and redeemed US$410 million aggregate principal amount of 8.75% outstanding notes.

· Extended the maturity of our US$1.1 billion credit facilities by two years to May 2028.

· Maintained balance sheet strength with a total debt⁽³⁾ to Bank EBITDA⁽³⁾ ratio of 1.1x.

2024 Guidance

We are focused on maintaining capital discipline and driving meaningful free cash flow. We are executing our 2024 development plan with a tightened production guidance range of 152,000 to 154,000 boe/d (150,000 to 156,000 boe/d, previously). Our 2024 exploration and development expenditures guidance is unchanged at $1.2 to $1.3 billion.

We expect to generate approximately $700 million of free cash flow⁽²⁾⁽⁴⁾ in 2024, weighted 75% to H2/2024. We intend to allocate 50% of free cash flow to the balance sheet and 50% to shareholder returns, which includes a combination of share buybacks and a quarterly dividend.

(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)	Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
(4)	Based on the mid-point of 2024 production and exploration and development expenditures guidance and the following full-year commodity price assumptions: WTI - US$78.50/bbl; WCS differential - US$16/bbl; NYMEX Gas - US$2.30/MMbtu; and Exchange Rate (CAD/USD) - 1.37.

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
	2024			2024			2023			2024			2023
FINANCIAL (thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales	$	1,133,123		$	984,192		$	598,760		$	2,117,315		$	1,154,096
Adjusted funds flow (1)		532,839			423,846			273,590			956,685			510,579
Per share – basic		0.65			0.52			0.47			1.17			0.90
Per share – diluted		0.65			0.52			0.47			1.16			0.90
Free cash flow (2)		180,673			(88	)		96,313			180,585			94,395
Per share – basic		0.22			—			0.17			0.22			0.17
Per share – diluted		0.22			—			0.16			0.22			0.17
Cash flows from operating activities		505,584			383,773			192,308			889,357			377,246
Per share – basic		0.62			0.47			0.33			1.09			0.67
Per share – diluted		0.62			0.47			0.33			1.08			0.66
Net income (loss)		103,898			(14,043	)		213,603			89,855			265,044
Per share – basic		0.13			(0.02	)		0.37			0.11			0.47
Per share – diluted		0.13			(0.02	)		0.36			0.11			0.47
Dividends declared		18,161			18,494			—			36,655			—
Per share		0.0225			0.0225			—			0.0450			—
Capital Expenditures
Exploration and development expenditures	$	339,573		$	412,551		$	170,704		$	752,124		$	404,330
Acquisitions and divestitures		654			35,378			(112	)		36,032			159
Total oil and natural gas capital expenditures	$	340,227		$	447,929		$	170,592		$	788,156		$	404,489
Net Debt
Credit facilities	$	625,976		$	849,926		$	986,903		$	625,976		$	986,903
Long-term notes		1,881,894			1,637,155			1,601,468			1,881,894			1,601,468
Total debt (3)		2,507,870			2,487,081			2,588,371			2,507,870			2,588,371
Working capital deficiency (2)		131,144			152,760			226,473			131,144			226,473
Net debt (1)	$	2,639,014		$	2,639,841		$	2,814,844		$	2,639,014		$	2,814,844
Shares Outstanding - basic (thousands)
Weighted average		814,151			821,710			583,365			817,931			564,319
End of period		804,977			821,322			862,192			804,977			862,192
BENCHMARK PRICES
Crude oil
WTI (US$/bbl)	$	80.57		$	76.96		$	73.78		$	78.77		$	74.96
MEH oil (US$/bbl)		83.10			78.95			75.01			81.03			76.22
MEH oil differential to WTI (US$/bbl)		2.53			1.99			1.23			2.26			1.26
Edmonton par ($/bbl)		105.30			92.16			95.13			98.73			97.09
Edmonton par differential to WTI (US$/bbl)		(3.62	)		(8.63	)		(2.95	)		(6.10	)		(2.91	)
WCS heavy oil ($/bbl)		91.72			77.73			78.85			84.68			74.16
WCS differential to WTI (US$/bbl)		(13.55	)		(19.33	)		(15.07	)		(16.44	)		(19.92	)
Natural gas
NYMEX (US$/MMbtu)	$	1.89		$	2.24		$	2.10		$	2.07		$	2.76
AECO ($/Mcf)		1.44			2.05			2.35			1.74			3.34
CAD/USD average exchange rate		1.3684			1.3488			1.3431			1.3586			1.3475

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)	Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

2  Baytex Energy Corp. Second Quarter Report 2024

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
	2024			2024			2023			2024			2023
OPERATING
Daily Production
Light oil and condensate (bbl/d)		67,031			66,036			35,322			66,534			33,510
Heavy oil (bbl/d)		43,703			40,560			32,821			42,131			33,502
NGL (bbl/d)		20,167			19,299			8,620			19,733			7,920
Total liquids (bbl/d)		130,901			125,895			76,763			128,398			74,932
Natural gas (Mcf/d)		139,764			148,353			77,989			144,059			80,017
Oil equivalent (boe/d @ 6:1) (1)		154,194			150,620			89,761			152,407			88,269
Netback (thousands of Canadian dollars)
Total sales, net of blending and other expense (2)	$	1,065,438		$	919,984		$	545,765		$	1,985,422		$	1,041,420
Royalties		(240,440	)		(209,171	)		(107,920	)		(449,611	)		(201,173	)
Operating expense		(167,705	)		(173,435	)		(119,438	)		(341,140	)		(231,846	)
Transportation expense		(33,314	)		(29,835	)		(14,574	)		(63,149	)		(31,579	)
Operating netback (2)	$	623,979		$	507,543		$	303,833		$	1,131,522		$	576,822
General and administrative		(21,006	)		(22,412	)		(15,240	)		(43,418	)		(26,974	)
Cash financing and interest		(53,946	)		(53,280	)		(28,255	)		(107,226	)		(46,630	)
Realized financial derivatives (loss) gain		(2,257	)		5,488			16,365			3,231			21,780
Other (3)		(13,931	)		(13,493	)		(3,113	)		(27,424	)		(14,419	)
Adjusted funds flow (4)	$	532,839		$	423,846		$	273,590		$	956,685		$	510,579
Netback (per boe) (2)
Total sales, net of blending and other expense (2)	$	75.93		$	67.12		$	66.82		$	71.58		$	65.18
Royalties (5)		(17.14	)		(15.26	)		(13.21	)		(16.21	)		(12.59	)
Operating expense (5)		(11.95	)		(12.65	)		(14.62	)		(12.30	)		(14.51	)
Transportation expense (5)		(2.37	)		(2.18	)		(1.78	)		(2.28	)		(1.98	)
Operating netback (2)	$	44.47		$	37.03		$	37.21		$	40.79		$	36.10
General and administrative (5)		(1.50	)		(1.64	)		(1.87	)		(1.57	)		(1.69	)
Cash financing and interest (5)		(3.84	)		(3.89	)		(3.46	)		(3.87	)		(2.92	)
Realized financial derivatives (loss) gain (5)		(0.16	)		0.40			2.00			0.12			1.36
Other (3)		(1.00	)		(0.98	)		(0.39	)		(0.98	)		(0.89	)
Adjusted funds flow (4)	$	37.97		$	30.92		$	33.49		$	34.49		$	31.96

Notes:

(1)	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.
(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)	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 Q2/2024 MD&A for further information on these amounts.
(4)	Capital management measure. Refer to the Specified Financial Measures section in this press release for further information.
(5)	Calculated as royalties, operating, transportation expense, general and administrative expense, cash interest expense or realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.

Baytex Energy Corp. Second Quarter Report 2024 3

During the second quarter, we delivered operating and financial results consistent with our full-year guidance. We remain committed to a disciplined, returns-based capital allocation philosophy intended to drive increased per-share returns. Our strong free cash flow forecast for 2024 reflects our stable production profile and the efficiency of our exploration and development program.

We increased production per basic share by 23% in Q2/2024, compared to Q2/2023, with production averaging 154,194 boe/d (85% oil and NGLs). Adjusted funds flow⁽¹⁾ was $533 million or $0.65 per basic share, 38% higher than $0.47 per basic share in Q2/2023, and we generated net income of $104 million ($0.13 per basic share). Exploration and development expenditures totaled $340 million and we brought 58 (39.8 net) wells onstream.

During the second quarter we generated free cash flow⁽²⁾ of $181 million ($0.22 per basic share) and returned $97 million to shareholders. We repurchased 16.4 million common shares for $79 million, at an average price of $4.84 per share, and paid a quarterly cash dividend of $18 million ($0.0225 per share).

During the last twelve months, we returned $378 million to shareholders. We repurchased 57.5 million common shares for $304 million, representing 6.7% of our shares outstanding, at an average price of $5.28 per share, and paid total dividends of $74 million ($0.09 per share).

On June 26, 2024, we renewed our Normal Course Issuer Bid ("NCIB") with the Toronto Stock Exchange for a share buyback program for up to 10% of our public float. The renewed NCIB allows Baytex to purchase up to 70 million common shares during the 12-month period commencing July 2, 2024 and ending July 1, 2025. For the period July 2, 2024 to July 25, 2024, we repurchased 4.8 million common shares for $24 million, at an average price of $5.00 per share.

During the second quarter, we extended our debt maturities and increased the liquidity on our credit facilities. On April 1, 2024, we closed a private placement offering of US$575 million aggregate principal amount of senior unsecured notes. The notes bear interest at a rate of 7.375% per annum and mature on March 15, 2032. Net proceeds from the offering were used to redeem US$409.8 million aggregate principal amount of outstanding 8.75% notes and the associated call premiums and repay a portion of the debt outstanding on our credit facilities. In addition, on May 9, 2024, we extended the maturity of our US$1.1 billion credit facilities to May 2028.

Our total debt⁽³⁾ at June 30, 2024 was $2.5 billion, largely unchanged from year-end 2023. Continuing to strengthen our balance sheet remains a priority. Based on our forecast free cash flow and shareholder return profile, we expect a reduction in total debt in the second half of 2024. The change in our total debt year-to-date reflects the strengthening U.S. dollar, relative to the Canadian dollar, on our U.S. dollar denominated debt (approximately $70 million), the call premium and issuance costs on our private placement offering and debt refinancing (approximately $50 million), and strategic land acquisitions (approximately $35 million). We are now forecasting interest expense for 2024 of $200 million, up from $190 million, previously.

We employ a disciplined commodity hedging program to help mitigate the volatility in revenue due to changes in commodity prices. For the second half of 2024, we have entered into hedges on approximately 40% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$93/bbl. For H1/2025, we have entered into hedges on approximately 35% of our net crude oil exposure utilizing two-way collars with an average floor price of US$60/bbl and an average ceiling price of US$91/bbl. A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2024 financial statements.

Operations

In the Eagle Ford, we continue to deliver strong results across the black oil, volatile oil and condensate windows of our acreage. We generated production of 90,506 boe/d (82% oil and NGL) in Q2/2024. During the second quarter, we brought 11 (10.7 net) operated Lower Eagle Ford wells onstream that were largely focused on the black oil window. We brought onstream one of our strongest performing oil-weighted pads to-date (3-wells, Pluto A1H, B2H and D4H) with the wells generating an average 30-day peak production rate of 1,348 boe/d per well (1,161 bbl/d of crude oil, 104 bbl/d of NGLs, 500 Mcf/d of natural gas).

In aggregate, 8 of 11 wells brought onstream during the second quarter were on production for a sufficient amount of time to establish 30-day peak production rates. These wells generated an average 30-day peak production rate of 1,022 boe/d per well (892 bbl/d of crude oil, 72 bbl/d of NGLs, 349 Mcf/d of natural gas). Due to efficient drilling and completion activities, in the first half of 2024 we realized an 8% improvement in operated drilling and completion costs per completed lateral foot over 2023. On our non-operated Eagle Ford acreage, we brought 19 (4.1 net) wells onstream.

(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)	Calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.

4  Baytex Energy Corp. Second Quarter Report 2024

We are focused on optimizing our acreage and continue to identify Upper Eagle Ford development areas. Our 2024 program includes four Upper Eagle Ford wells. The first three wells were brought onstream in Q1/2024 and continue to deliver strong results. The fourth well was brought onstream in July. In addition, following our successful Q1/2024 Lower Eagle Ford refrac (Medina Unit 3H), we are evaluating additional refrac opportunities to supplement our 2025 capital program.

In our Canadian light oil business unit, the first pad (3-wells) from our 2024 Duvernay program was brought onstream in May and generated an average 30-day peak production rate of 1,350 boe/d per well (890 bbl/d of crude oil, 326 bbl/d of NGLs, 825 Mcf/d of natural gas). These initial results are consistent with expectations. The second pad (4-wells) is expected to be onstream in August. In the Viking, activity resumed in late June following spring breakup.

In our heavy oil business unit, second quarter activity is typically lower due to spring breakup. Peavine continued to outperform expectations with production averaging 19,938 bbl/d (100% heavy oil) during the second quarter, up 13% from Q1/2024. In Q2/2024, we brought 4 (4.0 net) wells onstream at Peavine that generated an average 30-day peak production rate of 760 bbl/ d per well (100% heavy oil). Following spring breakup, our heavy oil development program has ramped up with four rigs running across our Peavine, Peace River and Lloydminster regions.

Quarterly Dividend

The Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2024 to shareholders of record on September 16, 2024.

2023 ESG Report

On June 20, 2024, the Canadian government passed amendments to the Competition Act that creates uncertainty for companies that wish to publicly communicate their environmental goals, targets and performance. As it is unclear how the new law will be interpreted and enforced, and given the significant potential penalties associated with non-compliance, we have deferred the publication of our 2023 ESG report.

This legislation does not change our commitment to our environmental goals and to ensuring safe, responsible operations. We are proud of the work we have done with respect to GHG emissions and air quality, asset retirement, reclamation and water management. We remain committed to moving these items forward.

As more guidance regarding the implementation of this new law becomes available, we look forward to sharing our progress.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2024 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.sedarplus.ca and EDGAR at www.sec.gov/edgar.shtml.

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: our expectation that free cash flow will increase in the second half of 2024 allowing for increased shareholder returns and debt reduction; for 2024: our guidance for exploration and development expenditures and production, the amount of free cash flow we expect to generate based on the forward strip and our expected allocation of that free cash flow as between the balance sheet and shareholder returns (including share buybacks and quarterly dividends); that we are committed to a disciplined, returns-based capital allocation philosophy to drive increased per-share returns; our expectation that we will reduce our total debt during H2/2024; our forecast interest rate expense for 2024; our commodity hedging program, the percentage of our 2024 net crude exposure that is hedged, and the ability of such program to mitigate revenue volatility due to changes in commodity prices; well completion plans for the Duvernay; and that we will share progress with respect to ESG matters. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that they can be profitably produced in the future.

Baytex Energy Corp. Second Quarter Report 2024 5

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

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; risks associated with achieving our total debt target, production guidance, exploration and development expenditures guidance; the amount of free cash flow we expect to generate; risk that the board of directors determines to allocate capital other than as set forth herein; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; 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; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risk that we do not achieve our GHG emissions intensity reduction target; risks associated with our use of information technology systems; adverse 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 associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Corporation and its directors and officers; variability of share buybacks and dividends; 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. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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, 2023 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.

This press release contains information that may be considered a financial outlook under applicable securities laws about the Corporation's potential financial position, including, but not limited to, our 2024 guidance for development expenditures; our expected 2024 free cash flow; and our intentions regarding the allocating our annual free cash flow; all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Corporation and the resulting financial results 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, the Corporation undertakes no obligation to update such financial outlook, whether as a result of new information, future events or otherwise. 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 the Corporation's potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.

The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Corporation'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 (including covenants contained in the agreements governing any indebtedness that the Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future.

Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board of Directors of Baytex.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

6  Baytex Energy Corp. Second Quarter Report 2024

Specified Financial Measures

In this press release, we refer to certain financial measures (such as free cash flow, operating netback, working capital deficiency, 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 gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This press release also contains the terms "adjusted funds flow" and "net debt" which are considered capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.

Non-GAAP Financial Measures

Total sales, net of blending and other expense

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

Operating netback

Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales less blending expense, royalties, operating expense and transportation expense.

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

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
($ thousands)	2024			2024			2023			2024			2023
Petroleum and natural gas sales	$	1,133,123		$	984,192		$	598,760		$	2,117,315		$	1,154,096
Blending and other expense		(67,685	)		(64,208	)		(52,995	)		(131,893	)		(112,676	)
Total sales, net of blending and other expense	$	1,065,438		$	919,984		$	545,765		$	1,985,422		$	1,041,420
Royalties		(240,440	)		(209,171	)		(107,920	)		(449,611	)		(201,173	)
Operating expense		(167,705	)		(173,435	)		(119,438	)		(341,140	)		(231,846	)
Transportation expense		(33,314	)		(29,835	)		(14,574	)		(63,149	)		(31,579	)
Operating netback	$	623,979		$	507,543		$	303,833		$	1,131,522		$	576,822
Realized financial derivatives (loss) gain (1)		(2,257	)		5,488			16,365			3,231			21,780
Operating netback after realized financial derivatives	$	621,722		$	513,031		$	320,198		$	1,134,753		$	598,602

(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, 2024 and the consolidated financial statements for the three months ended March 31, 2024 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, transaction costs and cash premiums on derivatives.

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

	Three Months Ended									Six Months Ended
	June 30,			March 31,			June 30,			June 30,			June 30,
($ thousands)	2024			2024			2023			2024			2023
Cash flows from operating activities	$	505,584		$	383,773		$	192,308		$	889,357		$	377,246
Change in non-cash working capital		20,140			32,023			40,795			52,163			79,849
Additions to exploration and evaluation assets		—			—			(741	)		—			(1,231	)
Additions to oil and gas properties		(339,573	)		(412,551	)		(169,963	)		(752,124	)		(403,099	)
Payments on lease obligations		(5,478	)		(4,872	)		(1,181	)		(10,350	)		(2,336	)
Transaction costs		—			1,539			32,832			1,539			41,703
Cash premiums on derivatives		—			—			2,263			—			2,263
Free cash flow	$	180,673		$	(88	)	$	96,313		$	180,585		$	94,395

Baytex Energy Corp. Second Quarter Report 2024 7

Working capital deficiency

Working capital deficiency is calculated as cash, trade receivables, prepaids and other assets net of trade payables, dividends payable, other long-term liabilities and share-based compensation liability. Working capital deficiency is used by management to measure the Company's liquidity. At June 30, 2024, the Company had $874.9 million of available credit facility capacity to cover any working capital deficiencies.

The following table summarizes the calculation of working capital deficiency.

	As at
($ thousands)	June 30, 2024			March 31, 2024			December 31, 2023
Cash	$	(35,887	)	$	(29,140	)	$	(55,815	)
Trade receivables		(429,098	)		(423,119	)		(339,405	)
Prepaids and other assets		(81,805	)		(77,901	)		(83,259	)
Trade payables		617,222			626,137			477,295
Share-based compensation liability		22,706			18,667			35,732
Other long-term liabilities		19,845			19,622			19,147
Dividends payable		18,161			18,494			18,381
Working capital deficiency	$	131,144		$	152,760		$	72,076

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 (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 equal to operating netback (a non-GAAP financial measure) 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 also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash, trade receivables, and prepaids and other assets.

8  Baytex Energy Corp. Second Quarter Report 2024

The following table summarizes our calculation of net debt.

	As at
($ thousands)	June 30, 2024			March 31, 2024			December 31, 2023
Credit facilities	$	607,589		$	835,363		$	848,749
Unamortized debt issuance costs - Credit facilities (1)		18,387			14,563			15,987
Long-term notes		1,833,182			1,602,417			1,562,361
Unamortized debt issuance costs - Long-term notes (1)		48,712			34,738			35,114
Trade payables		617,222			626,137			477,295
Share-based compensation liability		22,706			18,667			35,732
Other long-term liabilities		19,845			19,622			19,147
Dividends payable		18,161			18,494			18,381
Cash		(35,887	)		(29,140	)		(55,815	)
Trade receivables		(429,098	)		(423,119	)		(339,405	)
Prepaids and other assets		(81,805	)		(77,901	)		(83,259	)
Net debt	$	2,639,014		$	2,639,841		$	2,534,287

(1) Unamortized debt issuance costs for the respective periods 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, 2024 and the consolidated financial statements for the three months ended March 31, 2024.

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, transaction costs and cash premiums on derivatives during the applicable period.

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

	Three Months Ended						Six Months Ended
($ thousands)	June 30, 2024		March 31, 2024		June 30, 2023		June 30, 2024		June 30, 2023
Cash flow from operating activities	$	505,584	$	383,773	$	192,308	$	889,357	$	377,246
Change in non-cash working capital		20,140		32,023		40,795		52,163		79,849
Asset retirement obligations settled		7,115		6,511		5,392		13,626		9,518
Transaction costs		—		1,539		32,832		1,539		41,703
Cash premiums on derivatives		—		—		2,263		—		2,263
Adjusted funds flow	$	532,839	$	423,846	$	273,590	$	956,685	$	510,579

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 peak 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.

Baytex Energy Corp. Second Quarter Report 2024 9

Throughout this press release, “oil and NGL” refers to heavy crude oil, bitumen, light and medium crude 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, 2024. 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, 2024										Three Months Ended June 30, 2023
			Light										Light
			and										and
	Heavy		Medium				Natural		Oil		Heavy		Medium				Natural		Oil
	Crude Oil		Crude Oil		NGL		Gas		Equivalent		Crude Oil		Crude Oil		NGL		Gas		Equivalent
	(bbl/d)		(bbl/d)		(bbl/d)		(Mcf/d)		(boe/d)		(bbl/d)		(bbl/d)		(bbl/d)		(Mcf/d)		(boe/d)
Canada – Heavy
Peace River		9,116		7		41		10,733		10,953		9,801		6		49		11,117		11,708
Lloydminster		13,688		16		—		1,607		13,972		11,398		23		—		1,228		11,625
Peavine		19,938		—		—		—		19,938		11,622		—		—		—		11,622
Canada - Light
Viking		—		8,130		181		10,586		10,075		—		13,265		181		12,105		15,464
Duvernay		—		2,509		1,640		5,875		5,128		—		675		566		1,946		1,565
Remaining Properties		961		414		447		10,798		3,622		—		643		638		15,647		3,890
United States
Eagle Ford		—		55,955		17,858		100,165		90,506		—		20,710		7,186		35,946		33,887
Total		43,703		67,031		20,167		139,764		154,194		32,821		35,322		8,620		77,989		89,761

	Six Months Ended June 30, 2024										Six Months Ended June 30, 2023
			Light										Light
			and										and
	Heavy		Medium				Natural		Oil		Heavy		Medium				Natural		Oil
	Crude Oil		Crude Oil		NGL		Gas		Equivalent		Crude Oil		Crude Oil		NGL		Gas		Equivalent
	(bbl/d)		(bbl/d)		(bbl/d)		(Mcf/d)		(boe/d)		(bbl/d)		(bbl/d)		(bbl/d)		(Mcf/d)		(boe/d)
Canada – Heavy
Peace River		9,299		8		44		10,411		11,086		10,289		9		51		11,191		12,215
Lloydminster		13,422		15		—		1,519		13,690		11,522		17		—		1,223		11,743
Peavine		18,768		—		—		—		18,768		11,691		—		—		—		11,691
Canada - Light
Viking		—		8,655		185		10,827		10,645		—		13,948		187		11,864		16,113
Duvernay		—		2,156		1,699		5,665		4,799		—		868		754		2,283		2,002
Remaining Properties		642		451		542		13,568		3,896		—		658		661		19,001		4,485
United States
Eagle Ford		—		55,249		17,263		102,069		89,523		—		18,010		6,267		34,455		30,020
Total		42,131		66,534		19,733		144,059		152,407		33,502		33,510		7,920		80,017		88,269

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 & Investor Relations

Toll Free Number: 1-800-524-5521

Email: investor@baytexenergy.com

10  Baytex Energy Corp. Second Quarter Report 2024

BAYTEX ENERGY CORP.

Management’s Discussion and Analysis

For the three and six months ended June 30, 2024 and 2023

Dated July 25, 2024

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, 2024. This information is provided as of July 25, 2024. 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, 2024 ("Q2/2024" and "YTD 2024") have been compared with the results for the three and six months ended June 30, 2023 ("Q2/2023" and "YTD 2023"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three and six months ended June 30, 2024, its audited comparative consolidated financial statements for the years ended December 31, 2023 and 2022, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2023. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca 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 oil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operated assets in Texas.

On June 20, 2023, Baytex and Ranger Oil Corporation ("Ranger") completed a merger of the two companies (the "Merger") whereby Baytex acquired all of the issued and outstanding common shares of Ranger. The Merger increased our Eagle Ford scale and provided an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford. Production from the Ranger assets is approximately 80% weighted towards high netback light oil and liquids and is primarily operated which increased our ability to effectively allocate capital.

We issued 311.4 million common shares, paid $732.8 million in cash and assumed $1.1 billion of Ranger's net debt⁽¹⁾. The cash portion of the transaction was funded with an expanded US$1.1 billion credit facility, a US$150 million two-year term loan facility (which was fully repaid and cancelled in August 2023) and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030.

SECOND QUARTER HIGHLIGHTS

Baytex delivered strong operating and financial results in Q2/2024. Production of 154,194 boe/d for Q2/2024 reflects our successful development programs in the U.S. and Canada. We invested $339.6 million on exploration and development expenditures and generated free cash flow⁽²⁾ of $180.7 million.

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

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

Baytex Energy Corp. Second Quarter Report 2024 11

Exploration and development expenditures totaled $339.6 million in Q2/2024. In the U.S. we invested $237.7 million and production averaged 90,506 boe/d during Q2/2024 compared to exploration and development expenditures of $74.3 million and production of 33,887 boe/d for Q2/2023. The increase in U.S. exploration and development spending and production in Q2/2024 relative to Q2/2023 is primarily the result of the Merger. In Canada, we invested $101.9 million in Q2/2024 and generated production of 63,688 boe/d in Q2/2024 compared to exploration and development expenditures of $96.4 million and production of 55,874 boe/d in Q2/2023 which reflects our successful light and heavy oil development program.

Oil prices improved during Q2/2024 as a result of stable supply and demand, continued OPEC production curtailments and geopolitical tension. The WTI benchmark price for Q2/2024 was US$80.57/bbl which was higher than Q2/2023 when WTI averaged US$73.78/bbl. Adjusted funds flow⁽¹⁾ of $532.8 million and cash flows from operating activities of $505.6 million for Q2/2024 reflect higher production compared to Q2/2023 when we generated adjusted funds flow of $273.6 million and cash flows from operating activities of $192.3 million.

Net debt⁽¹⁾ of $2.6 billion at June 30, 2024 was consistent with $2.5 billion at December 31, 2023 which was due to the impact of a weaker Canadian dollar at June 30, 2024 on our U.S. dollar denominated debt and also reflects $38.8 million of property acquisitions along with $49.7 million of debt issuance costs incurred during YTD 2024. We expect net debt to decline over the remainder of 2024 as we continue to allocate 50% of free cash flow to the balance sheet.

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

2024 GUIDANCE

Our 2024 annual guidance has been revised with a tightened production guidance range of 152,000 - 154,000 boe/d. We are now forecasting interest expense for 2024 of $200 million ($3.57/boe), up from $190 million ($3.40/boe), previously. Our annual exploration and development expenditures guidance is unchanged at $1.2 - $1.3 billion.

	Previous Annual Guidance (1)	Revised Annual Guidance	YTD 2024 Results
Exploration and development expenditures	$1.2 - $1.3 billion	No change	$752.1 million
Production (boe/d)	150,000 - 156,000	152,000 - 154,000	152,407
Expenses:
Average royalty rate (2)	23%	No change	22.6%
Operating (3)	$11.25 - $12.00/boe	No change	$12.30/boe
Transportation (3)	$2.35 - $2.55/boe	No change	$2.28/boe
General and administrative (3)	$92 million ($1.65/boe)	No change	$43.4 million ($1.57/boe)
Cash interest (3)	$190 million ($3.40/boe)	$200 million ($3.57/boe)	$107.2 million ($3.87/boe)
Current income tax (4)	$40 million ($0.72/boe)	No change	$8.2 million ($0.29/boe)
Leasing expenditures	$12 million	No change	$10.4 million
Asset retirement obligations	$30 million	No change	$13.6 million

(1)	As announced on December 6, 2023.
(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.
(4)	Current income tax expense per boe is calculated as current income tax expense divided by barrels of oil equivalent production volume for the applicable period.

12  Baytex Energy Corp. Second Quarter Report 2024

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 operated and non-operated Eagle Ford assets in Texas.

Production

	Three Months Ended June 30
	2024									2023
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		11,076			55,955			67,031			14,612			20,710			35,322
Heavy oil		43,703			—			43,703			32,821			—			32,821
Natural Gas Liquids (NGL)		2,309			17,858			20,167			1,434			7,186			8,620
Total liquids (bbl/d)		57,088			73,813			130,901			48,867			27,896			76,763
Natural gas (mcf/d)		39,599			100,165			139,764			42,043			35,946			77,989
Total production (boe/d)		63,688			90,506			154,194			55,874			33,887			89,761
Production Mix
Segment as a percent of total		41	%		59	%		100	%		62	%		38	%		100	%
Light oil and condensate		17	%		62	%		44	%		26	%		61	%		39	%
Heavy oil		69	%		—	%		28	%		59	%		—	%		37	%
NGL		4	%		20	%		13	%		3	%		21	%		10	%
Natural gas		10	%		18	%		15	%		12	%		18	%		14	%

	Six Months Ended June 30
	2024									2023
	Canada			U.S.			Total			Canada			U.S.			Total
Daily Production
Liquids (bbl/d)
Light oil and condensate		11,285			55,249			66,534			15,500			18,010			33,510
Heavy oil		42,131			—			42,131			33,502			—			33,502
Natural Gas Liquids (NGL)		2,470			17,263			19,733			1,653			6,267			7,920
Total liquids (bbl/d)		55,886			72,512			128,398			50,655			24,277			74,932
Natural gas (mcf/d)		41,990			102,069			144,059			45,562			34,455			80,017
Total production (boe/d)		62,884			89,523			152,407			58,249			30,020			88,269
Production Mix
Segment as a percent of total		41	%		59	%		100	%		66	%		34	%		100	%
Light oil and condensate		18	%		62	%		44	%		27	%		60	%		38	%
Heavy oil		67	%		—	%		28	%		58	%		—	%		38	%
NGL		4	%		19	%		13	%		3	%		21	%		9	%
Natural gas		11	%		19	%		15	%		12	%		19	%		15	%

Production was 154,194 boe/d for Q2/2024 and 152,407 boe/d for YTD 2024 compared to 89,761 boe/d for Q2/2023 and 88,269 boe/d for YTD 2023. Production for Q2/2024 and YTD 2024 was higher than the same periods of 2023 primarily due to production from the Eagle Ford properties acquired from Ranger along with our successful development program in Canada.

Baytex Energy Corp. Second Quarter Report 2024 13

In Canada, production was 63,688 boe/d for Q2/2024 and 62,884 boe/d for YTD 2024 compared to 55,874 boe/d for Q2/2023 and 58,249 boe/d for YTD 2023. Strong production results from our successful light and heavy oil development programs resulted in a 7,814 boe/d increase in production for Q2/2024 and 4,635 boe/d for YTD 2024 relative to the same periods of 2023. Higher production from our heavy oil development was partially offset by the disposition of non-core light oil Viking assets in December 2023.

In the U.S., production was 90,506 boe/d for Q2/2024 and 89,523 boe/d for YTD 2024 compared to 33,887 boe/d for Q2/2023 and 30,020 boe/d for YTD 2023. Production from the Merger with Ranger was the primary factor that resulted in a 56,619 boe/d increase in production for Q2/2024 and 59,503 boe/d increase in production for YTD 2024 relative to the same periods of 2023, respectively. Production from the acquired Eagle Ford assets is primarily operated and is weighted towards light oil which resulted in a higher proportion of our total production being light oil in 2024.

Total production of 152,407 boe/d for YTD 2024 is consistent with expectations and our revised annual guidance of 152,000 - 154,000 boe/d.

COMMODITY PRICES

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

Crude Oil

Global benchmark pricing for crude oil improved during Q2/2024 and YTD 2024 due to stable supply and demand and continued OPEC production curtailments along with ongoing geopolitical tension. The WTI benchmark price averaged US$80.57/bbl for Q2/2024 and US$78.77/bbl for YTD 2024 compared to US$73.78/bbl for Q2/2023 and US$74.96/bbl for YTD 2023.

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$83.10/bbl during Q2/2024 and US$81.03/bbl during YTD 2024 which is higher than US$75.01/bbl for Q2/2023 and US$76.22/bbl for YTD 2023. The MEH benchmark typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark premium to WTI was US$2.53/bbl and US$2.26/bbl for Q2/2024 and YTD 2024 compared to premiums of US$1.23/bbl and US$1.26/bbl for Q2/2023 and YTD 2023, respectively. The MEH benchmark traded at a higher premium to WTI in both periods of 2024 as a result of additional demand at the U.S. Gulf Coast.

Prices for Canadian oil trade at a discount to WTI due to a lack of egress to diversified markets from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada. Canadian oil differentials narrowed during Q2/2024 after exports commenced from the TMX pipeline expansion in May. Delays in the TMX expansion resulted in increased pipeline apportionment and reduced the available capacity to transport light and heavy crude oil out of the Western Canadian Sedimentary Basin earlier in 2024, which caused differentials to be wider for YTD 2024.

We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $105.30/bbl during Q2/2024 and $98.73/bbl during YTD 2024 compared to $95.13/bbl during Q2/2023 and $97.09/ bbl during YTD 2023. Edmonton par traded at a discount to WTI of US$3.62/bbl for Q2/2024 and US$6.10/bbl for YTD 2024 compared to a discount of US$2.95/bbl for Q2/2023 and US$2.91/bbl for YTD 2023.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q2/2024 and YTD 2024 averaged $91.72/bbl and $84.68/bbl respectively, compared to $78.85/bbl and $74.16/bbl for the same periods of 2023. The WCS heavy oil differential to WTI was US$13.55/bbl in Q2/2024 and US$16.44/bbl in YTD 2024 compared to US$15.07/bbl for Q2/2023 and US$19.92/bbl in YTD 2023 which was impacted by refinery turnarounds and additional supply from Strategic Petroleum Reserve releases by the U.S. government.

Natural Gas

Natural gas prices in Canada and the U.S. were lower in 2024 relative to 2023 after mild winter weather across most of North America resulted in weak natural gas demand and elevated inventory levels.

Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$1.89/mmbtu for Q2/2024 and US$2.07/mmbtu for YTD 2024 compared to US$2.10/ mmbtu for Q2/2023 and US$2.76/mmbtu for YTD 2023.

In Canada, we receive natural gas pricing based on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $1.44/mcf during Q2/2024 and $1.74/ mcf during YTD 2024 which is lower than $2.35/mcf for Q2/2023 and $3.34/mcf for YTD 2023.

14  Baytex Energy Corp. Second Quarter Report 2024

The following tables compare select benchmark prices and our average realized selling prices for the three and six months ended June 30, 2024 and 2023.

	Three Months Ended June 30									Six Months Ended June 30
	2024			2023			Change			2024			2023			Change
Benchmark Averages
WTI oil (US$/bbl) (1)		80.57			73.78			6.79			78.77			74.96			3.81
MEH oil (US$/bbl) (2)		83.10			75.01			8.09			81.03			76.22			4.81
MEH oil differential to WTI (US$/bbl)		2.53			1.23			1.30			2.26			1.26			1.00
Edmonton par oil ($/bbl) (3)		105.30			95.13			10.17			98.73			97.09			1.64
Edmonton par oil differential to WTI (US$/bbl)		(3.62	)		(2.95	)		(0.67	)		(6.10	)		(2.91	)		(3.19	)
WCS heavy oil ($/bbl) (4)		91.72			78.85			12.87			84.68			74.16			10.52
WCS heavy oil differential to WTI (US$/bbl)		(13.55	)		(15.07	)		1.52			(16.44	)		(19.92	)		3.48
AECO natural gas ($/mcf) (5)		1.44			2.35			(0.91	)		1.74			3.34			(1.60	)
NYMEX natural gas (US$/mmbtu) (6)		1.89			2.10			(0.21	)		2.07			2.76			(0.69	)
CAD/USD average exchange rate		1.3684			1.3431			0.0253			1.3586			1.3475			0.0111

(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
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	103.21	$	109.71	$	108.64	$	93.98	$	97.55	$	96.07
Heavy oil, net of blending and other expense ($/bbl) (2)		82.29		—		82.29		66.45		—		66.45
NGL ($/bbl) (1)		24.48		27.30		26.98		28.92		25.07		25.71
Natural gas ($/mcf) (1)		1.23		2.37		2.04		2.64		2.52		2.58
Total sales, net of blending and other expense ($/boe) (2)	$	76.07	$	75.83	$	75.93	$	66.34	$	67.60	$	66.82

	Six Months Ended June 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Average Realized Sales Prices
Light oil and condensate ($/bbl) (1)	$	97.02	$	105.87	$	104.37	$	96.74	$	99.96	$	98.47
Heavy oil, net of blending and other expense ($/bbl) (2)		74.07		—		74.07		58.69		—		58.69
NGL ($/bbl) (1)		25.61		26.71		26.57		32.86		28.35		29.29
Natural gas ($/mcf) (1)		1.86		2.37		2.22		3.12		3.23		3.17
Total sales, net of blending and other expense ($/boe) (2)	$	69.29	$	73.19	$	71.58	$	62.91	$	69.60	$	65.18

(1)	Calculated as light oil and condensate or NGL sales divided by barrels of oil equivalent production volume for the applicable period, or natural gas sales divided by the production volume in Mcf 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 2024 15

Average Realized Sales Prices

Our total sales, net of blending and other expense per boe⁽¹⁾ was $75.93/boe for Q2/2024 and $71.58/boe for YTD 2024 compared to $66.82/boe for Q2/2023 and $65.18/boe for YTD 2023. In Canada, our realized price of $76.07/boe for Q2/2024 was $9.73/boe higher than $66.34/boe for Q2/2023. Our realized price in the U.S. was $75.83/boe in Q2/2024 which is $8.23/boe higher than $67.60/boe in Q2/2023. The increase in North American benchmark prices was the primary factor that resulted in higher realized pricing for our operations in Canada and the U.S. in Q2/2024 and YTD 2024 relative to the same periods of 2023.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price⁽²⁾ was $103.21/bbl for Q2/2024 and $97.02/bbl for YTD 2024 compared to $93.98/bbl for Q2/2023 and $96.74/bbl for YTD 2023. Our realized light oil and condensate price represents a discount to the Edmonton par price of $2.09/bbl for Q2/2024 and $1.71/bbl for YTD 2024 compared to a discount of $1.15/bbl in Q2/2023 and $0.35/bbl for YTD 2023. We realized a slightly wider discount to the Edmonton par price in both periods of 2024 relative to 2023 due to temporary pricing adjustments related to new Duvernay production that did not meet certain specifications at the sales point.

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 $109.71/bbl for Q2/2024 and $105.87/bbl for YTD 2024 compared to $97.55/bbl for Q2/2023 and $99.96/bbl for YTD 2023. Expressed in U.S. dollars, our realized light oil and condensate price of US$80.17/bbl for Q2/2024 and US$77.93/bbl for YTD 2024 represent discounts to MEH of US$2.93/bbl and US$3.10/bbl for Q2/2024 and YTD 2024 respectively, compared to discounts of US$2.38/bbl for Q2/2023 and US$2.04/bbl for YTD 2023 and reflect the realized pricing on our operated Eagle Ford production acquired from Ranger.

Our realized heavy oil price, net of blending and other expense⁽¹⁾ was $82.29/bbl in Q2/2024 and $74.07/bbl for YTD 2024 compared to $66.45/bbl in Q2/2023 and $58.69/bbl for YTD 2023. Our realized heavy oil, net of blending and other expense for Q2/2024 and YTD 2024 was $15.84/bbl and $15.38/bbl higher than Q2/2023 and YTD 2023 respectively, compared to a $12.87/bbl and $10.52/bbl increase in the WCS benchmark price over the same periods. Our realized price increased more than the benchmark price as the cost of condensate purchased for blending was lower relative to the price received for sales of the blended product based on the WCS benchmark in both periods of 2024 compared to 2023.

Our realized NGL price as a percentage of WTI varies 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 $26.98/bbl in Q2/2024 or 24% of WTI (expressed in Canadian dollars) and $26.57/bbl in YTD 2024 or 25% of WTI (expressed in Canadian dollars), compared to $25.71/bbl or 26% of WTI (expressed in Canadian dollars) in Q2/2023 and $29.29/bbl or 29% of WTI (expressed in Canadian dollars) in YTD 2023. Our realized NGL price was slightly lower as a percentage of WTI in both periods of 2024 primarily due to lower demand for NGL products relative to 2023.

We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. In the U.S., our realized natural gas price⁽²⁾ was US$1.73/mcf for Q2/2024 and US$1.74/mcf for YTD 2024 compared to US$1.88/mcf for Q2/2023 and US$2.40/mcf for YTD 2023 which is consistent with the decrease in the NYMEX benchmark over the same period. In Canada our realized natural gas price was $1.23/mcf for Q2/2024 and $1.86/mcf for YTD 2024 compared to $2.64/mcf in Q2/2023 and $3.12/mcf for YTD 2023. The decrease in our realized price for Q2/2024 relative to Q2/2023 was more than the decrease in the AECO benchmark as a greater proportion of our sales were based on the daily AECO index which was lower than the monthly AECO index. The decrease in our realized price for YTD 2024 relative to YTD 2023 was lower than the decrease in the AECO benchmark as the daily AECO index was higher than the monthly AECO index during Q1/2024.

(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 or NGL sales divided by barrels of oil equivalent production volume for the applicable period, or natural gas sales divided by the production volume in Mcf for the applicable period.

16  Baytex Energy Corp. Second Quarter Report 2024

PETROLEUM AND NATURAL GAS SALES

	Three Months Ended June 30
	2024								2023
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	104,030		$	558,620	$	662,650		$	124,965		$	183,845	$	308,810
Heavy oil		394,960			—		394,960			251,449			—		251,449
NGL		5,144			44,366		49,510			3,772			16,391		20,163
Total oil sales		504,134			602,986		1,107,120			380,186			200,236		580,422
Natural gas sales		4,426			21,577		26,003			10,106			8,232		18,338
Total petroleum and natural gas sales		508,560			624,563		1,133,123			390,292			208,468		598,760
Blending and other expense		(67,685	)		—		(67,685	)		(52,995	)		—		(52,995	)
Total sales, net of blending and other expense (1)	$	440,875		$	624,563	$	1,065,438		$	337,297		$	208,468	$	545,765

	Six Months Ended June 30
	2024								2023
($ thousands)	Canada			U.S.		Total			Canada			U.S.		Total
Oil sales
Light oil and condensate	$	199,251		$	1,064,514	$	1,263,765		$	271,420		$	325,855	$	597,275
Heavy oil		699,884			—		699,884			468,534			—		468,534
NGL		11,513			83,928		95,441			9,832			32,165		41,997
Total oil sales		910,648			1,148,442		2,059,090			749,786			358,020		1,107,806
Natural gas sales		14,225			44,000		58,225			26,128			20,162		46,290
Total petroleum and natural gas sales		924,873			1,192,442		2,117,315			775,914			378,182		1,154,096
Blending and other expense		(131,893	)		—		(131,893	)		(112,676	)		—		(112,676	)
Total sales, net of blending and other expense (1)	$	792,980		$	1,192,442	$	1,985,422		$	663,238		$	378,182	$	1,041,420

(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 $1.1 billion for Q2/2024 increased $519.7 million from $545.8 million reported for Q2/2023, while total sales, net of blending and other expense of $2.0 billion for YTD 2024 increased from $1.0 billion reported for YTD 2023. The increase in total sales for both periods of 2024 is primarily the result of the Merger with Ranger along with higher production from our successful development programs and higher realized pricing relative to the same periods of 2023.

In Canada, total sales, net of blending and other expense, of $440.9 million for Q2/2024 and $793.0 million for YTD 2024 increased from $337.3 million reported for Q2/2023 and $663.2 million for YTD 2023. The increase in our realized pricing for Q2/2024 relative to Q2/2023 resulted in a $56.4 million increase in total sales, net of blending and other expense while higher production contributed to a $47.2 million increase in total sales, net of blending and other expense, relative to Q2/2023. The increase in our realized pricing for YTD 2024 relative to YTD 2023 resulted in a $73.0 million increase in total sales, net of blending and other expense while higher production contributed to a $56.7 million increase in total sales, net of blending and other expense, relative to YTD 2023.

In the U.S., total petroleum and natural gas sales of $624.6 million for Q2/2024 and $1.2 billion for YTD 2024 increased from $208.5 million reported for Q2/2023 and $378.2 million for YTD 2023. The increase in production due to the Merger resulted in a $348.3 million increase in total sales in Q2/2024 relative to Q2/2023 and higher realized pricing contributed to a $67.8 million increase in total sales relative to Q2/2023. Higher production in YTD 2024 resulted in a $755.8 million increase in total sales relative to YTD 2023 and higher realized pricing contributed to a $58.5 million increase in total sales relative to YTD 2023.

Baytex Energy Corp. Second Quarter Report 2024 17

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, 2024 and 2023.

	Three Months Ended June 30
	2024									2023
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	72,894		$	167,546		$	240,440		$	47,309		$	60,611		$	107,920
Average royalty rate (1)(2)		16.5	%		26.8	%		22.6	%		14.0	%		29.1	%		19.8	%
Royalties per boe (3)	$	12.58		$	20.34		$	17.14		$	9.30		$	19.66		$	13.21

	Six Months Ended June 30
	2024									2023
($ thousands except for % and per boe)	Canada			U.S.			Total			Canada			U.S.			Total
Royalties	$	129,458		$	320,153		$	449,611		$	91,164		$	110,009		$	201,173
Average royalty rate (1)(2)		16.3	%		26.8	%		22.6	%		13.7	%		29.1	%		19.3	%
Royalties per boe (3)	$	11.31		$	19.65		$	16.21		$	8.65		$	20.25		$	12.59

(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 Q2/2024 were $240.4 million or 22.6% of total sales, net of blending and other expense, compared to $107.9 million or 19.8% for Q2/2023. Total royalties for YTD 2024 were $449.6 million or 22.6% of total sales, net of blending and other expense, compared to $201.2 million or 19.3% for YTD 2023. The increase in total royalty expense and our average royalty rate in both periods of 2024 relative to 2023 is primarily a result of the Merger with Ranger which resulted in higher total sales, net of blending and other expense, along with a higher proportion of our production being from the Eagle Ford which has a higher royalty rate than our Canadian properties.

Our average royalty rate⁽¹⁾ in Canada of 16.5% for Q2/2024 and 16.3% for YTD 2024 was higher than 14.0% for Q2/2023 and 13.7% for YTD 2023 as a result of heavy oil production growth which has a higher royalty rate relative to our light oil properties, as well as increased realized and crown reference prices on which crown royalties are calculated. In the U.S., royalties averaged 26.8% of total sales for both periods of 2024, which is lower than 29.1% for the comparative periods of 2023 due to production from the acquired Ranger properties which have a lower royalty rate relative to our legacy non-operated Eagle Ford properties.

Our average royalty rate of 22.6% for YTD 2024 is consistent with our annual guidance of 23% for 2024.

(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.

18  Baytex Energy Corp. Second Quarter Report 2024

OPERATING EXPENSE

	Three Months Ended June 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	84,415	$	83,290	$	167,705	$	91,354	$	28,084	$	119,438
Operating expense per boe (1)	$	14.57	$	10.11	$	11.95	$	17.97	$	9.11	$	14.62

	Six Months Ended June 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Operating expense	$	169,818	$	171,322	$	341,140	$	182,534	$	49,312	$	231,846
Operating expense per boe (1)	$	14.84	$	10.51	$	12.30	$	17.31	$	9.08	$	14.51

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

Total operating expense was $167.7 million ($11.95/boe) for Q2/2024 and $341.1 million ($12.30/boe) for YTD 2024 compared to $119.4 million ($14.62/boe) for Q2/2023 and $231.8 million ($14.51/boe) for YTD 2023. Total operating expense for both periods of 2024 increased relative to 2023 due to higher production while lower per unit operating costs reflect the lower per boe operating expense on the properties acquired from Ranger.

In Canada, total operating expense was $84.4 million ($14.57/boe) for Q2/2024 and $169.8 million ($14.84/boe) for YTD 2024 which was lower than $91.4 million ($17.97/boe) for Q2/2023 and $182.5 million ($17.31/boe) for YTD 2023. The decrease in total and per unit operating expense for both periods of 2024 relative to the same periods of 2023 reflects production growth at Peavine along with the disposition of non-core Viking assets in Q4/2023.

In the U.S., operating expense was $83.3 million ($10.11/boe) for Q2/2024 and $171.3 million ($10.51/boe) for YTD 2024 compared to $28.1 million ($9.11/boe) for Q2/2023 and $49.3 million ($9.08/boe) for YTD 2023. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$7.39/boe for Q2/2024 and US$7.74/boe for YTD 2024 compared to US$6.78/boe for Q2/2023 and US$6.74/boe for YTD 2023. The increase in total and per unit operating expense for both periods of 2024 relative to 2023 reflects the additional production from the properties acquired from Ranger along with higher workover and maintenance costs on our non-operated acreage.

Operating expense of $12.30/boe for YTD 2024 is consistent with expectations and our annual guidance range of $11.25 - $12.00/ boe for 2024 reflects production growth over the remainder of the year.

TRANSPORTATION EXPENSE

Transportation expense includes the costs incurred to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize sales prices and transportation rates.

The following table compares our transportation expense for the three and six months ended June 30, 2024 and 2023.

	Three Months Ended June 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	19,569	$	13,745	$	33,314	$	13,240	$	1,334	$	14,574
Transportation expense per boe (1)	$	3.38	$	1.67	$	2.37	$	2.60	$	0.43	$	1.78

	Six Months Ended June 30
	2024						2023
($ thousands except for per boe)	Canada		U.S.		Total		Canada		U.S.		Total
Transportation expense	$	37,779	$	25,370	$	63,149	$	30,245	$	1,334	$	31,579
Transportation expense per boe (1)	$	3.30	$	1.56	$	2.28	$	2.87	$	0.25	$	1.98

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

Baytex Energy Corp. Second Quarter Report 2024 19

Transportation expense was $33.3 million ($2.37/boe) for Q2/2024 and $63.1 million ($2.28/boe) for YTD 2024 compared to $14.6 million ($1.78/boe) for Q2/2023 and $31.6 million ($1.98/boe) for YTD 2023. In Canada, total transportation expense and per unit costs were higher in Q2/2024 and YTD 2024 as a result of additional heavy oil production relative to the same periods of 2023. In the U.S., transportation expense and per unit costs were higher in both periods of 2024 due to trucking and pipeline costs on our operated Eagle Ford operations acquired from Ranger.

Per unit transportation expense of $2.28/boe for YTD 2024 is slightly below our annual guidance range of $2.35 - $2.55/boe for 2024.

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 $67.7 million for Q2/2024 and $131.9 million for YTD 2024 compared to $53.0 million for Q2/2023 and $112.7 million for YTD 2023. Higher blending and other expense is primarily a result of higher heavy oil production and pipeline shipments in Q2/2024 and YTD 2024 relative to same periods in 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 free cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed. The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2024 and 2023.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2024			2023			Change			2024			2023			Change
Realized financial derivatives (loss) gain
Crude oil	$	(4,847	)	$	16,363		$	(21,210	)	$	(3,900	)	$	21,778		$	(25,678	)
Natural gas		2,590			2			2,588			7,131			2			7,129
Total	$	(2,257	)	$	16,365		$	(18,622	)	$	3,231		$	21,780		$	(18,549	)
Unrealized financial derivatives gain (loss)
Crude oil	$	13,476		$	(17,124	)	$	30,600		$	(17,989	)	$	(7,914	)	$	(10,075	)
Natural gas		(2,686	)		(2,279	)		(407	)		(3,571	)		(2,279	)		(1,292	)
Total	$	10,790		$	(19,403	)	$	30,193		$	(21,560	)	$	(10,193	)	$	(11,367	)
Total financial derivatives gain (loss)
Crude oil	$	8,629		$	(761	)	$	9,390		$	(21,889	)	$	13,864		$	(35,753	)
Natural gas		(96	)		(2,277	)		2,181			3,560			(2,277	)		5,837
Total	$	8,533		$	(3,038	)	$	11,571		$	(18,329	)	$	11,587		$	(29,916	)

We recorded a total financial derivatives gain of $8.5 million for Q2/2024 and a loss of $18.3 million for YTD 2024 compared to a loss of $3.0 million for Q2/2023 and a gain of $11.6 million for YTD 2023. The realized financial derivatives gain of $3.2 million for YTD 2024 resulted from gains of $7.1 million on natural gas contracts, offset by losses of $3.9 million on crude oil contracts. The unrealized financial derivatives loss of $21.6 million for YTD 2024 resulted from a $3.6 million loss on natural gas contracts and a $18.0 million loss on crude oil contracts. The YTD loss is primarily due to changes in forecasted crude oil pricing used to revalue the volumes outstanding on our crude oil contracts in place at June 30, 2024 relative to December 31, 2023. The fair value of our financial derivative contracts resulted in a net asset of $1.7 million at June 30, 2024 compared to a net asset of $23.3 million at December 31, 2023.

20  Baytex Energy Corp. Second Quarter Report 2024

As at July 25, 2024, we had the following commodity financial derivative contracts for the period subsequent to June 30, 2024.

	Remaining Period	Volume	Price/Unit (1)	Index
Oil
Basis differential	July 2024 to Dec 2024	15,000 bbl/d	Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.31/bbl	WCS
Basis differential	July 2024 to Dec 2024	6,000 bbl/d	WTI less US$13.58/bbl	WCS
Basis differential	July 2024 to Dec 2024	8,250 bbl/d	WTI less US$2.78/bbl	MSW
Basis differential	Jan 2025 to Dec 2025	2,000 bbl/d	WTI less US$2.75/bbl	MSW
Collar	July 2024 to Dec 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Sep 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$94.15	WTI
Collar	July 2024 to Dec 2024	1,500 bbl/d	US$60.00/US$90.35	WTI
Collar	July 2024 to Dec 2024	1,000 bbl/d	US$60.00/US$90.00	WTI
Collar	July 2024 to Dec 2024	2,000 bbl/d	US$60.00/US$85.00	WTI
Collar	July 2024 to Dec 2024	2,000 bbl/d	US$60.00/US$84.60	WTI
Collar	July 2024 to Dec 2024	5,000 bbl/d	US$60.00/US$84.15	WTI
Collar	Oct 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2024 to Dec 2024	3,500 bbl/d	US$60.00/US$87.10	WTI
Collar	Oct 2024 to Dec 2024	3,500 bbl/d	US$60.00/US$85.75	WTI
Collar	Jan 2025 to Mar 2025	5,000 bbl/d	US$60.00/US$88.70	WTI
Collar	Jan 2025 to Mar 2025	2,500 bbl/d	US$60.00/US$90.20	WTI
Collar	Jan 2025 to Mar 2025	2,500 bbl/d	US$60.00/US$90.05	WTI
Collar	Jan 2025 to Mar 2025	7,500 bbl/d	US$60.00/US$90.00	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$94.25	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$93.90	WTI
Collar	Jan 2025 to Jun 2025	5,000 bbl/d	US$60.00/US$91.95	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$90.00	WTI
Collar	Jan 2025 to Jun 2025	3,000 bbl/d	US$60.00/US$89.55	WTI
Collar	Apr 2025 to Jun 2025	2,000 bbl/d	US$60.00/US$88.17	WTI
Collar (2)	Apr 2025 to Jun 2025	5,000 bbl/d	US$60.00/US$90.50	WTI
Collar (2)	Apr 2025 to Jun 2025	3,000 bbl/d	US$60.00/US$90.60	WTI
Natural Gas
Collar	July 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.185	NYMEX
Collar	July 2024 to Dec 2024	8,500 mmbtu/d	US$3.00/US$4.15	NYMEX
Collar	July 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.10	NYMEX
Collar	July 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.09	NYMEX
Collar	July 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.06	NYMEX
Collar	Jan 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.01	NYMEX
Collar	Jan 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.03	NYMEX
Collar	Jan 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.08	NYMEX
Collar	Jan 2025 to Dec 2025	3,000 mmbtu/d	US$3.25/US$4.135	NYMEX
Collar	Jan 2025 to Dec 2025	5,500 mmbtu/d	US$3.25/US$4.14	NYMEX
Collar	Jan 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.32	NYMEX
Collar	Jan 2025 to Dec 2025	3,000 mmbtu/d	US$3.00/US$4.85	NYMEX
Collar	Jan 2025 to Dec 2025	8,000 mmbtu/d	US$3.00/US$4.855	NYMEX
Collar	Jan 2026 to Dec 2026	11,000 mmbtu/d	US$3.25/US$5.02	NYMEX

(1)	Based on the weighted average price per unit for the period.
(2)	Contract entered subsequent to June 30, 2024.

Baytex Energy Corp. Second Quarter Report 2024 21

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, 2024 and 2023.

	Three Months Ended June 30
	2024									2023
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		63,688			90,506			154,194			55,874			33,887			89,761
Operating netback:
Total sales, net of blending and other expense (1)	$	76.07		$	75.83		$	75.93		$	66.34		$	67.60		$	66.82
Less:
Royalties (2)		(12.58	)		(20.34	)		(17.14	)		(9.30	)		(19.66	)		(13.21	)
Operating expense (2)		(14.57	)		(10.11	)		(11.95	)		(17.97	)		(9.11	)		(14.62	)
Transportation expense (2)		(3.38	)		(1.67	)		(2.37	)		(2.60	)		(0.43	)		(1.78	)
Operating netback (1)	$	45.54		$	43.71		$	44.47		$	36.47		$	38.40		$	37.21
Realized financial derivatives gain (loss) (3)		—			—			(0.16	)		—			—			2.00
Operating netback after financial derivatives (1)	$	45.54		$	43.71		$	44.31		$	36.47		$	38.40		$	39.21

	Six Months Ended June 30
	2024									2023
($ per boe except for volume)	Canada			U.S.			Total			Canada			U.S.			Total
Total production (boe/d)		62,884			89,523			152,407			58,249			30,020			88,269
Operating netback:
Total sales, net of blending and other expense (1)	$	69.29		$	73.19		$	71.58		$	62.91		$	69.60		$	65.18
Less:
Royalties (2)		(11.31	)		(19.65	)		(16.21	)		(8.65	)		(20.25	)		(12.59	)
Operating expense (2)		(14.84	)		(10.51	)		(12.30	)		(17.31	)		(9.08	)		(14.51	)
Transportation expense (2)		(3.30	)		(1.56	)		(2.28	)		(2.87	)		(0.25	)		(1.98	)
Operating netback (1)	$	39.84		$	41.47		$	40.79		$	34.08		$	40.02		$	36.10
Realized financial derivatives gain (3)		—			—			0.12			—			—			1.36
Operating netback after financial derivatives (1)	$	39.84		$	41.47		$	40.91		$	34.08		$	40.02		$	37.46

(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 of $44.47/boe for Q2/2024 and $40.79/boe for YTD 2024 was higher than $37.21/boe for Q2/2023 and $36.10/boe for YTD 2023 due to the increase in our realized price which resulted in higher per unit sales net of royalties. In 2024, a higher proportion of our production was from our U.S. properties which have lower operating and transportation expense resulting in total operating and transportation expense of $14.32/boe for Q2/2024 and $14.58/boe for YTD 2024, which was lower than $16.40/boe for Q2/2023 and $16.49/boe for YTD 2023. Our operating netback net of realized gains and losses on financial derivatives was $44.31/boe for Q2/2024 and $40.91/boe for YTD 2024 compared to $39.21/boe for Q2/2023 and $37.46/boe for YTD 2023.

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.

22  Baytex Energy Corp. Second Quarter Report 2024

The following table summarizes our G&A expense for the three and six months ended June 30, 2024 and 2023.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands except for per boe)	2024			2023			Change			2024			2023			Change
Gross general and administrative expense	$	27,064		$	16,476		$	10,588		$	55,827		$	30,893		$	24,934
Overhead recoveries		(6,058	)		(1,236	)		(4,822	)		(12,409	)		(3,919	)		(8,490	)
General and administrative expense	$	21,006		$	15,240		$	5,766		$	43,418		$	26,974		$	16,444
General and administrative expense per boe (1)	$	1.50		$	1.87		$	(0.37	)	$	1.57		$	1.69		$	(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 $21.0 million ($1.50/boe) for Q2/2024 and $43.4 million ($1.57/boe) for YTD 2024 compared to $15.2 million ($1.87/boe) for Q2/2023 and $27.0 million ($1.69/boe) for YTD 2023. G&A expense for Q2/2024 and YTD 2024 was higher than both periods of 2023 due to staffing costs associated with the personnel retained following the Merger with Ranger. G&A expense of $1.57/boe for YTD 2024 is consistent with our 2024 annual guidance of $1.65/boe.

FINANCING AND INTEREST EXPENSE

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

The following table summarizes our financing and interest expense for the three and six months ended June 30, 2024 and 2023.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2024		2023		Change		2024		2023		Change
Interest on credit facilities	$	15,639	$	7,535	$	8,104	$	33,928	$	13,751	$	20,177
Interest on long-term notes		37,656		20,565		17,091		72,334		32,659		39,675
Interest on lease obligations		651		155		496		964		220		744
Cash interest	$	53,946	$	28,255	$	25,691	$	107,226	$	46,630	$	60,596
Accretion of debt issue costs		7,862		1,847		6,015		10,922		2,371		8,551
Accretion of asset retirement obligations		5,459		4,395		1,064		10,386		9,221		1,165
Early redemption expense		24,350		—		24,350		24,350		—		24,350
Financing and interest expense	$	91,617	$	34,497	$	57,120	$	152,884	$	58,222	$	94,662
Cash interest per boe (1)	$	3.84	$	3.46	$	0.38	$	3.87	$	2.92	$	0.95
Financing and interest expense per boe (1)	$	6.53	$	4.22	$	2.31	$	5.51	$	3.64	$	1.87

(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 $91.6 million ($6.53/boe) for Q2/2024 and $152.9 million ($5.51/boe) for YTD 2024 compared to $34.5 million ($4.22/boe) for Q2/2023 and $58.2 million ($3.64/boe) for YTD 2023. Higher interest costs in 2024 compared to 2023 are primarily the result of the additional debt outstanding after the Merger with Ranger and also includes costs incurred related to the early redemption of the 8.75% notes on April 1, 2024.

Cash interest of $53.9 million ($3.84/boe) for Q2/2024 and $107.2 million ($3.87/boe) for YTD 2024 was higher than $28.3 million ($3.46/boe) for Q2/2023 and $46.6 million ($2.92/boe) for YTD 2023, primarily due to higher debt balances outstanding after the Merger, which included the issuance of US$800.0 million aggregate principal amount of long-term notes. Interest on our credit facilities increased in Q2/2024 relative to Q2/2023 due to higher applicable borrowing rates along with additional principal amounts outstanding following the Merger. The weighted average interest rate applicable on our credit facilities was 7.9% for Q2/2024 and 8.0% for YTD 2024 compared to 6.8% for Q2/2023 and 6.5% for YTD 2023.

Accretion of asset retirement obligations of $5.5 million for Q2/2024 and $10.4 million for YTD 2024 was consistent with $4.4 million for Q2/2023 and $9.2 million for YTD 2023. Accretion of debt issue costs was higher for 2024 compared to 2023 due to the increase in debt issue costs associated with the credit facilities and new long-term notes issued to fund the Merger with Ranger. We also recorded $24.4 million of early redemption expense related to the 8.75% senior notes which were redeemed in Q2/2024 using the proceeds from the issuance of US$575 million aggregate principal amount of senior unsecured notes due 2032.

Baytex Energy Corp. Second Quarter Report 2024 23

We have revised our cash interest expense annual guidance for 2024 to $200 million ($3.57/boe), up from $190 million ($3.40/boe) previously.

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 $0.6 million for Q2/2024 and $0.7 million for YTD 2024 compared to $0.4 million for Q2/2023 and $0.5 million for YTD 2023.

DEPLETION AND DEPRECIATION

Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved and 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, 2024 and 2023.

	Three Months Ended June 30						Six Months Ended June 30
($ thousands except for per boe)	2024		2023		Change		2024		2023		Change
Depletion	$	349,718	$	174,473	$	175,245	$	691,153	$	338,908	$	352,245
Depreciation		3,383		1,671		1,712		6,085		3,235		2,850
Depletion and depreciation	$	353,101	$	176,144	$	176,957	$	697,238	$	342,143	$	355,095
Depletion and depreciation per boe (1)	$	25.16	$	21.56	$	3.60	$	25.14	$	21.42	$	3.72

(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 $353.1 million ($25.16/boe) for Q2/2024 and $697.2 million ($25.14/boe) for YTD 2024 compared to $176.1 million ($21.56/boe) for Q2/2023 and $342.1 million ($21.42/boe) for YTD 2023. Total depletion and depreciation expense and depletion and depreciation per boe were higher in Q2/2024 and YTD 2024 relative to Q2/2023 and YTD 2023 due to depletion on the assets acquired from Ranger which have a higher depletion rate than our other properties. The effect of the Merger was partially offset by an impairment loss of $833.7 million that was recorded at December 31, 2023.

IMPAIRMENT

We did not identify indicators of impairment or impairment reversal for any of our cash generating units ("CGUs") at June 30, 2024.

2023 Impairment

At December 31, 2023, we identified indicators of impairment for oil and gas properties in our legacy non-operated Eagle Ford CGU due to changes in our reserves and in our Viking CGU due to changes in our reserves and a loss recorded on a disposition of an asset. We recorded an impairment loss of $833.7 million.

SHARE-BASED COMPENSATION EXPENSE

Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with equity-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding increase in contributed surplus. SBC expense associated with cash-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding share-based compensation liability. SBC expense varies with the quantity of unvested share awards outstanding and changes in the market price of our common shares.

We recorded SBC expense of $5.6 million for Q2/2024 and $15.1 million for YTD 2024 which is lower than $16.9 million for Q2/2023 and $26.7 million for YTD 2023. SBC expense for Q2/2024 and YTD 2024 decreased relative to the same periods of 2023 as 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. This decrease in SBC expense was partially offset by an increase in the Company's share price during YTD 2024. 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.

24  Baytex Energy Corp. Second Quarter Report 2024

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)	2024		2023			Change			2024		2023			Change
Unrealized foreign exchange loss (gain)	$	19,189	$	(12,880	)	$	32,069		$	57,907	$	(13,093	)	$	71,000
Realized foreign exchange loss		866		941			(75	)		2,085		1,091			994
Foreign exchange loss (gain)	$	20,055	$	(11,939	)	$	31,994		$	59,992	$	(12,002	)	$	71,994
CAD/USD exchange rates:
At beginning of period		1.3533		1.3528						1.3205		1.3534
At end of period		1.3687		1.3238						1.3687		1.3238

We recorded a foreign exchange loss of $20.1 million for Q2/2024 and $60.0 million for YTD 2024 compared to a gain of $11.9 million for Q2/2023 and $12.0 million for YTD 2023.

The unrealized foreign exchange loss of $19.2 million for Q2/2024 and $57.9 million for YTD 2024 is due to an increase in the reported amount of our long-term notes and credit facilities as a result of a weaker Canadian dollar relative to the U.S. dollar at June 30, 2024 compared to March 31, 2024 and December 31, 2023. The unrealized foreign exchange gain of $12.9 million for Q2/2023 and $13.1 million for YTD 2023 is due to a decrease in the reported amount of our long-term notes 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.

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 functional currency entities. We recorded a realized foreign exchange loss of $0.9 million for Q2/2024 and $2.1 million for YTD 2024 compared to a loss of $0.9 million for Q2/2023 and $1.1 million for YTD 2023.

INCOME TAXES

	Three Months Ended June 30							Six Months Ended June 30
($ thousands)	2024		2023			Change		2024		2023			Change
Current income tax expense	$	6,475	$	1,350		$	5,125	$	8,155	$	2,470		$	5,685
Deferred income tax expense (recovery)		22,810		(178,360	)		201,170		38,611		(162,837	)		201,448
Total income tax expense (recovery)	$	29,285	$	(177,010	)	$	206,295	$	46,766	$	(160,367	)	$	207,133
Current income tax expense per boe	$	0.46	$	0.17		$	0.29	$	0.29	$	0.15		$	0.14

Current income tax expense was $6.5 million for Q2/2024 and $8.2 million for YTD 2024 compared to $1.4 million for Q2/2023 and $2.5 million for YTD 2023. The current tax expense recorded in Q2/2024 and YTD 2024 primarily relates to repatriation and related taxes, which have increased from the same periods of 2023 as a result of the Merger. We expect current income tax expense of $40 million ($0.72/boe) for 2024.

We recorded deferred tax expense of $22.8 million for Q2/2024 and $38.6 million for YTD 2024 compared to a recovery of $178.4 million for Q2/2023 and $162.8 million for YTD 2023. The deferred tax expense recorded in Q2/2024 and YTD 2024 reflects income generated on our U.S. operations for the period as the tax pools associated with our Canadian operations are subject to a valuation allowance. The deferred tax recovery recorded 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.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court of Canada and we estimate it could take between two and three years to receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

Baytex Energy Corp. Second Quarter Report 2024 25

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During Q4/2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $208.6 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.

26  Baytex Energy Corp. Second Quarter Report 2024

NET INCOME AND ADJUSTED FUNDS FLOW

The components of adjusted funds flow and net income for the three and six months ended June 30, 2024 and 2023 are set forth in the following table.

	Three Months Ended June 30									Six Months Ended June 30
($ thousands)	2024			2023			Change			2024			2023			Change
Petroleum and natural gas sales	$	1,133,123		$	598,760		$	534,363		$	2,117,315		$	1,154,096		$	963,219
Royalties		(240,440	)		(107,920	)		(132,520	)		(449,611	)		(201,173	)		(248,438	)
Revenue, net of royalties		892,683			490,840			401,843			1,667,704			952,923			714,781
Expenses
Operating		(167,705	)		(119,438	)		(48,267	)		(341,140	)		(231,846	)		(109,294	)
Transportation		(33,314	)		(14,574	)		(18,740	)		(63,149	)		(31,579	)		(31,570	)
Blending and other		(67,685	)		(52,995	)		(14,690	)		(131,893	)		(112,676	)		(19,217	)
Operating netback (1)	$	623,979		$	303,833		$	320,146		$	1,131,522		$	576,822		$	554,700
General and administrative		(21,006	)		(15,240	)		(5,766	)		(43,418	)		(26,974	)		(16,444	)
Cash interest		(53,946	)		(28,255	)		(25,691	)		(107,226	)		(46,630	)		(60,596	)
Realized financial derivatives (loss) gain		(2,257	)		16,365			(18,622	)		3,231			21,780			(18,549	)
Realized foreign exchange loss		(866	)		(941	)		75			(2,085	)		(1,091	)		(994	)
Cash other expense		(1,025	)		(141	)		(884	)		(2,096	)		(354	)		(1,742	)
Current income tax expense		(6,475	)		(1,350	)		(5,125	)		(8,155	)		(2,470	)		(5,685	)
Cash share-based compensation		(5,565	)		(681	)		(4,884	)		(15,088	)		(10,504	)		(4,584	)
Adjusted funds flow (2)	$	532,839		$	273,590		$	259,249		$	956,685		$	510,579		$	446,106
Transaction costs		—			(32,832	)		32,832			(1,539	)		(41,703	)		40,164
Exploration and evaluation		(649	)		(369	)		(280	)		(667	)		(532	)		(135	)
Depletion and depreciation		(353,101	)		(176,144	)		(176,957	)		(697,238	)		(342,143	)		(355,095	)
Non-cash share-based compensation		—			(16,237	)		16,237			—			(16,237	)		16,237
Non-cash financing and interest		(37,671	)		(6,242	)		(31,429	)		(45,658	)		(11,592	)		(34,066	)
Non-cash other income		—			—			—			—			1,271			(1,271	)
Unrealized financial derivatives gain (loss)		10,790			(19,403	)		30,193			(21,560	)		(10,193	)		(11,367	)
Unrealized foreign exchange (loss) gain		(19,189	)		12,880			(32,069	)		(57,907	)		13,093			(71,000	)
Loss on dispositions and swaps		(6,311	)		—			(6,311	)		(3,650	)		(336	)		(3,314	)
Deferred income tax (expense) recovery		(22,810	)		178,360			(201,170	)		(38,611	)		162,837			(201,448	)
Net income	$	103,898		$	213,603		$	(109,705	)	$	89,855		$	265,044		$	(175,189	)

(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 $532.8 million for Q2/2024 and $956.7 million for YTD 2024 compared to $273.6 million for Q2/2023 and $510.6 million for YTD 2023. The increase in adjusted funds flow was primarily due to higher commodity prices and production that resulted in increased revenues net of royalties, which was offset by higher operating, transportation and blending and other expense. Cash interest and general and administrative expenses were also higher in both periods of 2024 due to the Merger. We reported net income of $103.9 million for Q2/2024 and $89.9 million for YTD 2024 compared to net income of $213.6 million for Q2/2023 and $265.0 million for YTD 2023. The decrease in net income for Q2/2024 and YTD 2024 relative to the same periods of 2023 is the result of deferred income tax expense recognized in 2024 compared to a deferred tax recovery recognized in 2023, a higher depletion rate and associated depletion expense, an unrealized foreign exchange loss and increased non-cash financing and interest costs.

Baytex Energy Corp. Second Quarter Report 2024 27

OTHER COMPREHENSIVE INCOME

Other comprehensive income is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation gain of $52.0 million for Q2/2024 and $162.6 million for YTD 2024 relates to the change in value of our U.S. net assets and is due to the weakening of the Canadian dollar relative to the U.S. dollar at June 30, 2024 compared to March 31, 2024 and December 31, 2023. The CAD/USD exchange rate was 1.3687 CAD/ USD as at June 30, 2024 compared to 1.3533 CAD/USD at March 31, 2024 and 1.3205 CAD/USD at December 31, 2023.

CAPITAL EXPENDITURES

Capital expenditures for the three and six months ended June 30, 2024 and 2023 are summarized as follows.

	Three Months Ended June 30
	2024								2023
($ thousands)	Canada		U.S.			Total			Canada			U.S.		Total
Drilling, completion and equipping	$	80,349	$	208,662		$	289,011		$	77,518		$	69,309	$	146,827
Facilities and other		21,567		28,995			50,562			18,885			4,992		23,877
Exploration and development expenditures	$	101,916	$	237,657		$	339,573		$	96,403		$	74,301	$	170,704
Property acquisitions	$	1,802	$	1,547		$	3,349		$	(62	)	$	—	$	(62	)
Proceeds from dispositions	$	157	$	(2,852	)	$	(2,695	)	$	(50	)	$	—	$	(50	)

	Six Months Ended June 30
	2024								2023
($ thousands)	Canada		U.S.			Total			Canada			U.S.		Total
Drilling, completion and equipping	$	206,357	$	428,601		$	634,958		$	232,471		$	118,145	$	350,616
Facilities and other		53,685		63,481			117,166			48,538			5,176		53,714
Exploration and development expenditures	$	260,042	$	492,082		$	752,124		$	281,009		$	123,321	$	404,330
Property acquisitions	$	36,077	$	2,675		$	38,752		$	444		$	—	$	444
Proceeds from dispositions	$	132	$	(2,852	)	$	(2,720	)	$	(285	)	$	—	$	(285	)

Exploration and development expenditures were $339.6 million for Q2/2024 and $752.1 million for YTD 2024 compared to $170.7 million for Q2/2023 and $404.3 million for YTD 2023. Exploration and development expenditures in Q2/2024 and YTD 2024 were higher compared to Q2/2023 and YTD 2023 primarily due to development activity on the properties acquired from Ranger. We also completed property acquisitions, including the acquisition of 30.75 net sections of high-quality Duvernay lands adjacent to our existing acreage, in YTD 2024 for a total of $38.8 million.

In Canada, exploration and development expenditures were $101.9 million in Q2/2024 and $260.0 million for YTD 2024 compared to $96.4 million in Q2/2023 and $281.0 million for YTD 2023. Drilling and completion spending of $80.3 million in Q2/2024 was relatively consistent with Q2/2023 when we spent $77.5 million which reflects similar development activity levels on our Canadian properties. YTD 2024 drilling and completion spending of $206.4 million reflects lower light and heavy oil development activity relative to YTD 2023 when we spent $232.5 million. We also invested $53.7 million on facilities and other expenditures during YTD 2024 which is consistent with $48.5 million during YTD 2023.

Total U.S. exploration and development expenditures were $237.7 million for Q2/2024 and $492.1 million for YTD 2024 compared to $74.3 million in Q2/2023 and $123.3 million for YTD 2023. The increase in exploration and development expenditures for both periods of 2024 is due to development activity on our properties acquired from Ranger.

Exploration and development expenditures of $752.1 million for YTD 2024 were consistent with expectations. Our annual guidance of $1.2 - $1.3 billion reflects moderated exploration and development spending over the remainder of 2024.

CAPITAL RESOURCES AND LIQUIDITY

Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions. We strive to actively manage our capital structure in response to changes in economic conditions. At June 30, 2024, our capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.

28  Baytex Energy Corp. Second Quarter Report 2024

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

Management of debt levels is a priority for Baytex in order to sustain operations and support our business strategy. Net debt⁽¹⁾ of $2.6 billion at June 30, 2024 was consistent with $2.5 billion at December 31, 2023 which was due to the impact of a weaker Canadian dollar at June 30, 2024 on our U.S. dollar denominated debt and also reflects $38.8 million of property acquisitions along with $49.7 million of debt issuance costs incurred during YTD 2024. We expect net debt to decline over the remainder of 2024 as we continue to allocate 50% of free cash flow to the balance sheet.

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

Credit Facilities

At June 30, 2024, we had $626.0 million of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (the "Credit Facilities"). The Credit 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. On May 9, 2024, we extended the maturity of the Credit Facilities from April 1, 2026 to May 9, 2028. There were no changes to the loan balances or financial covenants as a result of the amendment. Following the amendment, borrowing in Canadian funds previously based on the banker's acceptance rate has been replaced with borrowings based on the Canadian Overnight Repo Rate Average ("CORRA").

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, CORRA rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the Credit Facilities was 7.9% for Q2/2024 and 8.0% for YTD 2024 compared to 6.8% for Q2/2023 and 6.5% for YTD 2023. The increase in the weighted average interest rate on our Credit Facilities was primarily due to an increase in the margins applicable to our Credit Facilities in 2024 relative to the same period in 2023.

At June 30, 2024, we had $5.7 million of outstanding letters of credit (December 31, 2023 - $5.6 million outstanding) under the Credit Facilities.

The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov.

Financial Covenants

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2024.

	Position as at June
Covenant Description	30, 2024	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.3:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	10.3:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.1:1.0	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, 2024, the Company's Senior Secured Debt totaled $630.6 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, 2024 was $2.3 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, 2024 was $219.0 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 payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at June 30, 2024, the Company's Total Debt totaled $2.5 billion of principal amounts outstanding.

Baytex Energy Corp. Second Quarter Report 2024 29

Long-Term Notes

At June 30, 2024 we have two issuances of long-term notes outstanding with a total principal amount of $1.9 billion. The long-term notes do not contain any financial maintenance covenants.

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 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. At June 30, 2024 there was US$800.0 million aggregate principal amount of the 8.50% Senior Notes outstanding.

On April 1, 2024, we closed a private offering of the US$575 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"). The 7.375% Senior Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15, 2032. The 7.375% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity. Proceeds from the 7.375% Senior Notes were used to redeem the remaining US$409.8 million aggregate principal amount of the outstanding 8.75% Senior Notes at 104.375% of par value, pay the related fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities. At June 30, 2024 there was US$575.0 million aggregate principal amount of the 7.375% Senior Notes outstanding.

Shareholders’ Capital

We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the six months ended June 30, 2024, we issued 0.3 million common shares pursuant to our share-based compensation program. As at June 30, 2024, we had 805.0 million common shares issued and outstanding and no preferred shares issued and outstanding.

Our shareholder returns framework includes common share repurchases and a quarterly dividend. During the six months ended June 30, 2024, we repurchased 17.0 million common shares under our normal course issuer bid ("NCIB") at an average price of $4.85 per share for total consideration of $82.3 million. In June 2024, we renewed our NCIB under which Baytex is permitted to purchase for cancellation up to 70.1 million common shares over the 12-month period commencing July 2, 2024, which represents 10% of Baytex's public float, as defined by the TSX, as of June 18, 2024. Baytex obtained an exemption order from the Canadian securities regulators which permits the company to purchase its common shares through the NYSE and other U.S.-based trading systems.

Effective January 1, 2024, the Government of Canada introduced a 2% federal tax on equity repurchases. During the six months ended June 30, 2024, Baytex recorded a $1.6 million liability, charged to shareholders’ capital, related to the federal tax on equity repurchases.

On January 2, April 1 and July 2, 2024, we paid a quarterly cash dividend of CDN$0.0225 per share to shareholders of record. On July 25, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2024 for shareholders on record as at September 16, 2024. 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.”

30  Baytex Energy Corp. Second Quarter Report 2024

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, 2024 and the expected timing for funding these obligations are noted in the table below.

($ thousands)	Total		Less than 1 year		1-3 years		3-5 years		Beyond 5 years
Financial derivatives	$	5,314	$	5,314	$	—	$	—	$	—
Credit facilities - principal		625,976		—		—		625,976		—
Long-term notes - principal		1,881,894		—		—		—		1,881,894
Interest on long-term notes (1)		990,729		151,108		302,215		302,215		235,191
Lease obligations - principal		31,351		10,189		10,188		7,269		3,705
Processing agreements		5,334		559		908		3,867		—
Transportation agreements		188,871		53,196		89,161		37,860		8,654
Total	$	3,729,469	$	220,366	$	402,472	$	977,187	$	2,129,444

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

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.

Baytex Energy Corp. Second Quarter Report 2024 31

QUARTERLY FINANCIAL INFORMATION

($ thousands, except per common share	2024						2023												2022
amounts)	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Petroleum and natural gas sales		1,133,123			984,192			1,065,515			1,163,010			598,760			555,336			648,986			712,065
Net income (loss)		103,898			(14,043	)		(625,830	)		127,430			213,603			51,441			352,807			264,968
Per common share - basic		0.13			(0.02	)		(0.75	)		0.15			0.37			0.09			0.65			0.48
Per common share - diluted		0.13			(0.02	)		(0.75	)		0.15			0.36			0.09			0.64			0.47
Adjusted funds flow (1)		532,839			423,846			502,148			581,623			273,590			236,989			255,552			284,288
Per common share - basic		0.65			0.52			0.60			0.68			0.47			0.43			0.47			0.51
Per common share - diluted		0.65			0.52			0.60			0.68			0.47			0.43			0.46			0.51
Free cash flow (2)		180,673			(88	)		290,785			158,440			96,313			(1,918	)		143,324			111,568
Per common share - basic		0.22			—			0.35			0.19			0.17			—			0.26			0.20
Per common share - diluted		0.22			—			0.35			0.18			0.16			—			0.26			0.20
Cash flows from operating activities		505,584			383,773			474,452			444,033			192,308			184,938			303,441			310,423
Per common share - basic		0.62			0.47			0.57			0.52			0.33			0.34			0.56			0.56
Per common share - diluted		0.62			0.47			0.57			0.52			0.33			0.34			0.55			0.56
Dividends declared		18,161			18,494			18,381			19,138			—			—			—			—
Per common share		0.0225			0.0225			0.0225			0.0225			—			—			—			—
Exploration and development		339,573			412,551			199,214			409,191			170,704			233,626			103,634			167,453
Canada		101,916			158,126			75,137			107,053			96,403			184,606			85,641			117,150
U.S.		237,657			254,425			124,077			302,138			74,301			49,020			17,993			50,303
Property acquisitions		3,349			35,403			33,923			4,277			(62	)		506			1,085			—
Proceeds from dispositions		(2,695	)		(25	)		(159,745	)		(226	)		(50	)		(235	)		(148	)		(25,460	)
Net debt (1)		2,639,014			2,639,841			2,534,287			2,824,348			2,814,844			995,170			987,446			1,113,559
Total assets		7,770,926			7,717,495			7,460,931			8,946,181			8,617,444			5,180,059			5,103,769			4,923,617
Common shares outstanding		804,977			821,322			821,681			845,360			862,192			545,553			544,930			547,615
Daily production
Total production (boe/d)		154,194			150,620			160,373			150,600			89,761			86,760			86,864			83,194
Canada (boe/d)		63,688			62,081			64,744			63,289			55,874			60,651			56,946			55,803
U.S. (boe/d)		90,506			88,540			95,629			87,311			33,887			26,109			29,918			27,391
Benchmark prices
WTI oil (US$/bbl)		80.57			76.96			78.32			82.26			73.78			76.13			82.64			91.56
WCS heavy oil ($/bbl)		91.72			77.73			76.86			93.02			78.85			69.44			77.37			93.62
Edmonton par oil ($/bbl)		105.30			92.16			99.72			107.93			95.13			99.04			109.57			116.79
CAD/USD avg exchange rate		1.3684			1.3488			1.3619			1.3410			1.3431			1.3520			1.3577			1.3059
AECO natural gas ($/mcf)		1.44			2.05			2.66			2.39			2.35			4.34			5.58			5.81
NYMEX natural gas (US$/mmbtu)		1.89			2.24			2.88			2.55			2.10			3.42			6.26			8.20
Total sales, net of blending and other expense ($/boe) (2)		75.93			67.12			68.00			80.34			66.82			63.48			74.93			87.68
Royalties ($/boe) (3)		(17.14	)		(15.26	)		(15.49	)		(17.33	)		(13.21	)		(11.94	)		(15.23	)		(19.21	)
Operating expense ($/boe) (3)		(11.95	)		(12.65	)		(11.17	)		(12.57	)		(14.62	)		(14.40	)		(13.06	)		(14.39	)
Transportation expense ($/boe) (3)		(2.37	)		(2.18	)		(2.02	)		(2.02	)		(1.78	)		(2.18	)		(1.85	)		(1.67	)
Operating netback ($/boe) (2)		44.47			37.03			39.32			48.42			37.21			34.96			44.79			52.41
Financial derivatives (loss) gain ($/boe) (3)		(0.16	)		0.40			0.84			0.15			2.00			0.69			(6.21	)		(9.98	)
Operating netback after financial derivatives ($/boe) (2)		44.31			37.43			40.16			48.57			39.21			35.65			38.58			42.43

(1)	Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)	Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(3)	Calculated as royalties, operating expense, transportation expense or financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.

32  Baytex Energy Corp. Second Quarter Report 2024

Our results for the previous eight quarters reflect the disciplined execution of our capital programs as oil and natural gas prices have fluctuated. Production steadily increased from 83,194 boe/d in Q3/2022 and reached 154,194 boe/d in Q2/2024 due to strong well performance from our development programs in Canada and the U.S., along with the production contribution from the Merger with Ranger.

Commodity prices strengthened to multi-year highs in 2022 following Russia's invasion of Ukraine which created elevated uncertainty surrounding the global supply of oil and natural gas and is reflected in our realized sales price of $87.68/boe for Q3/2022, which is our strongest realized pricing in the most recent eight quarters. Our realized price of $75.93/boe for Q2/2024 reflects stable crude oil prices from balanced global supply and demand with ongoing geopolitical tensions.

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 $532.8 million and cash flows from operating activities of $505.6 million for Q2/2024 reflect strong production results from our development plans in the U.S. and Canada as well as the Merger with Ranger.

Net debt can fluctuate on a quarterly basis depending on the timing of exploration and development expenditures, changes in our adjusted funds flow and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt⁽¹⁾ increased to $2.6 billion at Q2/2024 from $1.1 billion at Q3/2022 as a result of additional debt used to fund the Merger which closed in Q2/2023. The change in net debt also reflects free cash flow⁽²⁾ of $867.5 million generated in the period since Q3/2022, of which $397.7 million was allocated to shareholder returns.

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

ENVIRONMENTAL REGULATIONS

As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2023 for a full description of the risks associated with these regulations and how they may impact our business in the future.

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 ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Sustainability Standards Board has released proposed standards that are aligned with the ISSB release, but include suggestions for Canadian-specific modifications. 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.

OFF BALANCE SHEET TRANSACTIONS

We do not have any financial arrangements that are excluded from the consolidated financial statements as at June 30, 2024, 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, 2024. 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, 2023.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2024, Baytex adopted amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.

These amendments have not had a material impact on our consolidated financial statements.

Baytex Energy Corp. Second Quarter Report 2024 33

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.

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)	2024			2023			2024			2023
Petroleum and natural gas sales	$	1,133,123		$	598,760		$	2,117,315		$	1,154,096
Light oil and condensate (1)		(662,650	)		(308,810	)		(1,263,765	)		(597,275	)
NGL (1)		(49,510	)		(20,163	)		(95,441	)		(41,997	)
Natural gas sales (1)		(26,003	)		(18,338	)		(58,225	)		(46,290	)
Heavy oil sales	$	394,960		$	251,449		$	699,884		$	468,534
Blending and other expense (2)		(67,685	)		(52,995	)		(131,893	)		(112,676	)
Heavy oil, net of blending and other expense	$	327,275		$	198,454		$	567,991		$	355,858

(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, 2024 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.

34  Baytex Energy Corp. Second Quarter Report 2024

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)	2024			2023			2024			2023
Petroleum and natural gas sales	$	1,133,123		$	598,760		$	2,117,315		$	1,154,096
Blending and other expense		(67,685	)		(52,995	)		(131,893	)		(112,676	)
Total sales, net of blending and other expense		1,065,438			545,765			1,985,422			1,041,420
Royalties		(240,440	)		(107,920	)		(449,611	)		(201,173	)
Operating expense		(167,705	)		(119,438	)		(341,140	)		(231,846	)
Transportation expense		(33,314	)		(14,574	)		(63,149	)		(31,579	)
Operating netback	$	623,979		$	303,833		$	1,131,522		$	576,822
Realized financial derivatives (loss) gain (1)		(2,257	)		16,365			3,231			21,780
Operating netback after realized financial derivatives	$	621,722		$	320,198		$	1,134,753		$	598,602

(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, 2024 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, transaction costs and cash premiums on derivatives.

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)	2024			2023			2024			2023
Cash flows from operating activities	$	505,584		$	192,308		$	889,357		$	377,246
Change in non-cash working capital		20,140			40,795			52,163			79,849
Additions to exploration and evaluation assets		—			(741	)		—			(1,231	)
Additions to oil and gas properties		(339,573	)		(169,963	)		(752,124	)		(403,099	)
Payments on lease obligations		(5,478	)		(1,181	)		(10,350	)		(2,336	)
Transaction costs		—			32,832			1,539			41,703
Cash premiums on derivatives		—			2,263			—			2,263
Free cash flow	$	180,673		$	96,313		$	180,585		$	94,395

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.

Baytex Energy Corp. Second Quarter Report 2024 35

Operating netback per boe

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

Capital Management Measures

Net debt

We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt is comprised of our credit facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash, trade receivables, and prepaids and other assets.

The following table summarizes our calculation of net debt.

	As at
($ thousands)	June 30, 2024			December 31, 2023
Credit facilities	$	607,589		$	848,749
Unamortized debt issuance costs - Credit facilities (1)		18,387			15,987
Long-term notes		1,833,182			1,562,361
Unamortized debt issuance costs - Long-term notes (1)		48,712			35,114
Trade payables		617,222			477,295
Share-based compensation liability		22,706			35,732
Dividends payable		18,161			18,381
Other long-term liabilities		19,845			19,147
Cash		(35,887	)		(55,815	)
Trade receivables		(429,098	)		(339,405	)
Prepaids and other assets		(81,805	)		(83,259	)
Net debt	$	2,639,014		$	2,534,287

(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, 2024. 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 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
($ thousands)	2024		2023		2024		2023
Cash flow from operating activities	$	505,584	$	192,308	$	889,357	$	377,246
Change in non-cash working capital		20,140		40,795		52,163		79,849
Asset retirement obligations settled		7,115		5,392		13,626		9,518
Transaction costs		—		32,832		1,539		41,703
Cash premiums on derivatives		—		2,263		—		2,263
Adjusted funds flow	$	532,839	$	273,590	$	956,685	$	510,579

36  Baytex Energy Corp. Second Quarter Report 2024

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 that changes were made to, internal controls over financial reporting during the three months ended June 30, 2024, except for the matter described below.

Baytex previously excluded business processes acquired through the Merger on June 20, 2023 from the Company's evaluation of internal control over financial reporting as permitted by applicable securities laws in Canada and the U.S. We completed the evaluation of design of internal controls over financial reporting of Ranger during Q2/2024.

FORWARD-LOOKING STATEMENTS

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

Specifically, this document contains forward-looking statements relating to but not limited to: that we can effectively allocate capital across our assets; our expectation that net debt will decline over the balance of 2024; our 2024 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; that we intend to settle outstanding share based compensation awards in cash; the expected time to resolve the reassessment of our tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions; that we may issue or repurchase debt or equity securities from time to time; our intent to fund certain financial obligations with cash flow from operations and the expected timing of the financial obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.

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

Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices; risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; 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; risks associated with a third-party operating our Eagle Ford properties; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse 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 associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; 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, 2023, 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.

Baytex Energy Corp. Second Quarter Report 2024 37

The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Corporation'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 (including covenants contained in the agreements governing any indebtedness that the Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future.

Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board of Directors of Baytex.

38  Baytex Energy Corp. Second Quarter Report 2024

Baytex Energy Corp. 

Condensed Consolidated Interim Statements of Financial Position 

(thousands of Canadian dollars) (unaudited)

			As at
	Notes		June 30, 2024			December 31, 2023
ASSETS
Current assets
Cash			$	35,887		$	55,815
Trade receivables		13, 17		429,098			339,405
Prepaids and other assets		14		22,938			21,530
Financial derivatives		17		7,028			23,274
				494,951			440,024
Non-current assets
Exploration and evaluation assets		5		122,214			90,919
Oil and gas properties		6		6,862,101			6,619,033
Other plant and equipment				9,223			7,936
Lease assets				24,237			28,145
Prepaids and other assets		14		58,867			61,729
Deferred income tax asset		14		199,333			213,145
			$	7,770,926		$	7,460,931
LIABILITIES
Current liabilities
Trade payables		17	$	617,222		$	477,295
Financial derivatives		17		5,314			—
Share-based compensation liability		11		18,312			28,508
Dividends payable		10, 17		18,161			18,381
Lease obligations				8,471			13,391
Asset retirement obligations		9		19,439			20,448
				686,919			558,023
Non-current liabilities
Other long-term liabilities				19,845			19,147
Share-based compensation liability		11		4,394			7,224
Credit facilities		7		607,589			848,749
Long-term notes		8		1,833,182			1,562,361
Lease obligations				18,001			16,056
Asset retirement obligations		9		603,586			602,951
Deferred income tax liability		14		39,269			21,333
				3,812,785			3,635,844
SHAREHOLDERS’ EQUITY
Shareholders' capital		10		6,391,108			6,527,289
Contributed surplus				246,530			193,077
Accumulated other comprehensive income				853,499			690,917
Deficit				(3,532,996	)		(3,586,196	)
				3,958,141			3,825,087
			$	7,770,926		$	7,460,931

Subsequent events (notes 10 and 17)

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2024 39

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		2024			2023			2024			2023
Revenue, net of royalties
Petroleum and natural gas sales		13	$	1,133,123		$	598,760		$	2,117,315		$	1,154,096
Royalties				(240,440	)		(107,920	)		(449,611	)		(201,173	)
				892,683			490,840			1,667,704			952,923
Expenses
Operating				167,705			119,438			341,140			231,846
Transportation				33,314			14,574			63,149			31,579
Blending and other				67,685			52,995			131,893			112,676
General and administrative				21,006			15,240			43,418			26,974
Transaction costs				—			32,832			1,539			41,703
Exploration and evaluation		5		649			369			667			532
Depletion and depreciation				353,101			176,144			697,238			342,143
Share-based compensation		11		5,565			16,918			15,088			26,741
Financing and interest		15		91,617			34,497			152,884			58,222
Financial derivatives (gain) loss		17		(8,533	)		3,038			18,329			(11,587	)
Foreign exchange loss (gain)		16		20,055			(11,939	)		59,992			(12,002	)
Loss on dispositions and property swaps				6,311			—			3,650			336
Other expense (income)				1,025			141			2,096			(917	)
				759,500			454,247			1,531,083			848,246
Net income before income taxes				133,183			36,593			136,621			104,677
Income tax expense (recovery)		14
Current income tax expense				6,475			1,350			8,155			2,470
Deferred income tax expense (recovery)				22,810			(178,360	)		38,611			(162,837	)
				29,285			(177,010	)		46,766			(160,367	)
Net income			$	103,898		$	213,603		$	89,855		$	265,044
Other comprehensive income (loss)
Foreign currency translation adjustment				52,019			(46,457	)		162,582			(47,005	)
Comprehensive income			$	155,917		$	167,146		$	252,437		$	218,039
Net income per common share		12
Basic			$	0.13		$	0.37		$	0.11		$	0.47
Diluted			$	0.13		$	0.36		$	0.11		$	0.47
Weighted average common shares (000's)		12
Basic				814,151			583,365			817,931			564,319
Diluted				818,025			588,170			821,290			569,284

See accompanying notes to the condensed consolidated interim financial statements.

40  Baytex Energy Corp. Second Quarter Report 2024

Baytex Energy Corp. 

Condensed Consolidated Interim Statements of Changes in Equity 

(thousands of Canadian dollars) (unaudited)

	Notes	Shareholders’ capital			Contributed surplus			Accumulated other comprehensive income			Deficit			Total equity
Balance at December 31, 2022		$	5,499,664		$	89,879		$	756,195		$	(3,315,321	)	$	3,030,417
Issued on corporate acquisition			1,326,435			21,316			—			—			1,347,751
Vesting of share awards			26,229			(37,462	)		—			—			(11,233	)
Share-based compensation			—			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
Balance at December 31, 2023		$	6,527,289		$	193,077		$	690,917		$	(3,586,196	)	$	3,825,087
Vesting of share awards	10		1,167			—			—			—			1,167
Repurchase of common shares for cancellation	10		(137,348	)		53,453			—			—			(83,895	)
Dividends declared	10		—			—			—			(36,655	)		(36,655	)
Comprehensive income			—			—			162,582			89,855			252,437
Balance at June 30, 2024		$	6,391,108		$	246,530		$	853,499		$	(3,532,996	)	$	3,958,141

See accompanying notes to the condensed consolidated interim financial statements.

Baytex Energy Corp. Second Quarter Report 2024 41

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	2024			2023			2024			2023
CASH PROVIDED BY (USED IN):
Operating activities
Net income		$	103,898		$	213,603		$	89,855		$	265,044
Adjustments for:
Non-cash share-based compensation	11		—			16,237			—			16,237
Unrealized foreign exchange loss (gain)	16		19,189			(12,880	)		57,907			(13,093	)
Exploration and evaluation	5		649			369			667			532
Depletion and depreciation			353,101			176,144			697,238			342,143
Non-cash financing and interest	15		37,671			6,242			45,658			11,592
Non-cash other income	9		—			—			—			(1,271	)
Unrealized financial derivatives (gain) loss	17		(10,790	)		19,403			21,560			10,193
Cash premiums on derivatives			—			(2,263	)		—			(2,263	)
Loss on dispositions and property swaps			6,311			—			3,650			336
Deferred income tax expense (recovery)	14		22,810			(178,360	)		38,611			(162,837	)
Asset retirement obligations settled	9		(7,115	)		(5,392	)		(13,626	)		(9,518	)
Change in non-cash working capital			(20,140	)		(40,795	)		(52,163	)		(79,849	)
Cash flows from operating activities			505,584			192,308			889,357			377,246
Financing activities
(Decrease) increase in credit facilities			(225,961	)		577,428			(247,516	)		601,979
Decrease in acquired credit facilities	3		—			(373,608	)		—			(373,608	)
Debt issuance costs			(25,023	)		(39,925	)		(25,023	)		(39,925	)
Payments on lease obligations			(5,478	)		(1,181	)		(10,350	)		(2,336	)
Net proceeds from issuance of long-term notes	8		780,936			1,046,197			780,936			1,046,197
Redemption of long-term notes	8		(580,913	)		—			(580,913	)		—
Redemption of acquired long-term notes	3		—			(569,256	)		—			(569,256	)
Repurchase of common shares	10		(80,890	)		—			(83,895	)		—
Dividends declared	10		(18,161	)		—			(36,655	)		—
Change in non-cash working capital			(4,105	)		—			(2,100	)		—
Cash flows (used in) from financing activities			(159,595	)		639,655			(205,516	)		663,051
Investing activities
Additions to exploration and evaluation assets	5		—			(741	)		—			(1,231	)
Additions to oil and gas properties	6		(339,573	)		(169,963	)		(752,124	)		(403,099	)
Additions to other plant and equipment			(1,279	)		(580	)		(3,536	)		(1,021	)
Corporate acquisition, net of cash acquired	3		—			(662,579	)		—			(662,579	)
Property acquisitions			(3,349	)		62			(38,752	)		(444	)
Proceeds from dispositions			2,695			50			2,720			285
Change in non-cash working capital			2,264			14,980			87,923			41,965
Cash flows used in investing activities			(339,242	)		(818,771	)		(703,769	)		(1,026,124	)
Change in cash			6,747			13,192			(19,928	)		14,173
Cash, beginning of period			29,140			6,445			55,815			5,464
Cash, end of period		$	35,887		$	19,637		$	35,887		$	19,637
Supplementary information
Interest paid		$	86,727		$	7,535		$	105,016		$	38,004
Income taxes paid		$	11,877		$	3,603		$	16,421		$	3,603

See accompanying notes to the condensed consolidated interim financial statements.

42  Baytex Energy Corp. Second Quarter Report 2024

Baytex Energy Corp.

Notes to the Condensed Consolidated Interim Financial Statements

For the periods ended June 30, 2024 and 2023

(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 in Texas, 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 PREPARATION

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 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, 2023 ("2023 annual consolidated financial statements").

The consolidated financial statements were approved by the Board of Directors of Baytex on July 25, 2024.

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 2023 annual consolidated financial statements of the Company are available through its filings on SEDAR+ at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov.

Estimation Uncertainty

Management makes judgments 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.

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 ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Sustainability Standards Board has released proposed standards that are aligned with the ISSB release and include suggestions for Canadian-specific modifications. 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.

Material Accounting Policies

Except as described below, the accounting policies, critical accounting judgments and significant estimates used in these consolidated financial statements are consistent with those used in the preparation of the 2023 annual consolidated financial statements.

New Accounting Standards Adopted

Effective January 1, 2024, Baytex adopted amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.

These amendments have not had a material impact on our consolidated financial statements.

Baytex Energy Corp. Second Quarter Report 2024 43

3. BUSINESS COMBINATION

On June 20, 2023, Baytex closed the acquisition of Ranger Oil Corporation (“Ranger”), a publicly traded oil and gas exploration and production company with operations in the Eagle Ford. Baytex acquired all of the issued and outstanding common shares of Ranger and 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 with the net assets and liabilities recorded at fair value at the acquisition date. The total consideration of US$1.6 billion ($2.1 billion) consisted of $732.8 million of cash consideration and 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 was primarily based on estimated cash flows associated with proved and probable oil and gas reserves acquired and the discount rate. Factors that impact these reserves cash flows include forecasted production volumes, royalty obligations, operating and capital costs, taxes and commodity prices. The estimation of reserves cash flows involves the expertise of the independent qualified reserve evaluators. 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 the acquired oil and gas properties were determined using a discount rate of 12.2%.

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 market rate of interest of 9.0%.

The total consideration paid and estimates of the fair value of the assets and liabilities acquired as at the date of the acquisition are set forth in the table below. The purchase price equation was based on management's best estimate of the assets acquired and liabilities assumed. There were no measurement period adjustments recorded during the three and six months ended June 30, 2024 and the purchase price is considered final.

	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	$	2,337,173		$	3,096,404
Working capital deficiency excluding bank debt and financial derivatives (3)		(120,565	)		(159,731	)
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		76,123			100,852
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) Following 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). Included in this balance is $21.3 million (US$16.1 million) of awards that were fully vested at close of the Ranger acquisition and $5.3 million (US$4.0 million) of cash-based awards included in share-based compensation liability.

(3) Includes $70.3 million (US$53.0 million) of cash. Trade receivables acquired is net of a provision for expected credit losses of approximately $0.3 million.

44  Baytex Energy Corp. Second Quarter Report 2024

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	2024			2023			2024			2023			2024			2023			2024			2023
Revenue, net of royalties
Petroleum and natural gas sales	$	508,560		$	390,292		$	624,563		$	208,468		$	—		$	—		$	1,133,123		$	598,760
Royalties		(72,894	)		(47,309	)		(167,546	)		(60,611	)		—			—			(240,440	)		(107,920	)
		435,666			342,983			457,017			147,857			—			—			892,683			490,840
Expenses
Operating		84,415			91,354			83,290			28,084			—			—			167,705			119,438
Transportation		19,569			13,240			13,745			1,334			—			—			33,314			14,574
Blending and other		67,685			52,995			—			—			—			—			67,685			52,995
General and administrative		—			—			—			—			21,006			15,240			21,006			15,240
Transaction costs		—			—			—			—			—			32,832			—			32,832
Exploration and evaluation		649			369			—			—			—			—			649			369
Depletion and depreciation		117,865			112,262			231,853			62,211			3,383			1,671			353,101			176,144
Share-based compensation		—			—			—			—			5,565			16,918			5,565			16,918
Financing and interest		—			—			—			—			91,617			34,497			91,617			34,497
Financial derivatives (gain) loss		—			—			—			—			(8,533	)		3,038			(8,533	)		3,038
Foreign exchange loss (gain)		—			—			—			—			20,055			(11,939	)		20,055			(11,939	)
Loss on dispositions and property swaps		1,356			—			4,955			—			—			—			6,311			—
Other expense		—			—			—			—			1,025			141			1,025			141
		291,539			270,220			333,843			91,629			134,118			92,398			759,500			454,247
Net income (loss) before income taxes		144,127			72,763			123,174			56,228			(134,118	)		(92,398	)		133,183			36,593
Income tax expense (recovery)
Current income tax expense																				6,475			1,350
Deferred income tax expense (recovery)																				22,810			(178,360	)
																				29,285			(177,010	)
Net income (loss)	$	144,127		$	72,763		$	123,174		$	56,228		$	(134,118	)	$	(92,398	)	$	103,898		$	213,603
Additions to exploration and evaluation assets		—			741			—			—			—			—			—			741
Additions to oil and gas properties		101,916			95,662			237,657			74,301			—			—			339,573			169,963
Corporate acquisition, net of cash acquired		—			—			—			662,439			—			—			—			662,439
Property acquisitions		1,802			(62	)		1,547			—			—			—			3,349			(62	)
Proceeds from dispositions		157			(50	)		(2,852	)		—			—			—			(2,695	)		(50	)

Baytex Energy Corp. Second Quarter Report 2024 45

	Canada						U.S.						Corporate						Consolidated
Six Months Ended June 30	2024			2023			2024			2023			2024			2023			2024			2023
Revenue, net of royalties
Petroleum and natural gas sales	$	924,873		$	775,914		$	1,192,442		$	378,182		$	—		$	—		$	2,117,315		$	1,154,096
Royalties		(129,458	)		(91,164	)		(320,153	)		(110,009	)		—			—			(449,611	)		(201,173	)
		795,415			684,750			872,289			268,173			—			—			1,667,704			952,923
Expenses
Operating		169,818			182,534			171,322			49,312			—			—			341,140			231,846
Transportation		37,779			30,245			25,370			1,334			—			—			63,149			31,579
Blending and other		131,893			112,676			—			—			—			—			131,893			112,676
General and administrative		—			—			—			—			43,418			26,974			43,418			26,974
Transaction costs		—			—			—			—			1,539			41,703			1,539			41,703
Exploration and evaluation		667			532			—			—			—			—			667			532
Depletion and depreciation		234,861			231,733			456,292			107,175			6,085			3,235			697,238			342,143
Share-based compensation		—			—			—			—			15,088			26,741			15,088			26,741
Financing and interest		—			—			—			—			152,884			58,222			152,884			58,222
Financial derivatives loss (gain)		—			—			—			—			18,329			(11,587	)		18,329			(11,587	)
Foreign exchange loss (gain)		—			—			—			—			59,992			(12,002	)		59,992			(12,002	)
(Gain) loss on dispositions and property swaps		(1,055	)		336			4,705			—			—			—			3,650			336
Other expense (income)		—			(1,271	)		—			—			2,096			354			2,096			(917	)
		573,963			556,785			657,689			157,821			299,431			133,640			1,531,083			848,246
Net income (loss) before income taxes		221,452			127,965			214,600			110,352			(299,431	)		(133,640	)		136,621			104,677
Income tax expense (recovery)
Current income tax expense																				8,155			2,470
Deferred income tax expense (recovery)																				38,611			(162,837	)
																				46,766			(160,367	)
Net income (loss)	$	221,452		$	127,965		$	214,600		$	110,352		$	(299,431	)	$	(133,640	)	$	89,855		$	265,044
Additions to exploration and evaluation assets		—			1,231			—			—			—			—			—			1,231
Additions to oil and gas properties		260,042			279,778			492,082			123,321			—			—			752,124			403,099
Corporate acquisition, net of cash acquired		—			—			—			662,439			—			—			—			662,439
Property acquisitions		36,077			444			2,675			—			—			—			38,752			444
Proceeds from dispositions		132			(285	)		(2,852	)		—			—			—			(2,720	)		(285	)

	June 30, 2024		December 31, 2023
Canadian assets	$	2,415,720	$	2,289,083
U.S. assets		5,314,718		5,112,493
Corporate assets		40,488		59,355
Total consolidated assets	$	7,770,926	$	7,460,931

46  Baytex Energy Corp. Second Quarter Report 2024

5. EXPLORATION AND EVALUATION ASSETS

	June 30, 2024			December 31, 2023
Balance, beginning of period	$	90,919		$	168,684
Property acquisitions		35,467			18,486
Divestitures		(1,173	)		(2,965	)
Property swaps		(68	)		1,000
Exploration and evaluation expense		(667	)		(8,896	)
Transfer to oil and gas properties (note 6)		(2,264	)		(83,530	)
Foreign currency translation		—			(1,860	)
Balance, end of period	$	122,214		$	90,919

At June 30, 2024 and December 31, 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").

6. OIL AND GAS PROPERTIES

	Cost			Accumulated depletion			Net book value
Balance, December 31, 2022	$	12,042,216		$	(7,421,450	)	$	4,620,766
Capital expenditures		1,012,787			—			1,012,787
Corporate acquisition (note 3)		3,096,404			—			3,096,404
Property acquisitions		20,263			—			20,263
Transfers from exploration and evaluation assets (note 5)		83,530			—			83,530
Transfers from lease assets		7,611			—			7,611
Change in asset retirement obligations (note 9)		54,166			—			54,166
Divestitures		(660,920	)		317,651			(343,269	)
Property swaps		(2,975	)		3,756			781
Impairment loss		—			(833,662	)		(833,662	)
Foreign currency translation		(127,065	)		66,501			(60,564	)
Depletion		—			(1,039,780	)		(1,039,780	)
Balance, December 31, 2023	$	15,526,017		$	(8,906,984	)	$	6,619,033
Capital expenditures		752,124			—			752,124
Property acquisitions		3,334			—			3,334
Transfers from exploration and evaluation assets (note 5)		2,264			—			2,264
Transfers from lease assets		7,418			—			7,418
Change in asset retirement obligations (note 9)		1,291			—			1,291
Divestitures		(2,626	)		469			(2,157	)
Property swaps		997			682			1,679
Foreign currency translation		305,550			(137,282	)		168,268
Depletion		—			(691,153	)		(691,153	)
Balance, June 30, 2024	$	16,596,369		$	(9,734,268	)	$	6,862,101

At June 30, 2024, there were no indicators of impairment or impairment reversal for oil and gas properties in any of the Company's CGUs.

At December 31, 2023, the Company identified indicators of impairment for oil and gas properties in the legacy non-operated Eagle Ford CGU due to changes in reserves and in the Viking CGU due to changes in reserves and a loss recorded on disposition of an asset. The recoverable amounts for the two CGUs were not sufficient to support their carrying values which resulted in an impairment loss of $833.7 million recorded at December 31, 2023. The recoverable amount for each CGU is based on estimated cash flows associated with proved and probable oil and gas reserves from an independent reserve report prepared as at December 31, 2023 utilizing a discount rate based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 14%.

Baytex Energy Corp. Second Quarter Report 2024 47

7. CREDIT FACILITIES

	June 30, 2024			December 31, 2023
Credit facilities - U.S. dollar denominated (1)	$	244,305		$	311,980
Credit facilities - Canadian dollar denominated		381,671			552,756
Credit facilities - principal (2)		625,976			864,736
Unamortized debt issuance costs		(18,387	)		(15,987	)
Credit facilities	$	607,589		$	848,749

(1)	U.S. dollar denominated credit facilities balance was US$178.5 million as at June 30, 2024 (December 31, 2023 - US$236.3 million).
(2)	The decrease in the principal amount of the credit facilities outstanding from December 31, 2023 to June 30, 2024 is the result of net repayments of $247.5 million, partially offset by an increase in the reported amount of U.S. denominated debt of $8.8 million due to foreign exchange.

On May 9, 2024, Baytex extended the maturity of the revolving credit facilities (the "Credit Facilities") from April 1, 2026 to May 9, 2028. There are no changes to the loan balances or financial covenants as a result of the amendment. Following the amendment, borrowing in Canadian funds previously based on the banker's acceptance rate has been replaced with borrowings based on the Canadian Overnight Repo Rate Average ("CORRA").

At June 30, 2024, Baytex had US$1.1 billion ($1.5 billion) of revolving credit facilities that mature on May 9, 2028. The Credit 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 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, CORRA rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the Credit Facilities was 8.0% for the six months ended June 30, 2024 (6.5% for six months ended June 30, 2023).

The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2024.

Covenant Description	Position as at June 30, 2024	Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)	0.3:1.0	3.5:1.0
Interest Coverage (3) (Minimum Ratio)	10.3:1.0	3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio)	1.1:1.0	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, 2024, the Company's Senior Secured Debt totaled $630.6 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, 2024 was $2.3 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 including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Financing and interest expense for the twelve months ended June 30, 2024 was $219.0 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 payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at June 30, 2024, the Company's Total Debt totaled $2.5 billion of principal amounts outstanding.

At June 30, 2024, Baytex had $5.7 million of outstanding letters of credit (December 31, 2023 - $5.6 million outstanding) under the Credit Facilities.

48  Baytex Energy Corp. Second Quarter Report 2024

8. LONG-TERM NOTES

	June 30, 2024			December 31, 2023
8.75% notes due April 1, 2027 (1)	$	—		$	541,114
8.50% notes due April 30, 2030 (2)		1,094,920			1,056,361
7.375% notes due March 15, 2032 (3)		786,974			—
Total long-term notes - principal (4)		1,881,894			1,597,475
Unamortized debt issuance costs		(48,712	)		(35,114	)
Total long-term notes - net of unamortized debt issuance costs	$	1,833,182		$	1,562,361

(1)	The 8.75% notes were fully repaid on April 1, 2024. The U.S. dollar denominated principal outstanding of the 8.75% notes was US$409.8 million as at December 31, 2023.
(2)	The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million as at June 30, 2024 (December 31, 2023 - US$800.0 million).
(3)	The U.S. dollar denominated principal outstanding of the 7.375% notes was US$575.0 million as at June 30, 2024 (December 31, 2023 - nil).
(4)	The increase in the principal amount of long-term notes outstanding from December 31, 2023 to June 30, 2024 is the result of the issuance of the 7.375% notes for $780.9 million and changes in the reported amount of U.S. denominated debt of $60.0 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding. This was partially offset by the repayment of the 8.75% notes for $556.6 million.

On April 1, 2024, Baytex closed a private offering of the US$575 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"). The 7.375% Senior Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15, 2032. The 7.375% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity. Proceeds from the 7.375% Senior Notes were used to redeem the remaining US$409.8 million aggregate principal amount of the outstanding 8.75% Senior Notes at 104.375% of par value, pay the related fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities. During Q2 2024, Baytex recorded early redemption expense of $24.4 million which is the call premium paid on the redemption of the 8.75% Senior Notes.

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

Baytex Energy Corp. Second Quarter Report 2024 49

9. ASSET RETIREMENT OBLIGATIONS

	June 30, 2024			December 31, 2023
Balance, beginning of period	$	623,399		$	588,923
Liabilities incurred (1)		10,275			24,185
Liabilities settled		(13,626	)		(26,416	)
Liabilities assumed from corporate acquisition (note 3)		—			31,310
Liabilities acquired from property acquisitions		81			11
Liabilities divested		(1,043	)		(43,153	)
Property swaps		(728	)		76
Accretion (note 15)		10,386			20,406
Government grants (2)		—			(1,271	)
Change in estimate (1)		8,100			17,067
Changes in discount and inflation rates (1)(3)		(17,084	)		12,914
Foreign currency translation		3,265			(653	)
Balance, end of period	$	623,025		$	623,399
Less current portion of asset retirement obligations		19,439			20,448
Non-current portion of asset retirement obligations	$	603,586		$	602,951

(1)	The total of these items reflects the total change in asset retirement obligations of $1.3 million per Note 6 - Oil and Gas Properties ($54.2 million increase in 2023).
(2)	Certain government grants were provided by the Government of Alberta and the Government of Saskatchewan under programs that were completed during the year ended December 31, 2023. During the six months ended June 30, 2024, no amounts have been recognized under these programs ($1.3 million for the year ended December 31, 2023).
(3)	The discount and inflation rates used to calculate the liability for our Canadian operations at June 30, 2024 were 3.4% and 1.8% respectively (December 31, 2023 - 3.0% and 1.6%). The discount and inflation rates used to calculate the liability for our U.S. operations at June 30, 2024 were 4.5% and 2.3%, respectively (December 31, 2023 - 4.0% and 2.1%).

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. As at June 30, 2024, 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.

	Number of Common Shares (000s)			Amount
Balance, December 31, 2022		544,930		$	5,499,664
Issued on corporate acquisition		311,370			1,326,435
Vesting of share awards		5,892			26,229
Common shares repurchased and cancelled		(40,511	)		(325,039	)
Balance, December 31, 2023		821,681		$	6,527,289
Vesting of share awards		272			1,167
Common shares repurchased and cancelled		(16,976	)		(137,348	)
Balance, June 30, 2024		804,977		$	6,391,108

Normal Course Issuer Bid ("NCIB") Share Repurchases

On June 26, 2024, Baytex announced that the Toronto Stock Exchange ("TSX") accepted the renewal of the NCIB under which Baytex is permitted to purchase for cancellation up to 70.1 million common shares over the 12-month period commencing July 2, 2024. The number of shares authorized for repurchase represented 10% of the Company's public float, as defined by the TSX, as at June 18, 2024. On June 18, 2024 Baytex had 808.0 million common shares outstanding.

During the six months ended June 30, 2024, Baytex recorded $83.9 million related to common share repurchases, which includes $82.3 million of consideration paid for the repurchase and cancellation of common shares as well as $1.6 million of federal tax levied on equity repurchases.

50  Baytex Energy Corp. Second Quarter Report 2024

Purchases are made on the open market at prices prevailing at the time of the transaction. During the six months ended June 30, 2024, Baytex repurchased and cancelled 17.0 million common shares at an average price of $4.85 per share for total consideration of $82.3 million. During 2023, Baytex repurchased and cancelled 40.5 million common shares at an average price of $5.48 per share for total consideration of $221.9 million. The total consideration paid includes the commissions and fees paid as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased and cancelled are accounted for as a reduction in shareholders' capital at historical cost, with any discount paid recorded to contributed surplus and any premium paid recorded to retained earnings.

Effective January 1, 2024, the Government of Canada introduced a 2% federal tax on equity repurchases. During the six months ended June 30, 2024, Baytex recorded a $1.6 million liability, charged to shareholders’ capital, related to the federal tax on equity repurchases.

Dividends

The following dividends were declared by Baytex during the six months ended June 30, 2024.

Record Date	Payable Date	Per Share Amount		Dividend Amount
March 15, 2024	April 1, 2024	$	0.0225	$	18,494
June 14, 2024	July 2, 2024		0.0225		18,161
Total dividends declared				$	36,655

On July 25, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2024 for shareholders on record as at September 16, 2024.

11. SHARE-BASED COMPENSATION PLAN

For the three and six months ended June 30, 2024 the Company recorded total share-based compensation expense of $5.6 million and $15.1 million respectively ($16.9 million and $26.7 million for the three and six months ended June 30, 2023) which is comprised of the expense related to cash-settled awards.

The Company's closing share price on the Toronto Stock Exchange on June 30, 2024 was $4.74 (December 31, 2023 - $4.38 and June 30, 2023 - $4.32).

The number of awards outstanding is detailed below:

(000s)	Restricted awards		Performance awards		Incentive awards		Director Share Units	Total
Total, December 31, 2022	762		4,796		5,109		967	11,634
Granted	41		2,641		2,607		278	5,567
Assumed on corporate acquisition (1)	10,789		—		—		—	10,789
Vested	(9,302	)	(3,767	)	(2,715	)	—	(15,784	)
Forfeited	(11	)	(315	)	(518	)	—	(844	)
Total, December 31, 2023	2,279		3,355		4,483		1,245	11,362
Granted	5		2,323		3,478		167	5,973
Added by performance factor	—		524		—		—	524
Vested	(1,457	)	(2,443	)	(2,515	)	—	(6,415	)
Forfeited	—		(20	)	(56	)	—	(76	)
Total, June 30, 2024	827		3,739		5,390		1,412	11,368

(1) Following the closing of the transaction, holders of awards outstanding under Ranger's Share Award Plan were 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 is recognized over the remaining future service periods.

Baytex Energy Corp. Second Quarter Report 2024 51

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 share-based compensation liability.

In 2023, Baytex became the successor to Ranger's Share Award Plan (note 3). Awards outstanding as at the closing day of the acquisition 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, 2024 was $4.28 per restricted and performance award ($5.41 for the six months ended June 30, 2023).

Incentive Award Plan

Baytex has an Incentive Award Plan whereby the participants of the plan are entitled to receive a cash payment equal to the value of one Baytex common share per incentive award 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 share-based compensation liability.

The weighted average fair value of share awards granted during the six months ended June 30, 2024 was $4.28 per incentive award ($5.39 for the six months ended June 30, 2023).

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 share-based compensation liability.

The weighted average fair value of share awards granted during the six months ended June 30, 2024 was $4.48 per DSU award ($5.49 for the six months ended June 30, 2023).

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.

52  Baytex Energy Corp. Second Quarter Report 2024

	Three Months Ended June 30
	2024					2023
			Weighted average					Weighted average
			common shares	Net income				common shares	Net income
	Net income		(000s)	per share		Net income		(000s)	per share
Net income - basic	$	103,898	814,151	$	0.13	$	213,603	583,365	$	0.37
Dilutive effect of share awards		—	3,874		—		—	4,805		—
Net income - diluted	$	103,898	818,025	$	0.13	$	213,603	588,170	$	0.36

	Six Months Ended June 30
	2024					2023
			Weighted average					Weighted average
			common shares	Net income				common shares	Net income
	Net income		(000s)	per share		Net income		(000s)	per share
Net income - basic	$	89,855	817,931	$	0.11	$	265,044	564,319	$	0.47
Dilutive effect of share awards		—	3,359		—		—	4,965		—
Net income - diluted	$	89,855	821,290	$	0.11	$	265,044	569,284	$	0.47

For the three and six months ended June 30, 2024 and June 30, 2023, no share awards were excluded from the calculation of diluted income per share as their effect was 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
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	104,030	$	558,620	$	662,650	$	124,965	$	183,845	$	308,810
Heavy oil		394,960		—		394,960		251,449		—		251,449
NGL		5,144		44,366		49,510		3,772		16,391		20,163
Natural gas sales		4,426		21,577		26,003		10,106		8,232		18,338
Total petroleum and natural gas sales	$	508,560	$	624,563	$	1,133,123	$	390,292	$	208,468	$	598,760

	Six Months Ended June 30
	2024						2023
	Canada		U.S.		Total		Canada		U.S.		Total
Light oil and condensate	$	199,251	$	1,064,514	$	1,263,765	$	271,420	$	325,855	$	597,275
Heavy oil		699,884		—		699,884		468,534		—		468,534
NGL		11,513		83,928		95,441		9,832		32,165		41,997
Natural gas sales		14,225		44,000		58,225		26,128		20,162		46,290
Total petroleum and natural gas sales	$	924,873	$	1,192,442	$	2,117,315	$	775,914	$	378,182	$	1,154,096

Included in accounts receivable at June 30, 2024 is $362.7 million of accrued receivables related to delivered volumes (December 31, 2023 - $271.1 million).

Baytex Energy Corp. Second Quarter Report 2024 53

14. INCOME TAXES

The provision for income taxes has been computed as follows:

	Six Months Ended June 30
	2024			2023
Net income before income taxes	$	136,621		$	104,677
Expected income taxes at the statutory rate of 24.64% (2023 – 24.80%)		33,663			25,960
Change in income taxes resulting from:
Effect of foreign exchange		7,398			(1,612	)
Effect of rate adjustments for foreign jurisdictions		(5,085	)		(2,883	)
Effect of change in deferred tax benefit not recognized (1)		2,145			(1,613	)
Effect of internal debt restructuring (2)		—			(186,460	)
Repatriation and related taxes		7,413			—
Adjustments, assessments and other		1,232			6,241
Income tax expense (recovery)	$	46,766		$	(160,367	)

(1) A deferred tax asset of $42.8 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains (December 31, 2023 - $40.4 million). These deferred income tax assets relate to capital losses of $161.9 million and non-capital losses of $92.9 million.

In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court of Canada and we estimate it could take between two and three years to receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During Q4/2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $208.6 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.

15. FINANCING AND INTEREST

	Three Months Ended June 30				Six Months Ended June 30
	2024		2023		2024		2023
Interest on Credit Facilities	$	15,639	$	7,535	$	33,928	$	13,751
Interest on long-term notes		37,656		20,565		72,334		32,659
Interest on lease obligations		651		155		964		220
Cash interest	$	53,946	$	28,255	$	107,226	$	46,630
Amortization of debt issue costs		7,862		1,847		10,922		2,371
Accretion on asset retirement obligations (note 9)		5,459		4,395		10,386		9,221
Early redemption expense (note 8)		24,350		—		24,350		—
Financing and interest	$	91,617	$	34,497	$	152,884	$	58,222

54  Baytex Energy Corp. Second Quarter Report 2024

16. FOREIGN EXCHANGE

	Three Months Ended June 30					Six Months Ended June 30
	2024		2023			2024		2023
Unrealized foreign exchange loss (gain)	$	19,189	$	(12,880	)	$	57,907	$	(13,093	)
Realized foreign exchange loss		866		941			2,085		1,091
Foreign exchange loss (gain)	$	20,055	$	(11,939	)	$	59,992	$	(12,002	)

17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company's financial assets and liabilities are comprised of cash, trade receivables, trade payables, dividends payable, financial derivatives, Credit Facilities and long-term notes. The fair value of trade receivables and trade 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, 2024						December 31, 2023
													Fair Value
													Measurement
	Carrying value			Fair value			Carrying value			Fair value			Hierarchy
Financial Assets
Fair value through profit and loss
Financial derivatives	$	7,028		$	7,028		$	23,274		$	23,274			Level 2
Total	$	7,028		$	7,028		$	23,274		$	23,274
Amortized cost
Cash	$	35,887		$	35,887		$	55,815		$	55,815			—
Trade receivables		429,098			429,098			339,405			339,405			—
Total	$	464,985		$	464,985		$	395,220		$	395,220
Financial Liabilities
Fair value through profit and loss
Financial derivatives	$	(5,314	)	$	(5,314	)	$	—		$	—			Level 2
Total	$	(5,314	)	$	(5,314	)	$	—		$	—
Amortized cost
Trade payables	$	(617,222	)	$	(617,222	)	$	(477,295	)	$	(477,295	)		—
Dividends payable		(18,161	)		(18,161	)		(18,381	)		(18,381	)		—
Credit Facilities		(607,589	)		(625,976	)		(848,749	)		(864,736	)		—
Long-term notes		(1,833,182	)		(1,946,995	)		(1,562,361	)		(1,653,118	)		Level 1
Total	$	(3,076,154	)	$	(3,208,354	)	$	(2,906,786	)	$	(3,013,530	)

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2024 and 2023.

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, 2024		December 31, 2023		June 30, 2024		December 31, 2023
U.S. dollar denominated	US$	10,256	US$	17,923	US$	1,405,172	US$	1,249,725

Baytex Energy Corp. Second Quarter Report 2024 55

Commodity Price Risk

Financial Derivative Contracts

As at July 25, 2024 Baytex had the following commodity financial derivative contracts for the period subsequent to June 30, 2024.

	Remaining Period	Volume	Price/Unit (1)	Index
Oil
Basis differential	July 2024 to Dec 2024	15,000 bbl/d	Baytex pays: WCS differential at Hardisty	WCS
			Baytex receives: WCS differential at Houston less US$8.31/bbl
Basis differential	July 2024 to Dec 2024	6,000 bbl/d	WTI less US$13.58/bbl	WCS
Basis differential	July 2024 to Dec 2024	8,250 bbl/d	WTI less US$2.78/bbl	MSW
Basis differential	Jan 2025 to Dec 2025	2,000 bbl/d	WTI less US$2.75/bbl	MSW
Collar	July 2024 to Dec 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Sep 2024	10,000 bbl/d	US$60.00/US$100.00	WTI
Collar	July 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$94.15	WTI
Collar	July 2024 to Dec 2024	1,500 bbl/d	US$60.00/US$90.35	WTI
Collar	July 2024 to Dec 2024	1,000 bbl/d	US$60.00/US$90.00	WTI
Collar	July 2024 to Dec 2024	2,000 bbl/d	US$60.00/US$85.00	WTI
Collar	July 2024 to Dec 2024	2,000 bbl/d	US$60.00/US$84.60	WTI
Collar	July 2024 to Dec 2024	5,000 bbl/d	US$60.00/US$84.15	WTI
Collar	Oct 2024 to Dec 2024	2,500 bbl/d	US$60.00/US$100.00	WTI
Collar	Oct 2024 to Dec 2024	3,500 bbl/d	US$60.00/US$87.10	WTI
Collar	Oct 2024 to Dec 2024	3,500 bbl/d	US$60.00/US$85.75	WTI
Collar	Jan 2025 to Mar 2025	5,000 bbl/d	US$60.00/US$88.70	WTI
Collar	Jan 2025 to Mar 2025	2,500 bbl/d	US$60.00/US$90.20	WTI
Collar	Jan 2025 to Mar 2025	2,500 bbl/d	US$60.00/US$90.05	WTI
Collar	Jan 2025 to Mar 2025	7,500 bbl/d	US$60.00/US$90.00	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$94.25	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$93.90	WTI
Collar	Jan 2025 to Jun 2025	5,000 bbl/d	US$60.00/US$91.95	WTI
Collar	Jan 2025 to Jun 2025	2,500 bbl/d	US$60.00/US$90.00	WTI
Collar	Jan 2025 to Jun 2025	3,000 bbl/d	US$60.00/US$89.55	WTI
Collar	Apr 2025 to Jun 2025	2,000 bbl/d	US$60.00/US$88.17	WTI
Collar (2)	Apr 2025 to Jun 2025	5,000 bbl/d	US$60.00/US$90.50	WTI
Collar (2)	Apr 2025 to Jun 2025	3,000 bbl/d	US$60.00/US$90.60	WTI
Natural Gas
Collar	July 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.185	NYMEX
Collar	July 2024 to Dec 2024	8,500 mmbtu/d	US$3.00/US$4.15	NYMEX
Collar	July 2024 to Dec 2024	5,000 mmbtu/d	US$3.00/US$4.10	NYMEX
Collar	July 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.09	NYMEX
Collar	July 2024 to Dec 2024	2,500 mmbtu/d	US$3.00/US$4.06	NYMEX
Collar	Jan 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.01	NYMEX
Collar	Jan 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.03	NYMEX
Collar	Jan 2025 to Dec 2025	5,000 mmbtu/d	US$3.25/US$4.08	NYMEX
Collar	Jan 2025 to Dec 2025	3,000 mmbtu/d	US$3.25/US$4.135	NYMEX
Collar	Jan 2025 to Dec 2025	5,500 mmbtu/d	US$3.25/US$4.14	NYMEX
Collar	Jan 2025 to Dec 2025	7,000 mmbtu/d	US$3.00/US$4.32	NYMEX
Collar	Jan 2025 to Dec 2025	3,000 mmbtu/d	US$3.00/US$4.85	NYMEX
Collar	Jan 2025 to Dec 2025	8,000 mmbtu/d	US$3.00/US$4.855	NYMEX
Collar	Jan 2026 to Dec 2026	11,000 mmbtu/d	US$3.25/US$5.02	NYMEX

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

(2)            Contract entered subsequent to June 30, 2024.

56  Baytex Energy Corp. Second Quarter Report 2024

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
	2024			2023			2024			2023
Realized financial derivatives loss (gain)	$	2,257		$	(16,365	)	$	(3,231	)	$	(21,780	)
Unrealized financial derivatives (gain) loss		(10,790	)		19,403			21,560			10,193
Financial derivatives (gain) loss	$	(8,533	)	$	3,038		$	18,329		$	(11,587	)

18. CAPITAL MANAGEMENT

The Company's capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute its development programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At June 30, 2024, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, share-based compensation liability, dividends payable, 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 payables, dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables and prepaids and other assets. 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, 2024			December 31, 2023
Credit Facilities	$	607,589		$	848,749
Unamortized debt issuance costs - Credit Facilities (note 7)		18,387			15,987
Long-term notes		1,833,182			1,562,361
Unamortized debt issuance costs - Long-term notes (note 8)		48,712			35,114
Trade payables		617,222			477,295
Share-based compensation liability		22,706			35,732
Dividends payable		18,161			18,381
Other long-term liabilities		19,845			19,147
Cash		(35,887	)		(55,815	)
Trade receivables		(429,098	)		(339,405	)
Prepaids and other assets		(81,805	)		(83,259	)
Net Debt	$	2,639,014		$	2,534,287

Baytex Energy Corp. Second Quarter Report 2024 57

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
	2024		2023		2024		2023
Cash flows from operating activities	$	505,584	$	192,308	$	889,357	$	377,246
Change in non-cash working capital		20,140		40,795		52,163		79,849
Asset retirement obligations settled		7,115		5,392		13,626		9,518
Transaction costs		—		32,832		1,539		41,703
Cash premiums on derivatives		—		2,263		—		2,263
Adjusted Funds Flow	$	532,839	$	273,590	$	956,685	$	510,579

58  Baytex Energy Corp. Second Quarter Report 2024

ABBREVIATIONS

AECO	the natural gas storage facility located at Suffield, Alberta
bbl	barrel
bbl/d	barrel per day
boe*	barrels of oil equivalent
boe/d	barrels of oil equivalent per day
COSO	Committee of Sponsoring Organizations of the Treadway Commission
GAAP	generally accepted accounting principles
GJ	gigajoule
GJ/d	gigajoule per day
IAS	International Accounting Standard
IASB	International Accounting Standards Board
IFRS	International Financial Reporting Standards
LLS	Louisiana Light Sweet
mbbl	thousand barrels
mboe*	thousand barrels of oil equivalent
mcf	thousand cubic feet
mcf/d	thousand cubic feet per day
mmBtu	million British Thermal Units
mmBtu/d	million British Thermal Units per day
mmcf	million cubic feet
mmcf/d	million cubic feet per day
NGL	natural gas liquids
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
TSX	Toronto Stock Exchange
WCS	Western Canadian Select
WTI	West Texas Intermediate

* Oil equivalent amounts may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio for natural gas of 6 Mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Baytex Energy Corp. Second Quarter Report 2024 59

CORPORATE INFORMATION

BOARD OF DIRECTORS

Mark R. Bly 

Chairman of the Board

Eric T. Greager 

Director

Tiffany (TJ) Thom Cepak ^1,3 

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 ^2,4 

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

BAYTEXENERGY.COM

Design: ARTHUR / HUNTER 

Printing: Merrill Corporation

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 C. 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 M.P. Lessoway 

Vice President, 

Finance and Treasurer

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