Calgary, Alberta--(Newsfile Corp. - July 25, 2024) - Baytex Energy Corp. (TSX:BTE) (NYSE:BTE) ("Baytex") 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, 2024		March 31, 2024		June 30, 2023		June 30, 2024		June 30, 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.

		Three Months Ended						Six Months Ended
		June 30, 2024		March 31, 2024		June 30, 2023		June 30, 2024		June 30, 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.

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.

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.

Conference Call Tomorrow
9:00 a.m. MT (11:00 a.m. ET)

Baytex will host a conference call tomorrow, July 26, 2024, starting at 9:00am MT (11:00am ET). To participate, please dial toll free in North America 1-844-763-8274 or international 1-647-484-8814. Alternatively, to listen to the conference call online, please enter https://event.choruscall.com/mediaframe/webcast.html?webcastid=hk99Bfmj in your web browser. To register, visit our website at https://www.baytexenergy.com/investors/events-presentations.
An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.

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.

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.

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
($ thousands)		June 30, 2024		March 31, 2024		June 30, 2023		June 30, 2024		June 30, 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
($ thousands)		June 30, 2024		March 31, 2024		June 30, 2023		June 30, 2024		June 30, 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

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.

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.

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
	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada - Heavy
Peace River	9,116	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
	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)	Heavy Crude Oil (bbl/d)	Light and Medium Crude Oil (bbl/d)	NGL (bbl/d)	Natural Gas (Mcf/d)	Oil Equivalent (boe/d)
Canada - Heavy
Peace River	9,299	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

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