Mitel Announces New Board of Directors to Enhance Leadership and Accelerate Momentum in the UC Market
OTTAWA, Ontario — Mitel, a global leader in business communications, today announced its new Board of Directors, led by Tony Abate as Chair. Following the company's successful financial restructuring, the newly appointed board will provide strategic direction as Mitel implements its strategy to meet the rising demand for hybrid communications and drive long-term, sustainable growth.
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Tony Abate – Chairman of GTT Communications and Tacora Resources; 35-year veteran in scaling infrastructure, software, and technology platforms
Marc Lefar – Former CEO of Vonage and RentPath; CMO of Cingular Wireless (AT&T); Former Director of IPC Systems, cxLoyalty and ClassPass; track record of steering companies through strategic pivots, scaling businesses and advising leadership teams
Marika Lulay – Current director at Aareal Bank, EnBW and FAZ GmbH; former CEO of GFT Technologies SE; recognized leader in enterprise digital transformation
Mike Robinson – Former CEO of Sungard AS, Former CEO of Broadview Networks, Former CFO of US LEC, and Chairman of Everstream Solutions; proven leader of global infrastructure businesses, driving growth and large-scale transformations
Carl Wiese – Former CRO of HP/Poly and President, Global Sales & Service of Blackberry; decades of global go-to-market leadership in unified communications
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These seasoned industry veterans join directors Tarun Loomba, Mitel's President & CEO, and Peter Wollman, Portfolio Manager for Invesco's Global Private Credit Group.
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'As we step into Mitel's next phase, a board that pairs operational rigor with strategic vision is essential,' said Tarun Loomba, Mitel President & CEO. 'Tony, Marc, Marika, Mike, and Carl have each led companies through pivotal transformations. Their guidance and expertise will be invaluable as we optimize our portfolio, deepen channel partnerships, and deliver value for our customers in critical industries around the world.'
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As part of the company's restructuring plan, the new board has been carefully recruited to provide specific subject matter expertise, strategic governance, and functional support to the management team as Mitel seeks to increase value for its customers, partners, employees, and stakeholders.
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'Unified communications sit at the heart of modern critical infrastructure,' added Tony Abate. 'Mitel's global installed base, channel strength, and enhanced balance sheet, combined with the significant market opportunity, position the company to capture increasing demand for secure, flexible, and AI-powered communications. I look forward to supporting the Mitel team as we focus on building durable, profitable growth.'
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Founded in 1971, Mitel has spent over 50 years driving innovation and shaping the Unified Communications (UC) landscape. The board appointments come at a critical juncture for Mitel, a global leader in business communications that powers communication for 75+ million users across 100+ countries. This announcement follows a series of notable milestones, including Mitel's recent financial restructuring, Mitel's continued partnership with Zoom, Mitel's OpenScape Voice platform achieving JITC certification, the launch of Mitel Unified Communications Accelerator, powered by L-SPARK Select, and the general availability of Mitel's AI-powered customer experience (CX) management platform, Mitel CX. To learn more about Mitel, visit www.mitel.com.
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We will continue to monitor market conditions and execute a prudent approach to shareholder returns, which has historically included a combination of share buybacks and quarterly dividend payments. (1) Capital management measure. Refer to the Specified Financial Measures section in this press release for further information. (2) Ratio is calculated as total debt on June 30, 2025 divided by EBITDA for the twelve months ended June 30, 2025. Total debt and EBITDA are calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at (3) 2025 full-year pricing assumptions: WTI - US$67.75/bbl; WCS differential - US$11.50/bbl; NYMEX Gas - US$3.60/MMbtu; Exchange Rate (CAD/USD) - 1.39. (4) Specified financial measure that does not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and may not be comparable with the calculation of similar measures presented by other entities. 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Three Months Ended Six Months Ended June 30, 2025 March 31, 2025 June 30, 2024 June 30, 2025 June 30, 2024 FINANCIAL (thousands of Canadian dollars, except per common share amounts) Petroleum and natural gas sales $ 886,579 $ 999,130 $ 1,133,123 $ 1,885,709 $ 2,117,315 Adjusted funds flow (1) 366,919 463,870 532,839 830,789 956,685 Per share - basic 0.48 0.60 0.65 1.08 1.17 Per share - diluted 0.48 0.60 0.65 1.07 1.16 Free cash flow (2) 3,188 52,529 180,673 55,717 180,585 Per share - basic - 0.07 0.22 0.07 0.22 Per share - diluted - 0.07 0.22 0.07 0.22 Cash flows from operating activities 354,312 431,317 505,584 785,629 889,357 Per share - basic 0.46 0.56 0.62 1.02 1.09 Per share - diluted 0.46 0.56 0.62 1.02 1.08 Net income 151,549 69,591 103,898 221,140 89,855 Per share - basic 0.20 0.09 0.13 0.29 0.11 Per share - diluted 0.20 0.09 0.13 0.29 0.11 Dividends declared 17,304 17,334 18,161 34,593 36,655 Per share 0.0225 0.0225 0.0225 0.0450 0.0450 Capital Expenditures Exploration and development expenditures $ 356,532 $ 405,097 $ 339,573 $ 761,629 $ 752,124 Acquisitions and divestitures 468 (1,009) 654 (541) 36,032 Total oil and natural gas capital expenditures $ 357,000 $ 404,088 $ 340,227 $ 761,088 $ 788,156 Net Debt Credit facilities $ 333,516 $ 250,284 $ 625,976 $ 333,516 $ 625,976 Long-term notes 1,817,707 1,977,044 1,881,894 1,817,707 1,881,894 Total debt (3) 2,151,223 2,227,328 2,507,870 2,151,223 2,507,870 Working capital deficiency (2) 142,717 162,922 131,144 142,717 131,144 Net debt (1) $ 2,293,940 $ 2,390,250 $ 2,639,014 $ 2,293,940 $ 2,639,014 Shares Outstanding - basic (thousands) Weighted average 768,717 771,443 814,151 770,072 817,931 End of period 768,317 770,039 804,977 768,317 804,977 BENCHMARK PRICES Crude oil WTI (US$/bbl) $ 63.74 $ 71.42 $ 80.57 $ 67.58 $ 78.77 MEH oil (US$/bbl) 65.56 73.37 83.10 69.47 81.03 MEH oil differential to WTI (US$/bbl) 1.82 1.95 2.53 1.89 2.26 Edmonton par ($/bbl) 84.15 95.27 105.30 89.71 98.73 Edmonton par differential to WTI (US$/bbl) (2.94) (5.03) (3.62) (3.93) (6.10) WCS heavy oil ($/bbl) 74.10 84.33 91.72 79.15 84.68 WCS differential to WTI (US$/bbl) (10.20) (12.65) (13.55) (11.43) (16.44) Natural gas NYMEX (US$/MMbtu) $ 3.44 $ 3.65 $ 1.89 $ 3.55 $ 2.07 AECO ($/Mcf) 2.07 2.02 1.44 2.05 1.74 CAD/USD average exchange rate 1.3840 1.4350 1.3684 1.4095 1.3586 Notes: (1) Capital management measure. 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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 and cash share-based compensation. Refer to the Q2/2025 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 expense, transportation expense, general and administrative expense, cash interest, realized financial derivatives gain or loss, or other, divided by barrels of oil equivalent production volume for the applicable period. Financial Results During the second quarter, we delivered operating and financial results in line with our full-year plan. Adjusted funds flow (1) was $367 million ($0.48 per basic share) and net income was $152 million ($0.20 per basic share). We generated free cash flow (2) of $3 million and returned $21 million to shareholders through share repurchases of $4 million (1.7 million shares at an average price of $2.36) and a quarterly dividend payment of $17 million. Net debt (1) decreased 4% ($96 million) to $2.3 billion, driven by unrealized foreign exchange gains from a strengthening Canadian dollar on our U.S. dollar-denominated debt. During the quarter, we repurchased and cancelled US$41 million principal amount of the 8.5% long-term notes below par. We maintain strong financial flexibility with US$1.1 billion in credit facilities that mature in June 2029 and are less than 25% drawn, positioning us well across various commodity price cycles. Operations Production averaged 148,095 boe/d (84% oil and NGL) in the second quarter, representing a 2% increase in production per basic share compared to Q2/2024. Consistent with our full-year plan, exploration and development expenditures for Q2/2025 totaled $357 million and we brought 74 (66.5 net) wells onstream. Inventory Extension Through Successful Eagle Ford Refracs Eagle Ford production averaged 83,928 boe/d (81% oil and NGL), up 3% from Q1/2025. We brought onstream 14.9 net wells while realizing an approximate 11% improvement in operated drilling and completion costs per completed lateral foot compared to 2024. We also completed two successful refracs that are delivering initial rates comparable to our broader development program with improved capital efficiencies and returns. The two refracs (Moulton A5H and Renee Unit 2H) were brought onstream in April and May with average completed lateral lengths of 1,648 meters (5,406 feet) and generated average 30-day peak production rates of 963 boe/d per well (734 bbl/d of crude oil, 124 bbl/d of NGLs, 631 Mcf/d of natural gas). The refrac program extends inventory duration - we have identified approximately 300 refrac opportunities across our acreage and anticipate an expanded program in 2026. Record Pembina Duvernay Well Results Demonstrate Asset Potential Production from our Canadian light oil business averaged 16,349 boe/d (81% oil and NGL), relatively unchanged from Q1/2025. The Pembina Duvernay represents our largest growth asset and accounts for 40% of Canadian light oil production, with the remaining 60% from Viking operations. The first Pembina Duvernay pad (07-01, 3 wells) from our 2025 program was brought onstream in May with average lateral lengths of 3,800 meters (12,500 feet) and generated average 30-day peak production rates of 1,865 boe/d per well (1,239 bbl/d of crude oil, 422 bbl/d of NGLs, 1,224 Mcf/d of natural gas). The second pad (08-08, 3 wells) came onstream through early July with similar lateral lengths, and over the last 26 days has averaged 1,264 boe/d per well (709 bbl/d of crude oil, 352 bbl/d of NGLs, 1,220 Mcf/d of natural gas. The third pad (10-31, 3 wells) is expected onstream in September. The first two pads have exceeded initial rate expectations with the first pad delivering the highest peak oil rates to-date in the West Shale Basin. These results demonstrate our continued advancement in drilling and completion performance and facility enhancements. Strong production performance, combined with an approximate 12% improvement in drilling and completion costs per completed lateral foot compared to 2024 has significantly improved well economics. We have assembled 140 net sections of highly prospective lands and identified approximately 200 drilling locations. As we transition to full commercialization over the next two years, we plan to implement a one-rig drilling program with 18 to 20 wells per year. At this development pace, we expect production to increase to 20,000-25,000 boe/d by 2029-2030, up from 6,665 boe/d in the second quarter. (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. Organic Heavy Oil Growth Heavy oil production averaged 44,895 boe/d (96% oil and NGL), up 7% from Q1/2025. Strong operating results reflect continued performance at Peavine, Peace River, and across the broader Mannville group in Lloydminster. During the quarter, we brought onstream 43 net wells: 15 Clearwater wells at Peavine, 4 wells at Peace River, and 24 wells at Lloydminster. Our heavy oil operations deliver the strongest economic returns across the portfolio, supported by our extensive acreage position, capital-efficient development, and the continued strength in Western Canadian Select pricing. Quarterly Dividend The Board of Directors has declared a quarterly cash dividend of $0.0225 per share, payable October 1, 2025 to shareholders of record on September 15, 2025. Additional Information Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2025 and the related Management's Discussion and Analysis of the operating and financial results can be accessed on our website at and will be available shortly through SEDAR+ at and EDGAR at Conference Call Tomorrow 9:00 a.m. MT (11:00 a.m. ET) Baytex will host a conference call tomorrow, August 1, 2025, starting at 9:00am MT (11:00am ET). To participate, please dial toll free in North America 1-833-821-2925 or international 1-647-846-2449. Alternatively, to listen to the conference call online, please enter in your web browser. To register, visit our website at 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 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: we are focused on disciplined capital allocation, prioritizing free cash flow, debt reduction and maximizing shareholder returns; for 2025: our guidance for exploration and development expenditures and production and the amount of free cash flow we expect to generate and its expected allocation; our targeted net debt at year-end 2025; the opportunity for refracs on our Eagle Ford acreage and the expected 2026 refrac program; and our Pembina Duvernay development plans. 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 (including as a result of tariffs); 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 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. 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. 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) or acquire Common Shares pursuant to a share buyback (including through the current Normal Course Issuer Bid) will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company'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 Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely. 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, 2024 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 Company's potential financial position, including, but not limited to, our 2025 guidance for development expenditures; our expected 2025 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 Company 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 Company 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 Company'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. 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 total sales, net of blending and other expense, operating netback, free cash flow, and working capital deficiency) 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, 2025 March 31, 2025 June 30, 2024 June 30, 2025 June 30, 2024 Petroleum and natural gas sales $ 886,579 $ 999,130 $ 1,133,123 $ 1,885,709 $ 2,117,315 Blending and other expense (62,381) (72,820) (67,685) (135,201) (131,893) Total sales, net of blending and other expense $ 824,198 $ 926,310 $ 1,065,438 $ 1,750,508 $ $ 1,985,422 Royalties (177,390) (207,937) (240,440) (385,327) (449,611) Operating expense (161,020) (147,703) (167,705) (308,723) (341,140) Transportation expense (32,907) (30,512) (33,314) (63,419) (63,149) Operating netback $ 452,881 $ 540,158 $ 623,979 $ 993,039 $ 1,131,522 Realized financial derivatives (loss) gain (1) (11,874) (194) (2,257) (12,068) 3,231 Operating netback after realized financial derivatives $ 441,007 $ 539,964 $ 621,722 $ 980,971 $ 1,134,753 (1) Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See the Financial Instruments and Risk Management note within the consolidated financial statements for the respective period end for further information. Free cash flow We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties, payments on lease obligations, and transaction costs. Free cash flow is reconciled to cash flows from operating activities in the following table. Three Months Ended Six Months Ended ($ thousands) June 30, 2025 March 31, 2025 June 30, 2024 June 30, 2025 June 30, 2024 Cash flows from operating activities $ 354,312 $ 431,317 $ 505,584 $ 785,629 $ 889,357 Change in non-cash working capital 9,042 29,034 20,140 38,076 52,163 Additions to exploration and evaluation assets (930) - - (930) - Additions to oil and gas properties (355,602) (405,097) (339,573) (760,699) (752,124) Payments on lease obligations (3,634) (2,725) (5,478) (6,359) (10,350) Transaction costs - - - - 1,539 Free cash flow $ 3,188 $ 52,529 $ 180,673 $ 55,717 $ 180,585 Working capital deficiency Working capital deficiency is calculated as cash, trade receivables, and prepaids and other assets net of trade payables, share-based compensation liability, dividends payable, and other long-term liabilities. Working capital deficiency is used by management to measure the Company's liquidity. At June 30, 2025, the Company had $1.2 billion of available credit facility capacity to cover any working capital deficiencies. The following table summarizes the calculation of working capital deficiency. As at ($ thousands) June 30, 2025 March 31, 2025 June 30, 2024 Cash $ $ (7,156) $ (5,966) $ (35,887) Trade receivables (363,507) (391,905) (429,098) Prepaids and other assets (75,856) (72,045) (81,805) Trade payables 538,330 582,053 617,222 Share-based compensation liability 13,851 12,602 22,706 Dividends payable 17,304 17,334 19,845 Other long-term liabilities 19,751 20,849 18,161 Working capital deficiency $ 142,717 $ 162,922 $ 131,144 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. 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, 2025 March 31, 2025 June 30, 2024 Credit facilities $ 317,310 $ 234,683 $ 607,589 Unamortized debt issuance costs - Credit facilities (1) 16,206 15,601 18,387 Long-term notes 1,776,647 1,930,809 1,833,182 Unamortized debt issuance costs - Long-term notes (1) 41,060 46,235 48,712 Trade payables 538,330 582,053 617,222 Share-based compensation liability 13,851 12,602 22,706 Dividends payable 17,304 17,334 19,845 Other long-term liabilities 19,751 20,849 18,161 Cash (7,156 ) ) ) Trade receivables (363,507) (391,905) (429,098) Prepaids and other assets (75,856) (72,045 ) ) Net debt $ 2,293,940 $ 2,390,250 $ 2,639,014 (1) Unamortized debt issuance costs were obtained from the Long-term Notes and Credit Facilities notes within the consolidated financial statements for the respective period end. 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, and transaction costs 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, 2025 March 31, 2025 June 30, 2024 June 30, 2025 June 30, 2024 Cash flow from operating activities $ 354,312 $ 431,317 $ 505,584 $ 785,629 $ 889,357 Change in non-cash working capital 9,042 29,034 20,140 38,076 52,163 Asset retirement obligations settled 3,565 3,519 7,115 7,084 13,626 Transaction costs - - - - 1,539 Adjusted funds flow $ 366,919 $ 463,870 $ 532,839 $ 830,789 $ 956,685 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, 2025 and 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, 2025 Three Months Ended June 30, 2024 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 9,308 14 34 9,845 10,997 9,116 7 41 10,733 10,953 Lloydminster 12,456 20 - 1,148 12,667 13,688 16 - 1,607 13,972 Peavine 19,662 - - - 19,662 19,938 - - - 19,938 Remaining Properties 1,439 2 - 770 1,569 957 1 - 535 1,047 Canada - Light Viking 89 7,603 198 10,761 9,684 - 8,130 181 10,586 10,075 Duvernay - 3,180 2,166 7,915 6,665 - 2,509 1,640 5,875 5,128 Remaining Properties 5 348 588 11,892 2,923 4 413 447 10,263 2,575 United States Eagle Ford - 50,941 16,962 96,151 83,928 - 55,955 17,858 100,165 90,506 Total 42,959 62,108 19,948 138,482 148,095 43,703 67,031 20,167 139,764 154,194 Six Months Ended June 30, 2025 Six Months Ended June 30, 2024 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 9,758 12 26 9,734 11,418 9,299 8 44 10,411 11,086 Lloydminster 11,905 17 - 1,169 12,117 13,422 15 - 1,519 13,690 Peavine 18,693 - - - 18,693 18,768 - - - 18,768 Remaining Properties 1,122 1 - 707 1,241 635 47 - 267 727 Canada - Light Viking 100 8,277 176 10,541 10,310 - 8,655 185 10,827 10,645 Duvernay - 2,794 2,193 7,313 6,206 - 2,156 1,699 5,665 4,799 Remaining Properties 5 368 659 13,569 3,294 7 404 542 13,301 3,169 United States Eagle Ford - 50,752 16,445 94,081 82,877 - 55,249 17,263 102,069 89,523 Total 41,583 62,221 19,499 137,114 146,156 42,131 66,534 19,733 144,059 152,407 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.
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