MEG Energy in 'defence mode' as takeover talk overshadows quarterly earnings in the oilsands
The two firms also share a history with MEG's last hostile suitor, Husky Energy. The former oil producer made a failed run at MEG in 2018 before going on to merge with Cenovus just two years later in a blockbuster deal during a downturn in the oil market at the depths of the pandemic.
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But analysts and investors have also said that Cenovus may have a tough time mounting a rival bid for MEG, with the company in the midst of completing a major spending program to boost production and improve performance at its U.S. refining operations.
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Cenovus is expected to deliver weaker second-quarter results Thursday due in part to lower oil prices and production cuts from wildfires and planned maintenance.
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Cenovus executives had previously downplayed the possibility of joining the fray for MEG, but speculation began to heat up earlier this month when the company hosted an in-person, technical presentation on its upstream operations for analysts and investors.
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The presentation was seen by some as 'trying to warm up the street' to the possibility of a bid, said Eric Nuttall, partner and senior portfolio manager at Ninepoint Partners, which holds stock in both companies.
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'I think they will. I think they should,' Nuttall said of a potential bid from Cenovus. 'An asset like this with such massive synergies does not come around every day. I think they'll be required to submit a bid for for MEG. The question, then, is price.'
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A competitive bid will have to top Strathcona's mixed offer to MEG shareholders of partial ownership in Strathcona, plus a cash payout.
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Strathcona offered $4.10 in cash plus 0.62 of a Strathcona share for each of MEG's shares. When it announced the deal in May, the implied value was $23.27 per share of MEG, representing a roughly nine per cent premium to its pre-bid share price.
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Since then, the implied value has moved up along with Strathcona's share price, reaching $25.77 per share at close Tuesday — representing a premium of roughly 21 per cent.
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Strathcona has argued a takeover would create a top-tier heavy oil producer with better access to capital and a stronger balance sheet.
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But MEG's board reportedly rejected an overture from Strathcona in April, prompting the Waterous Energy Fund-backed company to formally launch its hostile bid a few weeks later.
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Strathcona began hoovering up shares of MEG on the open market in the first quarter of the year, accumulating nearly 10 per cent of the company by early May, prior to launching its formal bid.
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The moves are in keeping with a successful pattern for Strathcona chairman and Waterous Energy Fund chief executive Adam Waterous: target an undervalued or undercapitalized oil producer, build a meaningful stake, then pursue control through acquisition, board changes or strategic consolidation.
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14 hours ago
- National Post
Imperial announces second quarter 2025 financial and operating results
Article content Quarterly net income of $949 million Cash flows from operating activities of $1,465 million and cash flows from operating activities excluding working capital 1 of $1,413 million Upstream production of 427,000 gross oil-equivalent barrels per day, highest second quarter in over 30 years Kearl achieved highest-ever second quarter production of 275,000 total gross oil-equivalent barrels per day (195,000 barrels Imperial's share) Completed construction and commissioning on Canada's largest renewable diesel facility located at the Strathcona refinery Renewed annual normal course issuer bid to repurchase up to five percent of outstanding common shares; plan to accelerate purchases to complete the program prior to year end Article content CALGARY, Alberta — Imperial (TSE: IMO) (NYSE American: IMO): Article content Article content Imperial reported estimated net income in the second quarter of $949 million, compared to net income of $1,288 million in the first quarter of 2025, primarily driven by lower upstream realizations and downstream margin capture. Quarterly cash flows from operating activities were $1,465 million, compared to $1,527 million generated in the first quarter of 2025. Excluding the impact of working capital 1, cash flows from operating activities were $1,413 million, compared to $1,760 million in the first quarter of 2025. Article content 'We safely completed our heaviest planned turnaround quarter in both our Upstream and Downstream businesses, positioning the company for a strong second half of the year,' said John Whelan, chairman, president and chief executive officer. 'A significant accomplishment was the work completed at Kearl which delivers on our plans to double turnaround intervals to an industry-leading four years.' Article content Upstream production averaged 427,000 gross oil-equivalent barrels per day, the highest second quarter production in over 30 years. Kearl recorded its highest-ever second quarter total gross production averaging 275,000 barrels per day (195,000 barrels Imperial's share), including the completion of its planned turnaround. Cold Lake averaged gross production of 145,000 barrels per day in the second quarter and completed the planned turnaround work at the Mahkeses plant. The company's share of Syncrude quarterly production averaged 77,000 gross barrels per day. Article content Downstream throughput in the quarter averaged 376,000 barrels per day, resulting in an overall refinery capacity utilization of 87 percent, including the successful execution of significant planned turnaround work at Nanticoke and Strathcona. Petroleum product sales averaged 480,000 barrels per day. Article content 'I am pleased to announce the start-up of Canada's largest renewable diesel facility which will deliver high quality lower emission fuels to the Canadian transportation sector,' said Whelan. 'This project is expected to deliver attractive returns and complements our integrated business model and industry-leading refinery base.' Article content During the quarter, Imperial returned $367 million to shareholders through dividend payments and has declared a third quarter dividend of 72 cents per share. In June, Imperial renewed its annual normal course issuer bid program (NCIB) allowing the repurchase of up to five percent of its outstanding shares over a 12-month period. Article content 'Imperial remains committed to its long-established history of returning surplus cash to shareholders, and I am pleased to announce our plan to accelerate our NCIB share repurchases with a target of completing the program prior to year end,' said Whelan. Second quarter highlights Article content Net income of $949 million or $1.86 per share on a diluted basis, compared to $1,133 million or $2.11 per share in the second quarter of 2024. Cash flows from operating activities of $1,465 million, compared to cash flows from operating activities of $1,629 million in the second quarter of 2024. Cash flows from operating activities excluding working capital 1 of $1,413 million, compared to $1,508 million in the second quarter of 2024. Capital and exploration expenditures totaled $473 million, up from $462 million in the second quarter of 2024. The company returned $367 million to shareholders in the second quarter of 2025 through dividends paid and declared a quarterly dividend of 72 cents per share. Renewed share repurchase program, enabling the purchase of up to five percent of common shares outstanding, a maximum of 25,452,248 shares, during the 12-month period commencing June 29, 2025. Consistent with the company's commitment to return surplus cash to shareholders, Imperial plans to accelerate its share purchases under the NCIB program and anticipates repurchasing all remaining allowable shares prior to year end. Purchase plans may be modified at any time without prior notice. Upstream production averaged 427,000 gross oil-equivalent barrels per day, the highest second quarter production in over 30 years, up from 404,000 gross oil-equivalent barrels per day in the second quarter of 2024 primarily driven by record Kearl production. Record second quarter total gross bitumen production at Kearl averaged 275,000 barrels per day (195,000 barrels Imperial's share), up from 255,000 barrels per day (181,000 barrels Imperial's share) in the second quarter of 2024, primarily due to mine productivity and improved reliability. Gross bitumen production at Cold Lake averaged 145,000 barrels per day, compared to 147,000 barrels per day in the second quarter of 2024, primarily due to production and steam cycle timing, and turnaround impacts partially offset by Grand Rapids solvent-assisted SAGD. Leming SAGD project remains on track with steam injection started at the end of the second quarter and continuing until late 2025. First oil anticipated in late 2025, with production ramping up over the next year to a peak of around 9,000 barrels per day. The company's share of gross production from Syncrude averaged 77,000 barrels per day, up from 66,000 barrels per day in the second quarter of 2024, primarily driven by the timing of the annual coker turnaround. Completed construction and commissioning on Canada's largest renewable diesel facility located at the Strathcona refinery with first production in July. Imperial has received project support through the Governments of Alberta, British Columbia and Strathcona County. Refinery throughput averaged 376,000 barrels per day, compared to 387,000 barrels per day in the second quarter of 2024. Capacity utilization was 87 percent, compared to 89 percent in the second quarter of 2024. Lower refinery throughput and capacity utilization were primarily due to unplanned downtime partially offset by lower turnaround impacts. Petroleum product sales were 480,000 barrels per day, up from 470,000 barrels per day in the second quarter of 2024, enabled by the Trans Mountain pipeline expansion. Chemical net income of $21 million in the quarter, compared to $65 million in the second quarter of 2024, primarily driven by lower polyethylene margins. Announced single largest corporate gift to any post-secondary institution in Alberta, with the donation of the $37 million research lab facility to the Southern Alberta Institute of Technology (SAIT). Article content During the second quarter of 2025, the price of crude oil decreased relative to first quarter of 2025, while the Canadian WTI/WCS spread narrowed due to low inventory levels. Industry refining margins improved in the second quarter of 2025, driven by strong seasonal demand. Article content During 2025, the United States announced a variety of trade-related actions, including the imposition of tariffs on imports from Canada and several other countries. In response, Canada announced its own retaliatory tariffs. Certain tariffs were paused for a period of time but have not been withdrawn, while others have been revised. The global trade environment continues to be volatile. The likelihood of the United States, Canada or their trading partners resuming tariffs, imposing new or revised reciprocal tariffs, export restrictions, or other forms of trade-related sanctions is highly uncertain. Additionally, significant uncertainty exists as to what effects these actions will ultimately have on Imperial, its suppliers and its customers. The company continually monitors the global trade environment and works to mitigate potential impacts. Article content Operating results Article content Second quarter Article content 2025 vs. second quarter 2024 Article content Second Quarter millions of Canadian dollars, unless noted 2025 2024 Net income (loss) (U.S. GAAP) 949 1,133 Net income (loss) per common share, assuming dilution (dollars) 1.86 2.11 Article content Upstream Net income (loss) factor analysis millions of Canadian dollars 2024 Price Volume Royalty Other 2025 799 (530) 130 170 95 664 Article content Price – Average bitumen realizations decreased by $17.20 per barrel, primarily driven by lower marker prices. Synthetic crude oil realizations decreased by $23.71 per barrel, primarily driven by lower WTI and a weaker Synthetic/WTI spread. Article content Volumes – Higher volumes were primarily driven by the timing of the annual coker turnaround at Syncrude and mine productivity and improved reliability at Kearl. Article content Royalty – Lower royalties were primarily driven by lower commodity prices. Article content Marker prices and average realizations Second Quarter Canadian dollars, unless noted 2025 2024 West Texas Intermediate (US$ per barrel) 63.69 80.63 Western Canada Select (US$ per barrel) 53.66 67.03 WTI/WCS Spread (US$ per barrel) 10.03 13.60 Bitumen (per barrel) 65.82 83.02 Synthetic crude oil (per barrel) 87.85 111.56 Average foreign exchange rate (US$) 0.72 0.73 Article content Production Second Quarter thousands of barrels per day 2025 2024 Kearl (Imperial's share) 195 181 Cold Lake 145 147 Syncrude (a) 77 66 Kearl total gross production (thousands of barrels per day) 275 255 Article content (a) In the second quarter of 2025, Syncrude gross production included about 4 thousand barrels per day of bitumen and other products (2024 – 2 thousand barrels per day) that were exported to the operator's facilities using an existing interconnect pipeline. Article content Higher production at Kearl was primarily driven by mine productivity and improved reliability. Article content Lower production at Cold Lake was primarily driven by production and steam cycle timing, and turnaround impacts partially offset by Grand Rapids solvent-assisted SAGD. Article content Higher production at Syncrude was primarily driven by the timing of the annual coker turnaround. Article content Downstream Net income (loss) factor analysis millions of Canadian dollars 2024 Margins Other 2025 294 70 (42) 322 Article content Margins – Higher margins primarily reflect improved market conditions. Article content Lower refinery throughput was primarily due to unplanned downtime partially offset by lower turnaround impacts. Article content Higher petroleum product sales were enabled by the Trans Mountain pipeline expansion. Article content Chemicals Net income (loss) factor analysis millions of Canadian dollars 2024 Margins Other 2025 65 (30) (14) 21 Article content Corporate and other Second Quarter millions of Canadian dollars 2025 2024 Net income (loss) (U.S. GAAP) (58 ) (25 ) Article content Liquidity and capital resources Second Quarter millions of Canadian dollars 2025 2024 Cash flows from (used in): Operating activities 1,465 1,629 Investing activities (472 ) (456 ) Financing activities (371 ) (329 ) Increase (decrease) in cash and cash equivalents 622 844 Cash and cash equivalents at period end 2,386 2,020 Article content Cash flows from operating activities primarily reflect lower earnings and lower favourable working capital impacts. Article content Cash flows used in investing activities primarily reflect higher additions to property, plant and equipment. Article content Cash flows used in financing activities primarily reflect: Article content (a) The company did not purchase any shares during the second quarter of 2025 and 2024. Article content On June 23, 2025, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid and will continue its existing share purchase program. Shareholders may obtain a copy of the Notice of Intention to Make a Normal Course Issuer Bid approved by the TSX without charge by contacting the company. The program enables the company to purchase up to a maximum of 25,452,248 common shares during the period June 29, 2025 to June 28, 2026. This maximum includes shares purchased under the normal course issuer bid from Exxon Mobil Corporation. As in the past, Exxon Mobil Corporation has advised the company that it intends to participate to maintain its ownership percentage at approximately 69.6 percent. The program will end should the company purchase the maximum allowable number of shares or otherwise on June 28, 2026. Imperial plans to accelerate its share purchases under the normal course issuer bid program, and anticipates repurchasing all remaining allowable shares prior to year end. Purchase plans may be modified at any time without prior notice. Article content Six months 2025 vs. six months 2024 Six Months millions of Canadian dollars, unless noted 2025 2024 Net income (loss) (U.S. GAAP) 2,237 2,328 Net income (loss) per common share, assuming dilution (dollars) 4.38 4.34 Article content Upstream Net income (loss) factor analysis millions of Canadian dollars 2024 Price Volume Royalty Other 2025 1,357 (460) 110 160 228 1,395 Article content Price – Average bitumen realizations decreased by $4.20 per barrel, primarily driven by lower marker prices partially offset by narrowing WTI/WCS spread and lower diluent costs. Synthetic crude oil realizations decreased by $8.96 per barrel, primarily driven by lower WTI partially offset by an improved Synthetic/WTI spread. Article content Volume – Higher volumes were primarily driven by Grand Rapids solvent-assisted SAGD and the timing of the annual coker turnaround at Syncrude. Article content Royalty – Lower royalties were primarily driven by lower commodity prices. Article content Other – Primarily due to favourable foreign exchange impacts of about $170 million. Article content Marker prices and average realizations Six Months Canadian dollars, unless noted 2025 2024 West Texas Intermediate (US$ per barrel) 67.52 78.77 Western Canada Select (US$ per barrel) 56.25 62.34 WTI/WCS Spread (US$ per barrel) 11.27 16.43 Bitumen (per barrel) 70.50 74.70 Synthetic crude oil (per barrel) 93.14 102.10 Average foreign exchange rate (US$) 0.71 0.74 Article content Production Six Months thousands of barrels per day 2025 2024 Kearl (Imperial's share) 189 189 Cold Lake 150 144 Syncrude (a) 75 70 Kearl total gross production (thousands of barrels per day) 266 266 Article content (a) In 2025, Syncrude gross production included about 3 thousand barrels per day of bitumen and other products (2024 – 1 thousand barrels per day) that were exported to the operator's facilities using an existing interconnect pipeline. Article content Higher production at Cold Lake was primarily driven by Grand Rapids solvent-assisted SAGD, partially offset by production and steam cycle timing. Article content Margins – Higher margins primarily reflect improved market conditions. Article content Other – Primarily due to unfavourable wholesale volume impacts of about $70 million. Article content Lower refinery throughput was primarily due to unplanned downtime partially offset by lower turnaround impacts. Article content Chemicals Net income (loss) factor analysis millions of Canadian dollars 2024 Margins Other 2025 122 (50) (20) 52 Article content Margins – Lower margins primarily reflect weaker industry polyethylene margins. Article content Corporate and other Six Months millions of Canadian dollars 2025 2024 Net income (loss) (U.S. GAAP) (116 ) (76 ) Article content Liquidity and capital resources Six Months millions of Canadian dollars 2025 2024 Cash flows from (used in): Operating activities 2,992 2,705 Investing activities (849 ) (937 ) Financing activities (736 ) (612 ) Increase (decrease) in cash and cash equivalents 1,407 1,156 Article content Cash flows from operating activities primarily reflect lower unfavourable deferred tax and working capital impacts. Article content Cash flows used in investing activities primarily reflect lower additions to property, plant and equipment. Article content Cash flows used in financing activities primarily reflect: Article content Six Months millions of Canadian dollars, unless noted 2025 2024 Dividends paid 674 599 Per share dividend paid (dollars) 1.32 1.10 Share repurchases (a) — — Number of shares purchased (millions) (a) — — Article content (a) The company did not purchase any shares during the six months ended June 30, 2025 and 2024. Article content Key financial and operating data follow. Article content Forward-looking statements Article content Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans, are forward-looking statements. Similarly, discussion of roadmaps or future plans related to carbon capture, transportation and storage, biofuel, hydrogen, and other future plans to reduce emissions and emission intensity of the company, its affiliates and third parties are dependent on future market factors, such as continued technological progress, policy support and timely rule-making and permitting, and represent forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, estimate, expect, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to purchases under the normal course issuer bid and plans to accelerate purchases to complete the program prior to year end; the company's commitment of returning surplus cash to shareholders; plans to increase turnaround intervals at Kearl to four years; company performance in the second half of the year; expected returns and impacts of the company's Strathcona renewable diesel project; and the company's Leming SAGD redevelopment project, including timing and anticipated production. Article content Forward-looking statements are based on the company's current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning future energy demand, supply and mix; production rates, growth and mix across various assets; project plans, timing, costs, technical evaluations and capacities and the company's ability to effectively execute on these plans and operate its assets, including the Strathcona renewable diesel project and the Leming SAGD redevelopment project; the adoption and impact of new facilities or technologies on reductions to greenhouse gas emissions intensity, including but not limited to technologies using solvents to replace energy intensive steam at Cold Lake, Strathcona renewable diesel, carbon capture and storage including in connection with hydrogen for the renewable diesel project, recovery technologies and efficiency projects, and any changes in the scope, terms, or costs of such projects; for shareholder returns, assumptions such as cash flow forecasts, financing sources and capital structure, participation of the company's majority shareholder in the normal course issuer bid, and the results of periodic and ongoing evaluation of alternate uses of capital; for renewable diesel, the availability and cost of locally-sourced and grown feedstock and the supply of renewable diesel to British Columbia in connection with its low-carbon fuel legislation; the amount and timing of emissions reductions, including the impact of lower carbon fuels; the degree and timeliness of support that will be provided by policymakers and other stakeholders for various new technologies such as carbon capture and storage will be provided; receipt of regulatory approvals in a timely manner, especially with respect to large scale emissions reduction projects; performance of third-party service providers including service providers located outside of Canada; refinery utilization and product sales; applicable laws and government policies, including with respect to climate change, greenhouse gas emissions reductions and low carbon fuels; the ability to offset any ongoing or renewed inflationary pressures; capital and environmental expenditures; cash generation, financing sources and capital structure, such as dividends and shareholder returns, including the timing and amounts of share repurchases; and commodity prices, foreign exchange rates and general market conditions, could differ materially depending on a number of factors. Article content These factors include global, regional or local changes in supply and demand for oil, natural gas, and petroleum and petrochemical products and resulting price, differential and margin impacts, including Canadian and foreign government action with respect to supply levels, prices, trade tariffs, trade controls, the occurrence of disruptions in trade or military alliances, and wars; political or regulatory events, including changes in law or government policy, applicable royalty rates, and tax laws; third-party opposition to company and service provider operations, projects and infrastructure; competition from alternative energy sources and competitors who may be more experienced or established in these markets; availability and allocation of capital; the receipt, in a timely manner, of regulatory and third-party approvals, including for new technologies relating to the company's lower emissions business activities; failure, delay, reduction, revocation or uncertainty regarding supportive policy and market development for the adoption of emerging lower emission energy technologies and other technologies that support emissions reductions; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; unanticipated technical or operational difficulties; project management and schedules and timely completion of projects; the results of research programs and new technologies, including with respect to greenhouse gas emissions, and the ability to bring new technologies to scale on a commercially competitive basis, and the competitiveness of alternative energy and other emission reduction technologies; availability and performance of third-party service providers including those located outside of Canada; environmental risks inherent in oil and gas exploration and production activities; management effectiveness and disaster response preparedness; operational hazards and risks; cybersecurity incidents including incidents caused by actors employing emerging technologies such as artificial intelligence; currency exchange rates; general economic conditions, including inflation and the occurrence and duration of economic recessions or downturns; and other factors discussed in Item 1A risk factors and Item 7 management's discussion and analysis of financial condition and results of operations of Imperial's most recent annual report on Form 10-K. Article content Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial. Imperial's actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law. Article content Forward-looking and other statements regarding Imperial's environmental, social and other sustainability efforts and aspirations are not an indication that these statements are material to investors or require disclosure in the company's filings with securities regulators. In addition, historical, current and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making. Individual projects or opportunities may advance based on a number of factors, including availability of stable and supportive policy, technology for cost-effective abatement, company planning process, and alignment with partners and other stakeholders. Article content In this release all dollar amounts are expressed in Canadian dollars unless otherwise stated. This release should be read in conjunction with Imperial's most recent Form 10-K. Note that numbers may not add due to rounding. Article content The term 'project' as used in this release can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. Article content Second Quarter Six Months millions of Canadian dollars, unless noted 2025 2024 2025 2024 Net income (loss) (U.S. GAAP) Total revenues and other income 11,232 13,383 23,749 25,666 Total expenses 9,988 11,894 20,817 22,605 Income (loss) before income taxes 1,244 1,489 2,932 3,061 Income taxes 295 356 695 733 Net income (loss) 949 1,133 2,237 2,328 Net income (loss) per common share (dollars) 1.86 2.11 4.39 4.34 Net income (loss) per common share – assuming dilution (dollars) 1.86 2.11 4.38 4.34 Other financial data Gain (loss) on asset sales, after tax 1 1 10 3 Total assets at June 30 44,178 44,135 Total debt at June 30 4,002 4,119 Shareholders' equity at June 30 24,999 23,936 Dividends declared on common stock Total 366 322 733 643 Per common share (dollars) 0.72 0.60 1.44 1.20 Millions of common shares outstanding At June 30 509.0 535.8 Average – assuming dilution 510.3 537.0 510.2 537.0 Article content Attachment II Article content Second Quarter Six Months millions of Canadian dollars 2025 2024 2025 2024 Total cash and cash equivalents at period end 2,386 2,020 2,386 2,020 Operating activities Net income (loss) 949 1,133 2,237 2,328 Adjustments for non-cash items: Depreciation and depletion 478 456 1,009 946 (Gain) loss on asset sales (1 ) (1 ) (11 ) (3 ) Deferred income taxes and other — (75 ) (31 ) (239 ) Changes in operating assets and liabilities 52 121 (181 ) (324 ) All other items – net (13 ) (5 ) (31 ) (3 ) Cash flows from (used in) operating activities 1,465 1,629 2,992 2,705 Investing activities Additions to property, plant and equipment (471 ) (461 ) (869 ) (958 ) Proceeds from asset sales 2 3 13 7 Additional investments (4 ) — (4 ) — Loans to equity companies – net 1 2 11 14 Cash flows from (used in) investing activities (472 ) (456 ) (849 ) (937 ) Cash flows from (used in) financing activities (371 ) (329 ) (736 ) (612 ) Article content Attachment III Article content Second Quarter Six Months millions of Canadian dollars 2025 2024 2025 2024 Net income (loss) (U.S. GAAP) Upstream 664 799 1,395 1,357 Downstream 322 294 906 925 Chemical 21 65 52 122 Corporate and other (58 ) (25 ) (116 ) (76 ) Net income (loss) 949 1,133 2,237 2,328 Revenues and other income Upstream 3,784 4,552 8,242 8,720 Downstream 12,427 14,634 26,446 28,273 Chemical 356 418 728 837 Eliminations / Corporate and other (5,335 ) (6,221 ) (11,667 ) (12,164 ) Revenues and other income 11,232 13,383 23,749 25,666 Purchases of crude oil and products Upstream 1,369 1,900 3,231 3,713 Downstream 10,952 12,944 22,939 24,535 Chemical 240 256 493 516 Eliminations / Corporate and other (5,346 ) (6,244 ) (11,692 ) (12,202 ) Purchases of crude oil and products 7,215 8,856 14,971 16,562 Production and manufacturing Upstream 1,127 1,203 2,303 2,391 Downstream 466 435 923 856 Chemical 62 48 113 101 Eliminations / Corporate and other 9 3 11 5 Production and manufacturing 1,664 1,689 3,350 3,353 Selling and general Upstream — — — — Downstream 175 171 349 333 Chemical 20 23 42 49 Eliminations / Corporate and other 56 27 119 85 Selling and general 251 221 510 467 Capital and exploration expenditures Upstream 353 267 619 557 Downstream 90 149 178 302 Chemical 1 3 4 8 Corporate and other 29 43 70 91 Capital and exploration expenditures 473 462 871 958 Exploration expenses charged to Upstream income included above — 1 2 2 Article content Attachment IV Article content Operating statistics Second Quarter Six Months 2025 2024 2025 2024 Gross crude oil production (thousands of barrels per day) Kearl 195 181 189 189 Cold Lake 145 147 150 144 Syncrude (a) 77 66 75 70 Conventional 5 5 4 5 Total crude oil production 422 399 418 408 Gross natural gas production (millions of cubic feet per day) 28 30 29 30 Gross oil-equivalent production (b) 427 404 423 413 (thousands of oil-equivalent barrels per day) Net crude oil production (thousands of barrels per day) Kearl 185 167 177 175 Cold Lake 120 109 121 109 Syncrude (a) 68 54 65 57 Conventional 4 5 4 5 Total crude oil production 377 335 367 346 Net natural gas production (millions of cubic feet per day) 27 29 29 30 Net oil-equivalent production (b) 382 340 372 351 (thousands of oil-equivalent barrels per day) Kearl blend sales (thousands of barrels per day) 271 249 265 263 Cold Lake blend sales (thousands of barrels per day) 193 196 200 193 Average realizations (Canadian dollars) Bitumen (per barrel) 65.82 83.02 70.50 74.70 Synthetic crude oil (per barrel) 87.85 111.56 93.14 102.10 Conventional crude oil (per barrel) 39.31 64.55 44.17 58.59 Refinery throughput (thousands of barrels per day) 376 387 387 397 Refinery capacity utilization (percent) 87 89 89 92 Petroleum product sales (thousands of barrels per day) Gasolines 225 227 220 221 Heating, diesel and jet fuels 186 174 180 172 Lube oils and other products (c) 46 44 49 43 Heavy fuel oils 23 25 19 24 Net petroleum products sales 480 470 468 460 Petrochemical sales (thousands of tonnes) (c) 186 219 351 434 Article content (a) Syncrude gross and net production included bitumen and other products that were exported to the operator's facilities using an existing interconnect pipeline. Gross bitumen and other products production (thousands of barrels per day) 4 2 3 1 Net bitumen and other products production (thousands of barrels per day) 4 2 3 1 (b) Gas converted to oil-equivalent at six million cubic feet per one thousand barrels. (c) In 2025, benzene and aromatic solvent sales are reported under Petroleum product sales – Lube oils and other products, whereas in 2024, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative period has not been recast. Article content (a) Computed using the average number of shares outstanding during each period. The sum of the quarters presented may not add to the year total. Article content Attachment VI Article content Non-GAAP financial measures and other specified financial measures Article content Certain measures included in this document are not prescribed by U.S. Generally Accepted Accounting Principles (GAAP). These measures constitute 'non-GAAP financial measures' under Securities and Exchange Commission Regulation G and Item 10(e) of Regulation S-K, and 'specified financial measures' under National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure of the Canadian Securities Administrators. Article content Reconciliation of these non-GAAP financial measures to the most comparable GAAP measure, and other information required by these regulations, have been provided. Non-GAAP financial measures and specified financial measures are not standardized financial measures under GAAP and do not have a standardized definition. As such, these measures may not be directly comparable to measures presented by other companies, and should not be considered a substitute for GAAP financial measures. Article content Cash flows from (used in) operating activities excluding working capital Article content Cash flows from (used in) operating activities excluding working capital is a non-GAAP financial measure that is the total cash flows from operating activities less the changes in operating assets and liabilities in the period. The most directly comparable financial measure that is disclosed in the financial statements is 'Cash flows from (used in) operating activities' within the company's Consolidated statement of cash flows. Management believes it is useful for investors to consider these numbers in comparing the underlying performance of the company's business across periods when there are significant period-to-period differences in the amount of changes in working capital. Changes in working capital is equal to 'Changes in operating assets and liabilities' as disclosed in the company's Consolidated statement of cash flows and in Attachment II of this document. This measure assesses the cash flows at an operating level, and as such, does not include proceeds from asset sales as defined in Cash flows from operating activities and asset sales in the Frequently Used Terms section of the company's annual Form 10-K. Article content Free cash flow Article content Free cash flow is a non-GAAP financial measure that is cash flows from operating activities less additions to property, plant and equipment and equity company investments plus proceeds from asset sales. The most directly comparable financial measure that is disclosed in the financial statements is 'Cash flows from (used in) operating activities' within the company's Consolidated statement of cash flows. This measure is used to evaluate cash available for financing activities (including but not limited to dividends and share purchases) after investment in the business. Article content Net income (loss) excluding identified items Article content Net income (loss) excluding identified items is a non-GAAP financial measure that is total net income (loss) excluding individually significant non-operational events with an absolute corporate total earnings impact of at least $100 million in a given quarter. The net income (loss) impact of an identified item for an individual segment may be less than $100 million when the item impacts several segments or several periods. The most directly comparable financial measure that is disclosed in the financial statements is 'Net income (loss)' within the company's Consolidated statement of income. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The company believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Net income (loss) excluding identified items is not meant to be viewed in isolation or as a substitute for net income (loss) as prepared in accordance with U.S. GAAP. All identified items are presented on an after-tax basis. Article content Reconciliation of net income (loss) excluding identified items Article content There were no identified items in the second quarter or year-to-date 2025 and 2024 periods. Article content Cash operating costs (cash costs) Article content Cash operating costs is a non-GAAP financial measure that consists of total expenses, less purchases of crude oil and products, federal excise taxes and fuel charge, financing, and costs that are non-cash in nature, including depreciation and depletion, and non-service pension and postretirement benefit. The components of cash operating costs include 'Production and manufacturing', 'Selling and general' and 'Exploration' from the company's Consolidated statement of income, and as disclosed in Attachment III of this document. The sum of these income statement lines serves as an indication of cash operating costs and does not reflect the total cash expenditures of the company. The most directly comparable financial measure that is disclosed in the financial statements is 'Total expenses' within the company's Consolidated statement of income. This measure is useful for investors to understand the company's efforts to optimize cash through disciplined expense management. Article content Reconciliation of cash operating costs Second Quarter Six Months millions of Canadian dollars 2025 2024 2025 2024 From Imperial's Consolidated statement of income Total expenses 9,988 11,894 20,817 22,605 Less: Purchases of crude oil and products 7,215 8,856 14,971 16,562 Federal excise taxes and fuel charge 372 656 964 1,247 Depreciation and depletion 478 456 1,009 946 Non-service pension and postretirement benefit 6 1 11 2 Financing 2 14 — 26 Cash operating costs 1,915 1,911 3,862 3,822 Article content Components of cash operating costs Second Quarter Six Months millions of Canadian dollars 2025 2024 2025 2024 From Imperial's Consolidated statement of income Production and manufacturing 1,664 1,689 3,350 3,353 Selling and general 251 221 510 467 Exploration — 1 2 2 Cash operating costs 1,915 1,911 3,862 3,822 Article content Segment contributions to total cash operating costs Second Quarter Six Months millions of Canadian dollars 2025 2024 2025 2024 Upstream 1,127 1,204 2,305 2,393 Downstream 641 606 1,272 1,189 Chemicals 82 71 155 150 Eliminations / Corporate and other 65 30 130 90 Cash operating costs 1,915 1,911 3,862 3,822 Article content Unit cash operating costs (unit cash costs) Article content Unit cash operating costs is a non-GAAP ratio. Unit cash operating costs (unit cash costs) is calculated by dividing cash operating costs by total gross oil-equivalent production, and is calculated for the Upstream segment, as well as the major Upstream assets. Cash operating costs is a non-GAAP financial measure and is disclosed and reconciled above. This measure is useful for investors to understand the expense management efforts of the company's major assets as a component of the overall Upstream segment. Unit cash operating cost, as used by management, does not directly align with the definition of 'Average unit production costs' as set out by the U.S. Securities and Exchange Commission (SEC), and disclosed in the company's SEC Form 10-K. Article content Components of unit cash operating costs Second Quarter 2025 2024 millions of Canadian dollars Upstream (a) Kearl Cold Lake Syncrude Upstream (a) Kearl Cold Lake Syncrude Production and manufacturing 1,127 465 272 329 1,203 499 262 400 Selling and general — — — — — — — — Exploration — — — — 1 — — — Cash operating costs 1,127 465 272 329 1,204 499 262 400 Gross oil-equivalent production 427 195 145 77 404 181 147 66 (thousands of barrels per day) Unit cash operating cost ($/oeb) 29.00 26.20 20.61 46.95 32.75 30.30 19.59 66.60 USD converted at the quarterly average forex 2025 US$0.72; 2024 US$0.73 20.88 18.86 14.84 33.80 23.91 22.12 14.30 48.62 Article content Components of unit cash operating costs Six Months 2025 2024 millions of Canadian dollars Upstream (a) Kearl Cold Lake Syncrude Upstream (a) Kearl Cold Lake Syncrude Production and manufacturing 2,303 949 557 682 2,391 997 571 742 Selling and general — — — — — — — — Exploration 2 — — — 2 — — — Cash operating costs 2,305 949 557 682 2,393 997 571 742 Gross oil-equivalent production 423 189 150 75 413 189 144 70 (thousands of barrels per day) Unit cash operating cost ($/oeb) 30.11 27.74 20.52 50.24 31.84 28.98 21.79 58.24 USD converted at the YTD average forex 2025 US$0.71; 2024 US$0.74 21.38 19.70 14.57 35.67 23.56 21.45 16.12 43.10 Article content (a) Upstream includes Imperial's share of Kearl, Cold Lake, Syncrude and other. Article content After more than a century, Imperial continues to be an industry leader in applying technology and innovation to responsibly develop Canada's energy resources. As Canada's largest petroleum refiner, a major producer of crude oil, a key petrochemical producer and a leading fuels marketer from coast to coast, our company remains committed to high standards across all areas of our business. Article content Article content Article content Article content Article content Contacts Article content Article content Article content
Global News
a day ago
- Global News
Cenovus Energy reports reduced oil production due to spring wildfires
Cenovus Energy has reported a lower second-quarter profit and it blames lower production, in part, on spring wildfires in western Canada. The Calgary-based oil and gas producer released details of its quarterly update on Thursday. In early June, Cenovus was forced to evacuate most company employees from its Christina Lake oilsands operations, south of Fort McMurray, Alta. because of the nearby Caribou Lake wildfire. View image in full screen A steam-assisted gravity drainage pad at the Cenovus Christina Lake oilsands facility, southeast of Fort McMurray, Alta., is shown on April 24, 2024. THE CANADIAN PRESS/Amber Bracken At the time, the company estimated the reduced oil production at about 238,000 barrels of oil a day per day. Story continues below advertisement In Thursday's update, it estimated the total production loss from the wildfire at two-million barrels. Get breaking National news For news impacting Canada and around the world, sign up for breaking news alerts delivered directly to you when they happen. Sign up for breaking National newsletter Sign Up By providing your email address, you have read and agree to Global News' Terms and Conditions and Privacy Policy The company said a well leak and shut down of its Rush Lake facilities in western Saskatchewan, and maintenance at other oil production facilities, also weighed on production in the second quarter. Cenovus said total upstream production was 765, 900 barrels of oil per day, compared to 800,00 barrels per day in the second quarter last year. Net income fell to $851 million, or 45 cents Canadian per share in the three months that ended on June 30, 2025. That's down from $1 billion or 53 cents per share during the same period of 2024. — With files from Reuters and The Canadian Press.
Cision Canada
a day ago
- Cision Canada
MEG Energy Reports Second Quarter 2025 Results Including Successful Completion of Major Turnaround and Wildfire Response; Announces 10% Increase to Quarterly Dividend to $0.11 per share
CALGARY, AB, July 31, 2025 /CNW/ - MEG Energy Corp. (TSX: MEG) ("MEG" or the "Corporation") reported its second quarter 2025 operational and financial results. 1 View PDF "We safely and successfully completed the largest planned turnaround in MEG's history in the second quarter, while prioritizing the safety of our workforce and communities during challenging wildfire conditions," said Darlene Gates, President and Chief Executive Officer of MEG. "We made meaningful progress advancing the Facility Expansion Project, including achieving key milestones during the turnaround, which will further unlock significant value from our world-class Christina Lake resource. The 10% dividend increase reflects our continued confidence in the strength of our strategy, and our commitment to delivering sustainable shareholder returns." Key highlights: Excellent Safety Performance: Zero serious incidents, recordable injuries, or reportable spills during turnaround as site population doubled; total recordable incident rate reduced to 0.25 year-to-date and zero serious process safety events. Safe Wildfire Response: Safely evacuated over 850 workers while maintaining stable off-power grid operations following the May 29 Caribou Lake wildfire and third-party infrastructure damage; successful re-mobilization through June including power restored. Dividend Increase: On July 31, 2025, the Board of Directors approved a 10% increase in the quarterly cash dividend to $0.11 per share payable on October 15, 2025, to shareholders of record on September 12, 2025. Phase 2B Turnaround Completed on Time and Budget: Delivered MEG's largest planned turnaround on time and budget; positioned for extended four year turnaround cycles. Facility Expansion Project ("FEP") on track: Expansion remains on track for completion in 2027, with over 150 key FEP tie-ins completed during turnaround to minimize future production interruptions; 5th once-through steam generator delivered and all major equipment purchased. Financial Performance: Generated adjusted funds flow ("AFF") of $125 million ($0.49 per share). Production of 63,502 bbls/d at a 2.38 steam-oil ratio: Reflects planned turnaround and wildfire delays; achieved pre-turnaround rates within two weeks of restart despite a twelve day delay. July production averaged approximately 109,000 barrels per day and the newest pad of 16 well pairs is on steam ahead of schedule with first oil expected in the third quarter of 2025. Capital Expenditures on Plan: Delivered $200 million of planned capital expenditures, including investments in the turnaround, FEP, and advancing pad development to areas of improved resource quality. Shareholder Returns: Returned $35 million to shareholders by: repurchasing and cancelling 0.4 million shares for $9 million; and paying a quarterly cash dividend of $26 million ($0.10 per share) on April 15, 2025. Guidance: The Corporation's 2025 operating and capital guidance remains unchanged. _____________________________ 1 All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen unless otherwise noted. The Corporation's Non-GAAP and Other Financial Measures are detailed in the Advisory section of this news release. They include: cash operating netback, bitumen realization net of transportation and storage expense, operating expenses net of power revenue, energy operating costs net of power revenue, non-energy operating costs, energy operating costs, adjusted funds flow and free cash flow. The following table summarizes selected operational and financial information of the Corporation for the periods noted. All dollar amounts are stated in Canadian dollars ($ or C$) unless otherwise noted and all per barrel financial results are based on bitumen sales volumes: Six months ended June 30 2025 2024 ($millions, except as indicated) 2025 2024 Q2 Q1 Q4 Q3 Q2 Q1 Operational results: Bitumen production - bbls/d 83,253 102,309 63,502 103,224 100,139 103,298 100,531 104,088 Per share, diluted 0.06 0.07 0.02 0.04 0.03 0.04 0.03 0.03 Steam-oil ratio 2.31 2.40 2.38 2.28 2.40 2.36 2.44 2.37 Bitumen sales - bbls/d 86,356 99,337 70,760 102,126 100,821 105,255 93,140 105,534 Business environment: WTI - US$/bbl 67.58 78.77 63.74 71.42 70.27 75.09 80.57 76.96 Differential - WTI:WCS - Edmonton - US$/bbl (11.47) (16.46) (10.27) (12.67) (12.56) (13.55) (13.61) (19.31) AWB - Edmonton - US$/bbl 55.24 60.98 52.70 57.77 56.82 60.62 65.99 55.96 C$ equivalent of 1 US$ – average 1.4093 1.3586 1.3840 1.4350 1.3991 1.3636 1.3684 1.3488 Financial results: Bitumen realization after net transportation and storage expense (1) - $/bbl 58.04 66.55 46.72 65.98 62.62 65.61 73.84 60.10 Non-energy operating costs (2) - $/bbl 6.80 5.39 8.16 5.84 5.61 5.18 5.63 5.18 Energy operating costs net of power revenue (1) - $/bbl 2.33 1.10 2.72 2.06 0.90 0.64 0.99 1.19 Operating expenses net of power revenue (1) - $/bbl 9.13 6.49 10.88 7.90 6.51 5.82 6.62 6.37 Cash operating netback (1) - $/bbl 37.64 43.34 25.29 46.30 41.09 41.35 47.14 39.99 Royalties 176 290 68 108 132 169 162 128 Adjusted funds flow (3) 505 683 125 380 340 362 354 329 Per share, diluted 1.97 2.49 0.49 1.47 1.29 1.34 1.30 1.19 Capital expenditures 357 235 200 157 172 141 123 112 Free cash flow (3) 148 448 (75) 223 168 221 231 217 Per share, diluted 0.57 1.64 (0.30) 0.86 0.64 0.82 0.85 0.78 Weighted average common shares outstanding - diluted 257 274 255 258 263 269 272 276 Debt repayments - US$ — 158 — — — 100 53 105 Share repurchases - C$ 168 195 9 159 151 108 68 127 Dividends paid - C$ 52 — 26 26 27 — — — Revenues 1,919 2,737 757 1,162 1,147 1,265 1,373 1,364 Net earnings 278 234 67 211 106 167 136 98 Per share, diluted 1.08 0.86 0.26 0.82 0.40 0.62 0.50 0.36 Financial Results Adjusted funds flow ("AFF") in the three and six months ended June 30, 2025 was $125 million and $505 million, respectively, compared to $354 million and $683 million in the same periods of 2024. This was primarily driven by lower average WTI benchmark prices and reduced blend sales volumes partially offset by narrower WTI:AWB differentials and lower royalties. On a diluted per-share basis, AFF was $0.49 and $1.97 for the three and six months ended June 30, 2025, respectively, compared to $1.30 and $2.49 in the same periods of 2024. This primarily reflects the combined impacts of decreased AFF partially offset by share repurchases. The Corporation returned $35 million to shareholders during the second quarter of 2025 through the repurchase and cancellation of 0.4 million shares for $9 million and a dividend payment of $26 million. Second quarter net earnings were $67 million in 2025, compared to $136 million in 2024, driven by reduced AFF partially offset by lower depletion and depreciation and deferred income tax expense and an unrealized foreign exchange gain. Year-to-date net earnings were $278 million and $234 million in 2025 and 2024, respectively, whereby lower AFF was more than offset by lower depletion and depreciation and deferred income tax expense and an unrealized foreign exchange gain. Operational Results Bitumen production averaged 63,502 barrels per day, at a 2.38 steam-oil ratio ("SOR"), during the second quarter of 2025 and 83,253 barrels per day, at a 2.31 SOR, during the first half of 2025. This compares to 100,531 barrels per day, at a 2.44 SOR, and 102,309 barrels per day, at a 2.40 SOR, in the same periods of 2024. Production in the first half of 2025 was primarily impacted by planned turnaround activities. In addition, wildfire damage to third-party power line infrastructure delayed the scheduled post-turnaround production ramp-up. The lower SOR reflects improved reservoir quality and optimized design of recent wells partially offset by the impact of the planned turnaround. Non-energy operating costs were $53 million and $106 million, respectively, in the three and six months ended June 30, 2025 compared to $48 million and $98 million in the same periods of 2024, primarily reflecting higher planned maintenance and unexpected wildfire costs. Lower 2025 bitumen sales volumes also contributed to a per barrel increase. Capital expenditures were $200 million and $357 million in the three and six months ended June 30, 2025, respectively, compared to $123 million and $235 million in the same periods of 2024, primarily reflecting planned turnaround activities and FEP investments. Capital Allocation Strategy The Corporation is committed to returning 100% of free cash flow to shareholders through a combination of share repurchases and payment of quarterly base dividends while maintaining balance sheet quality and managing working capital requirements. During the first half of 2025, the Corporation repurchased and cancelled 7.1 million shares under its normal course issuer bid ("NCIB") program at a weighted-average price of $23.66 per share, totaling $168 million. As a result of the Strathcona Resources Ltd. ("Strathcona") unsolicited offer, and in accordance with applicable securities laws, the Corporation has paused all share repurchases under its NCIB program. On July 31, 2025, the Corporation's Board of Directors approved a 10% increase in the quarterly cash dividend to $0.11 per share, reflecting the Corporation's commitment to consistent and long-term dividend growth. This dividend will be paid on October 15, 2025 to shareholders of record on September 12, 2025. Outlook The Corporation's 2025 operating and capital guidance released on November 25, 2024 remains unchanged. Take-Over Offer On May 30, 2025, an unsolicited take-over offer was made by Strathcona to acquire all MEG's issued and outstanding shares. The Corporation's Board of Directors has unanimously recommended that shareholders reject the offer by taking no action and not tendering their shares. A Directors' Circular, filed on June 16, 2025, provides information for MEG shareholders about MEG's prospects and the Board's analysis, deliberations and recommendations at and on Additional information can be found in the Investor Presentation, which is available at Strategic Review With a focus on value maximization for Shareholders, the Board has authorized a strategic review of alternatives with the potential to surface an offer superior to MEG's compelling standalone plan. BMO Capital Markets, the Board's financial advisor, has begun an outreach to potential parties to solicit interest in an alternative transaction. Adjusted Funds Flow Sensitivity MEG's production is composed entirely of crude oil, and AFF is highly correlated with crude oil benchmark prices and light-heavy oil differentials. The following table provides an annual sensitivity estimate to the most significant market variables. Variable Range 2025 AFF Sensitivity (1)(2) - C$ WCS Differential (US$/bbl) +/- US$1.00/bbl +/- C$46mm WTI (US$/bbl) +/- US$1.00/bbl +/- C$32mm Bitumen Production (bbls/d) +/- 1,000 bbls/d +/- C$16mm Condensate (US$/bbl) +/- US$1.00/bbl +/- C$14mm Exchange Rate (C$/US$) +/- $0.01 +/- C$10mm Non-Energy Opex (C$/bbl) +/- C$0.25/bbl +/- C$6mm AECO Gas (3) (C$/GJ) +/- C$0.50/GJ +/- C$5mm (1) Each sensitivity is independent of changes to other variables. (2) Assumes mid-point of 2025 production guidance, US$70.00/bbl WTI, ~US$13.00/bbl Edmonton/PADD II WTI:WCS discount, C$1.35/US$ F/X rate, condensate purchased at 100% of WTI, and one bbl of bitumen per 1.42 bbls of blend sales (1.42 blend ratio). (3) Assumes 1.3 GJ/bbl of bitumen, 64% of 150 MW of power generation sold externally and a 25.0 heat rate (every $0.50/GJ change in AECO natural gas price changes the power price by C$12.50/MWh). Conference Call MEG's management will hold a conference to review MEG's second quarter 2025 results on August 1, 2025, at 6:30 a.m. Mountain Time (8:30 a.m. Eastern Time). To participate, please dial the North American toll-free number 1-800-715-9871, or the international call number 1-647-932-3411. A recording of the call will be available by 12:00 p.m. Mountain Time (2:00 p.m. Eastern Time) on the same day at Basis of Presentation MEG prepares its financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS Accounting Standards") and presents financial results in Canadian dollars ($ or C$), which is the Corporation's functional currency. Non-GAAP and Other Financial Measures Certain financial measures in this news release are non-GAAP financial measures or ratios, supplementary financial measures and capital management measures. These measures are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP and other financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Adjusted Funds Flow and Free Cash Flow AFF and FCF are capital management measures defined in the Corporation's consolidated financial statements and are presented to assist management and investors in analyzing operating performance and cash flow generating ability. Net cash provided by (used in) operating activities is an IFRS measure in the Corporation's consolidated statement of cash flow. AFF is calculated as net cash provided by (used in) operating activities before the net change in non-cash working capital items and excludes items not considered part of ordinary continuing operating results. By excluding non-recurring adjustments, the AFF measure provides a meaningful metric for management and investors by establishing a clear link between the Corporation's cash flows and cash operating netback. FCF is calculated as adjusted funds flow less capital expenditures. FCF is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to return capital to shareholders. The following table reconciles Net cash provided by (used in) operating activities to AFF and FCF: Cash Operating Netback Cash operating netback is a non-GAAP financial measure, or ratio when expressed on a per barrel basis. Its terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. This non-GAAP financial measure should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Cash operating netback is a financial measure widely used in the oil and gas industry as a supplemental measure of a company's efficiency and its ability to generate cash flow for debt repayment, dividends, capital expenditures, or other uses. The per barrel calculation of cash operating netback is based on bitumen sales volumes. Revenues is an IFRS measure in the Corporation's consolidated statement of earnings and comprehensive income which is the most directly comparable primary financial statement measure to cash operating netback. A reconciliation from revenues to cash operating netback has been provided below: Blend Sales and Bitumen Realization Blend sales and bitumen realization are non-GAAP financial measures, or ratios when expressed on a per barrel basis, and are used as measures of the Corporation's marketing strategy by isolating petroleum revenue and costs associated with its produced and purchased products and excludes royalties. Their terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Blend sales per barrel is based on blend sales volumes and bitumen realization per barrel is based on bitumen sales volumes. Revenues is an IFRS measure in the Corporation's consolidated statement of earnings and comprehensive income, which is the most directly comparable primary financial statement measure to blend sales and bitumen realization. A reconciliation from revenues to blend sales and bitumen realization has been provided below: Net Transportation and Storage Expense Net transportation and storage expense is a non-GAAP financial measure, or ratio when expressed on a per barrel basis. Its terms are not defined by IFRS and therefore may not be comparable to similar measures provided by other companies. This non-GAAP financial measure should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Per barrel amounts are based on bitumen sales volumes. It is used as a measure of the Corporation's marketing strategy by focusing on maximizing the realized AWB sales price after transportation and storage expense by utilizing its network of pipeline and storage facilities to optimize market access. Transportation and storage expense is an IFRS measure in the Corporation's consolidated statements of earnings and comprehensive income. Power and transportation revenue is an IFRS measure in the Corporation's consolidated statement of earnings and comprehensive income, which is the most directly comparable primary financial statement measure to transportation revenue. A reconciliation from power and transportation revenue to transportation revenue has been provided below. Bitumen Realization after Net Transportation and Storage Expense Bitumen realization after net transportation and storage expense is a non-GAAP financial measure, or ratio when expressed on a per barrel basis. Its terms are not defined by IFRS and therefore may not be comparable to similar measures provided by other companies. This non-GAAP financial measure should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Per barrel amounts are based on bitumen sales volumes. It is used as a measure of the Corporation's marketing strategy by focusing on maximizing the realized AWB sales price after net transportation and storage expense by utilizing its network of pipeline and storage facilities to optimize market access. Three months ended June 30 Six months ended June 30 2025 2024 2025 2024 ($millions, except as indicated) $/bbl $/bbl $/bbl $/bbl Bitumen realization (1) $ 459 $ 71.21 $ 772 $ 91.11 $ 1,230 $ 78.71 $ 1,478 $ 81.80 Net transportation and storage expense (1) (158) (24.49) (147) (17.27) (323) (20.67) (276) (15.25) Bitumen realization after net transportation and storage expense $ 301 $ 46.72 $ 625 $ 73.84 $ 907 $ 58.04 $ 1,202 $ 66.55 (1) Non-GAAP financial measure as defined in this section. Operating Expenses net of Power Revenue and Energy Operating Costs net of Power Revenue Operating expenses net of power revenue and energy operating costs net of power revenue are both non-GAAP financial measures, or ratios when expressed on a per barrel basis. Their terms are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Per barrel amounts are based on bitumen sales volumes. Operating expenses net of power revenue is used as a measure of the Corporation's cost to operate its facilities at the Christina Lake project after factoring in the benefits from selling excess power to offset energy costs. Energy operating costs net of power revenue is used to measure the performance of the Corporation's cogeneration facilities to offset energy operating costs. Non-energy operating costs and energy operating costs are supplementary financial measures as they represent portions of operating expenses. Non-energy operating costs comprise production-related operating activities and energy operating costs reflect the cost of natural gas used as fuel to generate steam and power. Per barrel amounts are based on bitumen sales volumes. Operating expenses is an IFRS measure in the Corporation's consolidated statement of earnings and comprehensive income. Power and transportation revenue is an IFRS measure in the Corporation's consolidated statement of earnings and comprehensive income which is the most directly comparable primary financial statement measure to power revenue. A reconciliation from power and transportation revenue to power revenue has been provided below. Forward-Looking Information Certain statements contained in this news release may constitute forward-looking statements within the meaning of applicable Canadian securities laws. These statements relate to future events or MEG's future performance. All statements other than statements of historical fact may be forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe", "plan", "intend", "target", "potential" and similar expressions are intended to identify forward-looking statements. Forward-looking statements are often, but not always, identified by such words. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. In particular, and without limiting the foregoing, this press release contains forward looking statements with respect to: the Corporation's 2025 operating and capital guidance, including its expectations regarding 2025 annual average production, capital expenditures and non-energy operating costs; the Corporation's belief that the FEP remains on track for completion in 2027; the Corporation's intent to return 100% of free cash flow to shareholders through a combination of share repurchases and payment of a quarterly base dividend, subject to approval of the Board of Directors; the strategic review process; and the Corporation's funds flow sensitivity estimates. Forward-looking information contained in this press release is based on management's expectations and assumptions regarding, among other things: future crude oil, bitumen blend, natural gas, electricity, condensate and other diluent prices, differentials, the reaction of heavy oil differentials in response to increased Canadian pipeline capacity; foreign exchange rates and interest rates; the recoverability of MEG's reserves and contingent resources; MEG's ability to produce and market production of bitumen blend successfully to customers; future growth, results of operations and production levels; future capital and other expenditures; revenues, expenses and cash flow; operating costs; reliability; continued liquidity and runway to sustain operations through a prolonged market downturn; MEG's ability to reduce or increase production to desired levels, including without negative impacts to its assets; anticipated reductions in operating costs as a result of optimization and scalability of certain operations; anticipated sources of funding for operations and capital investments; plans for and results of drilling activity; the regulatory framework governing royalties, land use, taxes and environmental matters, including federal and provincial climate change policies, in which MEG conducts and will conduct its business; and business prospects and opportunities. By its nature, such forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks and uncertainties include, but are not limited to, risks and uncertainties related to: the oil and gas industry, for example, the securing of adequate access to markets and transportation infrastructure (including pipelines and rail) and the commitments therein; the availability of capacity on the electricity transmission grid; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and revenues; support for protectionism and rising anti-globalization sentiment in the United States and other countries; enacted and proposed export and import restrictions, including but not limited to tariffs, export taxes or curtailment on exports; health, safety and environmental risks, including public health crises and any related actions taken by governments and businesses; legislative and regulatory changes to, amongst other things, tax, land use, royalty and environmental laws and production curtailment; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; the inability to access government support to industry to assist in the achievement of ESG goals; risks relating to shareholder activism; assumptions regarding and the volatility of commodity prices, interest rates and foreign exchange rates; commodity price, interest rate and foreign exchange rate swap contracts and/or derivative financial instruments that MEG may enter into from time to time to manage its risk related to such prices and rates; timing of completion, commissioning, and start-up, of MEG's turnarounds; the operational risks and delays in the development, exploration, production, and the capacities and performance associated with MEG's projects; MEG's ability to reduce or increase production to desired levels, including without negative impacts to its assets; MEG's ability to finance capital expenditures; MEG's ability to maintain sufficient liquidity to sustain operations through a prolonged market downturn; changes in credit ratings applicable to MEG or any of its securities; actions taken by OPEC+ in relation to supply management; the impact of the Russian invasion of Ukraine and associated sanctions on commodity prices; the availability and cost of labour and goods and services required in the Corporation's operations, including inflationary pressures; supply chain issues including transportation delays; the cost and availability of equipment necessary to our operations; and changes in general economic, market and business conditions. Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive. Further information regarding the assumptions and risks inherent in the making of forward-looking statements can be found in MEG's most recently filed Annual Information Form ("AIF"), along with MEG's other public disclosure documents. Copies of the AIF and MEG's other public disclosure documents are available through the Company's website at and through the SEDAR+ website at The forward-looking information included in this news release is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this news release is made as of the date of this news release and MEG assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. This news release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about MEG's prospective results of operations including, without limitation, the Corporation's AFF based on certain market variables, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. MEG's actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits MEG will derive therefrom. MEG has included the FOFI in order to provide readers with a more complete perspective on MEG's future operations, and the factors that could affect such operations, and such information may not be appropriate for other purposes. MEG disclaims any intention or obligation to update or revise any FOFI statements, whether as a result of new information, future events or otherwise, except as required by law. About MEG MEG is the leading pure-play in situ thermal oil producer in Canada. Our purpose is to meet the growing demand for energy, produced safely and reliably, while generating long-term value for all our stakeholders. MEG produces, transports and sells our oil (AWB) to customers throughout North America and internationally. Our common shares are listed on the Toronto Stock Exchange under the symbol "MEG" (TSX: MEG). For further information, please contact: Investor Relations T 403.767.0515 E [email protected] Media Relations T 403.775.1131 E [email protected] SOURCE MEG Energy Corp.
