Earnings release
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MEG Energy Delivers Record Q3 Production and Strong Third Quarter 2025 Financial Results CALGARY , ALBERTA (November 10, 2025) – MEG Energy Corp. (TSX:MEG) (“MEG” or the “Corporation”) reported its third quarter 2025 operational and financial results.1 "Our strong third quarter results are a testament to MEG's journey as a top-tier oil sands producer, built on the dedication, expertise, and innovation of our people," said Darlene Gates, President and Chief Executive Officer. "I am deeply proud of what we have accomplished together. I want to thank our employees, partners, and the communities who have supported us throughout our journey. As we look ahead, I am confident that MEG's legacy of operational excellence and value creation will continue to thrive." Key Highlights: • Record Q3 production: 108,166 bbls/d at a 2.27 steam -oil ratio ("SOR"), driven by strong facility performance post-turnaround and efficient ramp-up of the newest well pad. • Facility Expansion Project ("FEP") on track: Completion planned in 2027, with additional steam capacity in service in 2026. The once through steam generator has been delivered to site and module fabrication commenced during the quarter. • Strong adjusted funds flow ("AFF"): AFF of $368 million ($1.44 per share); Free Cash Flow ("FCF") of $239 million ($0.93 per share). • Disciplined capital investment: $129 million in capital expenditures, focused on FEP and advancing pad development into areas of improved resource quality. • Shareholder capital returns: On July 31, 2025, the Board approved a 10% increase in the quarterly dividend to $0.11 per share, paid on October 15, 2025, demonstrating MEG's commitment to consistent, long-term dividend growth. • Stable guidance: 2025 operating and capital guidance remains unchanged. 1 All financial figures are in Canadian dollars ($ or C$) and all references to barrels are per barrel of bitumen unless otherwise noted. The Corporation's Non-GAAP and Other Financial Measures are detailed in the Advisory section of this news release. They include: cash operating netback, bitumen realization net of transportation and storage expense, operating expenses net of power revenue, energy operating costs net of power revenue, non- energy operating costs, energy operating costs, adjusted funds flow and free cash flow.
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2 The following table summarizes selected operational and financial information of the Corporation for the periods noted. All dollar amounts are stated in Canadian dollars ($ or C$) unless otherwise noted and all per barrel financial results are based on bitumen sales volumes: Nine months ended Sept 30 2025 2024 ($millions, except as indicated) 2025 2024 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Operational results: Bitumen production - bbls/d 91,649 102,641 108,166 63,502 103,224 100,139 103,298 100,531 104,088 Per share, diluted 0.10 0.10 0.04 0.02 0.04 0.03 0.04 0.03 0.03 Steam-oil ratio 2.30 2.39 2.27 2.38 2.28 2.40 2.36 2.44 2.37 Bitumen sales - bbls/d 89,769 101,324 96,484 70,760 102,126 100,821 105,255 93,140 105,534 Business environment: WTI - US$/bbl 66.70 77.54 64.93 63.74 71.42 70.27 75.09 80.57 76.96 Differential - WTI:WCS - Edmonton - US$/bbl (11.11) (15.49) (10.39) (10.27) (12.67) (12.56) (13.55) (13.61) (19.31) AWB - Edmonton - US$/bbl 54.69 60.86 53.58 52.70 57.77 56.82 60.62 65.99 55.96 C$ equivalent of 1 US$ – average 1.3986 1.3603 1.3771 1.3840 1.4350 1.3991 1.3636 1.3684 1.3488 Financial results: Bitumen realization after net transportation and storage expense(1) - $/bbl 58.79 66.22 60.12 46.72 65.98 62.62 65.61 73.84 60.10 Non-energy operating costs(2) - $/bbl 6.12 5.32 4.94 8.16 5.84 5.61 5.18 5.63 5.18 Energy operating costs net of power revenue(1) - $/bbl 1.61 0.94 0.33 2.72 2.06 0.90 0.64 0.99 1.19 Operating expenses net of power revenue(1) - $/bbl 7.73 6.26 5.27 10.88 7.90 6.51 5.82 6.62 6.37 Cash operating netback(1) - $/bbl 40.75 42.65 46.23 25.29 46.30 41.09 41.35 47.14 39.99 Royalties 252 459 76 68 108 132 169 162 128 Adjusted funds flow(3) 873 1,045 368 125 380 340 362 354 329 Per share, diluted 3.40 3.83 1.44 0.49 1.47 1.29 1.34 1.30 1.19 Capital expenditures 486 376 129 200 157 172 141 123 112 Free cash flow(3) 387 669 239 (75) 223 168 221 231 217 Per share, diluted 1.51 2.46 0.93 (0.30) 0.86 0.64 0.82 0.85 0.78 Weighted average common shares outstanding - diluted 256 273 256 255 258 263 269 272 276 Debt repayments - US$ — 258 — — — — 100 53 105 Share repurchases - C$ 168 303 — 9 159 151 108 68 127 Dividends paid - C$ 78 — 26 26 26 27 — — — Revenues 3,100 4,002 1,181 757 1,162 1,147 1,265 1,373 1,364 Net earnings 437 401 159 67 211 106 167 136 98 Per share, diluted 1.71 1.47 0.62 0.26 0.82 0.40 0.62 0.50 0.36 (1) Non-GAAP financial measure - please refer to the Advisory section of this news release. (2) Supplementary financial measure - please refer to the Advisory section of this news release. (3) Capital management measure - please refer to the Advisory section of this news release. Financial Results Third quarter 2025 AFF increased to $368 million from $362 million in Q3 2024, as lower blend sales volumes and prices were more than offset by reduced diluent expense and royalties. On a diluted per share basis, AFF increased to $1.44 from $1.34, reflecting increased AFF and share repurchases.
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3 For the nine months ended September 30, 2025, AFF was $873 million, $172 million lower than the same period in 2024, primarily due to lower blend sales volumes and prices partially offset by lower diluent expense and royalties. On a diluted per share basis, AFF was $3.40 compared to $3.83 in 2024, reflecting decreased AFF partially offset by share repurchases. Third quarter FCF rose to $239 million from $221 million Q3 2024, reflecting higher AFF and lower capital expenditures. Year-to-date FCF declined to $387 million in 2025, from $669 million last year, due to lower 2025 AFF and higher 2025 capital expenditures for the FEP and turnaround activity. During the third quarter, $26 million was returned to shareholders through dividends. In light of the Strathcona Resources Ltd. ("Strathcona") unsolicited offer and the subsequent Cenovus Energy Inc. (“Cenovus”) plan of arrangement, all share repurchases under the normal course issuer bid ("NCIB") were paused in accordance with applicable securities laws. Net earnings were $159 million in Q3 2025, compared to $167 million in Q3 2024, primarily driven by an unrealized foreign exchange loss and transaction costs in 2025 related to the Strathcona unsolicited offer and the Cenovus plan of arrangement partially offset by lower depletion and depreciation. Year-to-date net earnings were $437 million and $401 million in 2025 and 2024, respectively, as lower AFF was more than offset by reduced depletion and depreciation and an unrealized foreign exchange gain. Operational Results Bitumen production averaged 108,166 barrels per day, at a 2.27 SOR and 91,649 barrels per day, at a 2.30 SOR, during the three and nine months ended September 30, 2025, respectively. This compares to 103,298 barrels per day, at a 2.36 SOR, and 102,641 barr els per day, at a 2.39 SOR, in the same periods of 2024. Record third quarter 2025 production reflects strong facility performance post-turnaround and efficient ramp-up of the newest well pad. Production in the nine months ended September 30, 2025 was primarily impacted by planned 2025 turnaround activities and wildfire delays to the post -turnaround ramp -up. The lower 2025 SOR reflects the allocation of steam to higher quality resource and optimized well designs in recent pads partially offset by the impact of the planned turnaround. Third quarter 2025 non-energy operating costs were $44 million, or $4.94 per barrel, compared to $49 million, or $5.18 per barrel in the same period of 2024. Year-to-date non-energy operating costs were $150 million, compared to $147 million in 2024. On a per barrel basis, 2025 non-energy operating costs rose to $6.12 per barrel from $5.32 per barrel in 2024 reflecting the turnaround and wildfire impacts. Capital expenditures were $129 million and $486 million in the three and nine months ended September 30, 2025, respectively, compared to $141 million and $376 million in the same periods of 2024. The increase reflects the planned turnaround and FEP investments. Capital Allocation Strategy In the first half of 2025, MEG repurchased and cancelled 7.1 million shares under the NCIB program at a weighted-average price of $23.66 per share, totaling $168 million. Share repurchases were suspended in May 2025 following the Strathcona offer and Cenovus arrangement. In line with its commitment to consistent and long -term dividend growth, the Board approved a 10% increase in the quarterly dividend to $0.11 per share on July 31, 2025, paid on October 15, 2025. Outlook 2025 operating and capital guidance, as released on November 25, 2024, remains unchanged:
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4 Summary of 2025 Guidance Capital expenditures $635 million Bitumen production - 2025 annual average 95,000 to 105,000 bbls/d Non-energy operating costs $5.30 to $5.80 per bbl Cenovus Plan of Arrangement An unsolicited take-over offer was made by Strathcona Resources Ltd. ("Strathcona") on May 30, 2025 to acquire all MEG’s issued and outstanding shares not already owned by Strathcona. Prior to commencing the offer, Strathcona announced that it owned 9.2% of the outstanding MEG shares. The Corporation’s Board of Directors evaluated the offer and unanimously recommended that shareholders reject the offer. A Directors’ Circular was filed on June 16, 2025 providing information regarding the Board’s recommendati ons and the Board’s intention to conduct a strategic review of alternatives. On August 22, 2025, the Corporation's Board announced an arrangement agreement with Cenovus Energy Inc. ("Cenovus") pursuant to which Cenovus would acquire all the issued and outstanding MEG shares in a transaction that valued MEG at $27.25 per share, with the consideration to be paid 75% in cash and 25% in Cenovus shares. Subsequent to the announcement of the MEG and Cenovus arrangement transaction, Strathcona announced that it had increased its ownership of MEG shares to 14.2% and on September 8, 2025, Strathcona announced a revised offer that valued MEG at $30.86 per shar e, with consideration comprised entirely of Strathcona shares. MEG subsequently announced on September 15, 2025 that the Board of Directors reaffirmed its unanimous recommendation that shareholders vote for the MEG and Cenovus arrangement transaction and to reject the revised Strathcona offer. On October 8, 2025, Cenovus and MEG announced an amended arrangement agreement that increased the offer price to $29.80 per MEG share and altered the consideration payable by Cenovus to be 50% cash and 50% Cenovus shares. Strathcona terminated its bid to acquire MEG on October 10, 2025. On October 27, 2025, Cenovus and MEG announced a second amended arrangement agreement that further increased the offer price to $30.00 per MEG share. This improved offer price represented a 47% premium to MEG’s unaffected 20- day volume-weighted share pric e as of May 15, 2025, the last trading day preceding the first public announcement by Strathcona that it intended to acquire MEG. Also on October 27, 2025, MEG announced that it had been advised by Cenovus that Strathcona entered into a shareholder support agreement with Cenovus pursuant to which Strathcona had agreed to vote its MEG shares in support of the MEG and Cenovus arrangement transaction at the MEG shareholder meeting to be held on October 30, 2025. The value of the Cenovus offer had increased to $30.37 per MEG share based on the closing price of Cenovus shares on November 7, 2025. The special meeting of shareholders of MEG was convened as scheduled on October 30, 2025 but was adjourned, with the consent of Cenovus, to November 6, 2025 in order to permit MEG to respond to a regulatory inquiry requesting additional disclosure in respect of MEG’s consideration of the amended arrangement agreement entered into on October 27, 2025. MEG issued a press release on October 31, 2025 providing such additional disclosure. On November 6, 2025, the special meeting of shareholders of MEG was held a nd the shareholders approved the arrangement between MEG and Cenovus. Closing of the transaction remains subject to the approval of the Court of King’s Bench of Alberta and the Court hearing to obtain such approval is set for November 12, 2025. Assuming such approval is obtained on November 12, 2025, closing will occur shortly thereafter. Further information can be found at www.megenergy.com/offer-update and on www.sedarplus.ca. Additional information can be found in the Investor Presentation, which is available at www.megenergy.com/offer-update.
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5 Adjusted Funds Flow Sensitivity MEG’s production is composed entirely of crude oil, and AFF is highly correlated with crude oil benchmark prices and light-heavy oil differentials. The following table provides an annual sensitivity estimate to the most significant market variables. Variable Range 2025 AFF Sensitivity(1)(2) - C$ 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$12.50/MWh). ADVISORY Basis of Presentation MEG prepares its financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS Accounting Standards”) and presents financial results in Canadian dollars ($ or C$), which is the Corporation’s functional currency. Non-GAAP and Other Financial Measures Certain financial measures in this news release are non -GAAP financial measures or ratios, supplementary financial measures and capital management measures. These measures are not defined by IFRS and, therefore, may not be comparable to similar measures provided by other companies. These non-GAAP and other financial measures should not be considered in isolation or as an alternative for measures of performance prepared in accordance with IFRS. Adjusted Funds Flow and Free Cash Flow AFF and FCF are capital management measures defined in the Corporation's consolidated financial statements and are presented to assist management and investors in analyzing operating performance and cash flow generating ability. Net cash provided by (used in) operating activities is an IFRS measure in the Corporation's consolidated statement of cash flow. AFF is calculated as net cash provided by (used in) operating activities before the net change in non -cash working capital items and excludes items not considered part of ordinary continuing operating results. By excluding non-recurring adjustments, the AFF measure provides a meaningful metric for management and investors by establishing a clear link between the Corporation's cash flows and cash operating n etback. FCF is calculated as adjusted funds flow less capital expenditures. FCF is presented to assist management and investors in analyzing performance by the Corporation as a measure of financial liquidity and the capacity of the business to return capital to shareholders. The following table reconciles Net cash provided by (used in) operating activities to AFF and FCF:
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6 Three months ended September 30 Nine months ended September 30 ($millions) 2025 2024 2025 2024 Net cash provided by operating activities $ 140 $ 441 $ 765 $ 1,029 Net change in non-cash working capital items 203 (79) 77 16 Transaction Costs 25 — 31 — Adjusted funds flow 368 362 873 1,045 Capital expenditures (129) (141) (486) (376) Free cash flow $ 239 $ 221 $ 387 $ 669 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: Three months ended September 30 Nine months ended September 30 ($millions) 2025 2024 2025 2024 Revenues $ 1,181 $ 1,265 $ 3,100 $ 4,002 Diluent expense (314) (403) (1,059) (1,271) Transportation and storage expense (171) (171) (495) (448) Purchased product (228) (214) (331) (859) Operating expenses (57) (66) (215) (218) Realized loss on commodity risk management — (10) — (22) Cash operating netback $ 411 $ 401 $ 1,000 $ 1,184 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 alternati ve 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.
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7 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: Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 ($millions, except as indicated) $/bbl $/bbl $/bbl $/bbl Revenues $ 1,181 $ 1,265 $ 3,100 $ 4,002 Power and transportation revenue (10) (10) (27) (46) Royalties 76 169 252 459 Petroleum revenue 1,247 1,424 3,325 4,415 Purchased product (228) (214) (331) (859) Blend sales 1,019 $ 84.18 1,210 $ 90.51 2,994 $ 86.42 3,556 $ 90.37 Diluent expense (314) (4.77) (403) (7.25) (1,059) (7.46) (1,271) (8.06) Bitumen realization $ 705 $ 79.41 $ 807 $ 83.26 $ 1,935 $ 78.96 $ 2,285 $ 82.31 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. Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 ($millions, except as indicated) $/bbl $/bbl $/bbl $/bbl Transportation and storage expense $ (171) $ (19.29) $ (171) $ (17.69) $ (495) $ (20.20) $ (448) $ (16.15) Power and transportation revenue $ 10 $ 10 $ 27 $ 46 Less power revenue (10) (10) (26) (45) Transportation revenue $ — $ — $ — $ 0.04 $ 1 $ 0.03 $ 1 $ 0.06 Net transportation and storage expense $ (171) $ (19.29) $ (171) $ (17.65) $ (494) $ (20.17) $ (447) $ (16.09)
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8 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 September 30 Nine months ended September 30 2025 2024 2025 2024 ($millions, except as indicated) $/bbl $/bbl $/bbl $/bbl Bitumen realization(1) $ 705 $ 79.41 $ 807 $ 83.26 $ 1,935 $ 78.96 $ 2,285 $ 82.31 Net transportation and storage expense(1) (171) (19.29) (171) (17.65) (494) (20.17) (447) (16.09) Bitumen realization after net transportation and storage expense $ 534 $ 60.12 $ 636 $ 65.61 $ 1,441 $ 58.79 $ 1,838 $ 66.22 (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 simil ar 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 whi ch 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.
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9 Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 ($millions, except as indicated) $/bbl $/bbl $/bbl $/bbl Non-energy operating costs $ (44) $ (4.94) $ (49) $ (5.18) $ (150) $ (6.12) $ (147) $ (5.32) Energy operating costs (13) (1.47) (17) (1.70) (65) (2.66) (71) (2.54) Operating expenses $ (57) $ (6.41) $ (66) $ (6.88) $ (215) $ (8.78) $ (218) $ (7.86) Power and transportation revenue $ 10 $ 10 $ 27 $ 46 Less transportation revenue — — (1) (1) Power revenue $ 10 $ 1.14 $ 10 $ 1.06 $ 26 $ 1.05 $ 45 $ 1.60 Operating expenses net of power revenue $ (47) $ (5.27) $ (56) $ (5.82) $ (189) $ (7.73) $ (173) $ (6.26) Energy operating costs net of power revenue $ (3) $ (0.33) $ (7) $ (0.64) $ (39) $ (1.61) $ (26) $ (0.94) 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 statement s 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 fo rward-looking statements. In particular, and without limiting the foregoing, this press release contains forward looking statements with respect to: the completion of the arrangement transaction between the Corporation and Cenovus (the "Arrangement"), the date of the final order application at the Court of King's Bench of Alberta regarding the Arrangement; the timing of closing of the Arrangement; 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 and that additional steam capacity will be in service in 2026; 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: the satisfaction of the conditions to closing of the Arrangement; the completion of the Arrangement on the anti cipated terms and timing, or at all; that actions by third parties do not delay or otherwise adversely affect completion of the Arrangement; 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; anti cipated 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 policie s, in which MEG conducts and will conduct its business; and business prospects and opportunities. By its nature, such forward -looking
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10 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 risk that the Arrangement may be varied, accelerated or terminated in certain circumstances; risks relating to the outcome of the Arrangement; the risk that the conditions to closing the Arrangement may not be satisfied, or to the extent permitted, waived; 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 expo rt 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 d esired 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 t o 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 forwa rd-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 an d MEG's other public disclosure documents are available through the Company's website at www.megenergy.com/investors and through the SEDAR+ website at www.sedarplus.ca. 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,
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11 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). Learn more at: www.megenergy.com For further information, please contact: Investor Relations T 403.767.0515 E invest@megenergy.com Media Relations T 403.775.1131 E media@megenergy.com