Cenovus Energy(CVE) - 2025 Q2 - Quarterly Report

Overview of Cenovus Company Profile and Strategy Cenovus is an integrated energy company focused on maximizing shareholder value through sustainable, low-cost, and diversified energy leadership - Cenovus is a Canadian-based integrated energy company with upstream operations in Canada and Asia Pacific, and downstream operations in Canada and the U.S[5][6] - The company's strategy aims to maximize shareholder value through sustainable, low-cost, diversified, and integrated energy leadership, with five strategic objectives including top-tier safety, competitive cost structures, financial discipline, disciplined capital allocation, and free funds flow growth[8] - Cenovus's 2025 corporate guidance, updated on July 30, 2025, focuses on disciplined capital allocation, cost control, and improving downstream profitability[9] Our Operations Cenovus operates through distinct upstream segments (Oil Sands, Conventional, Offshore) and downstream segments (Canadian and U.S. Refining) - Upstream segments include Oil Sands (bitumen and heavy oil in Alberta/Saskatchewan), Conventional (NGLs and natural gas in Alberta/British Columbia), and Offshore (operations in East Coast Canada and Asia Pacific)[10][12] - Downstream segments include Canadian Refining (Lloydminster upgrading and asphalt refining, commercial fuels) and U.S. Refining (Lima, Superior, Toledo, Wood River, and Borger refineries)[11][13] - Corporate and Eliminations covers general and administrative, financing, risk management, foreign exchange, and inter-segment adjustments for feedstock and refined products[14] Quarterly Results Overview Q2 2025 Highlights In Q2 2025, Cenovus completed key turnarounds and advanced growth projects, though production decreased, while returning significant capital to shareholders - Delivered safe operations and completed turnarounds at Foster Creek, Sunrise, and Toledo Refinery; temporarily shut-in production at Christina Lake due to wildfires and Rush Lake facilities due to a casing failure[15] - Progressed key growth projects: Narrows Lake tie-back to Christina Lake achieved first oil in July, one new well pad brought online at Sunrise, Foster Creek optimization project 87% complete, and West White Rose Project 92% complete[15] - Returned $819 million to common and preferred shareholders, including $301 million in common share buybacks, $368 million in base dividends, and $150 million in preferred share redemptions[16] Q2 2025 Key Financial and Operational Highlights | Metric | Q2 2025 | Q1 2025 | Q2 2024 | | :--- | :--- | :--- | :--- | | Upstream Production Volumes (MBOE/d) | 765.9 | 818.9 | 800.8 | | Downstream Total Processed Inputs (Mbbls/d) | 714.9 | 700.5 | 652.9 | | Revenues ($ millions) | 12,319 | 13,299 | 14,582 | | Operating Margin ($ millions) | 2,066 | 2,811 | 2,936 | | Adjusted Funds Flow ($ millions) | 1,519 | 2,212 | 2,361 | | Cash From Operating Activities ($ millions) | 2,374 | 1,315 | 2,807 | | Net Earnings (Loss) ($ millions) | 851 | 859 | 1,000 | | Capital Investment ($ millions) | 1,164 | 1,229 | 1,155 | | Free Funds Flow ($ millions) | 355 | 983 | 1,206 | | Net Debt ($ millions) | 4,934 | 5,079 | 4,258 | Operating and Financial Results Selected Operating and Financial Results — Upstream Total upstream production decreased in Q2 and H1 2025 due to temporary shut-ins and turnarounds, partially offset by optimization and new wells Upstream Production Volumes (MBOE/d) | Segment | Q2 2025 | Change (%) vs Q2 2024 | Q2 2024 | H1 2025 | Change (%) vs H1 2024 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Oil Sands | 579.8 | (5) | 611.5 | 602.9 | (2) | 613.4 | | Conventional | 119.8 | (3) | 123.1 | 121.8 | — | 121.9 | | Offshore | 66.3 | — | 66.2 | 67.5 | 3 | 65.6 | | Total | 765.9 | (4) | 800.8 | 792.2 | (1) | 800.9 | - Production decreases were mainly due to temporary shut-ins at Christina Lake (wildfire) and Rush Lake (casing failure), and turnaround activities at Foster Creek and Sunrise[24][25] - Decreases were partially offset by increased production from optimization and new well pads at Foster Creek and Sunrise, the safe restart of White Rose field production, and strong base production from Lloydminster conventional heavy oil assets[25] Upstream Per-Unit Operating Expenses ($/BOE) | Segment | Q2 2025 | Change (%) vs Q2 2024 | Q2 2024 | H1 2025 | Change (%) vs H1 2024 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Oil Sands | 13.60 | 19 | 11.47 | 12.64 | 8 | 11.67 | | Conventional | 9.95 | (12) | 11.25 | 10.44 | (14) | 12.14 | | Offshore | 15.94 | (29) | 22.34 | 15.71 | (22) | 20.03 | Selected Operating and Financial Results — Downstream Total downstream throughput increased in Q2 and H1 2025, driven by strong performance and reliability in Canadian and U.S. Refining assets Downstream Crude Oil Unit Throughput (Mbbls/d) | Segment | Q2 2025 | Change (%) vs Q2 2024 | Q2 2024 | H1 2025 | Change (%) vs H1 2024 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Canadian Refining | 112.4 | 109 | 53.8 | 112.2 | 42 | 79.0 | | U.S. Refining | 553.4 | (3) | 568.9 | 553.5 | (1) | 560.0 | | Total | 665.8 | 7 | 622.7 | 665.7 | 4 | 639.0 | - Canadian Refining throughput increased significantly due to strong reliability and recovery from a major Upgrader turnaround in Q2 2024[29] - U.S. Refining throughput remained consistent despite the Toledo turnaround, attributed to improved process unit reliability and ongoing operational improvements[30] Downstream Per-Unit Operating Expenses Excluding Turnaround Costs ($/bbl) | Segment | Q2 2025 | Change (%) vs Q2 2024 | Q2 2024 | H1 2025 | Change (%) vs H1 2024 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Canadian Refining | 10.63 | (66) | 30.92 | 10.72 | (45) | 19.53 | | U.S. Refining | 10.52 | (9) | 11.58 | 11.32 | — | 11.30 | Selected Consolidated Financial Results Consolidated financial results for Q2 and H1 2025 showed a decrease in key metrics due to lower commodity prices and sales volumes Revenues Revenues decreased due to lower benchmark crude oil and refined product pricing, as well as lower sales volumes from turnaround activities Revenues ($ millions) | Period | 2025 | 2024 | | :--- | :--- | :--- | | Q2 | 12,319 | 14,582 | | H1 | 25,618 | 27,645 | - The decrease in revenues for both periods was primarily due to lower benchmark crude oil and refined product pricing[33] - The quarter-over-quarter decrease was also due to lower sales volumes in upstream and U.S. Refining assets from turnaround activities[33] Operating Margin Operating Margin decreased due to lower realized sales prices, reduced sales volumes, and narrowing refining differentials Operating Margin ($ millions) | Period | 2025 | 2024 | | :--- | :--- | :--- | | Q2 | 2,066 | 2,936 | | H1 | 4,877 | 6,127 | - Operating Margin decreased primarily due to lower Realized Sales Prices and sales volumes in Oil Sands and Offshore, lower refined product prices, and narrowing WTI-WCS and upgrading differentials[38] - Higher operating expenses for turnaround activities at Oil Sands and U.S. Refining assets also contributed to the decrease[38] - Partially offset by lower operating expenses and higher sales volumes in Canadian Refining (post-Upgrader turnaround) and lower operating expenses from the completed SeaRose ALE project[38] Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash from operating activities and Adjusted Funds Flow decreased due to lower Operating Margin, though Q2 cash flow was boosted by working capital changes Cash Flow and Adjusted Funds Flow ($ millions) | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Cash From (Used in) Operating Activities | 2,374 | 2,807 | 3,689 | 4,732 | | Adjusted Funds Flow | 1,519 | 2,361 | 3,731 | 4,603 | - Decrease in both metrics for Q2 and H1 2025 was primarily due to lower Operating Margin[43] - For Q2 2025, changes in non-cash working capital increased cash from operating activities by $923 million, mainly from changes in accounts payable, inventories, and income tax receivable[44] Net Earnings (Loss) Net earnings decreased due to lower Operating Margin, partially offset by foreign exchange gains and lower income tax expense Net Earnings (Loss) ($ millions) | Period | 2025 | 2024 | | :--- | :--- | :--- | | Q2 | 851 | 1,000 | | H1 | 1,710 | 2,176 | - The decrease in net earnings for both periods was due to lower Operating Margin[45] - Partially offset by foreign exchange gains in 2025 (compared to losses in 2024) and lower income tax expense[45] Net Debt Net Debt increased to $4.9 billion due to capital investment and shareholder returns, partially offset by cash from operations Net Debt ($ millions) | Metric | June 30, 2025 | December 31, 2024 | | :--- | :--- | :--- | | Total Debt | 7,497 | 7,707 | | Cash and Cash Equivalents | (2,563) | (3,093) | | Net Debt | 4,934 | 4,614 | - Net Debt increased by $320 million from December 31, 2024, mainly due to $2.4 billion in capital investment, $691 million in base dividends, and $350 million in preferred share redemptions[47] - This increase was partially offset by $3.7 billion in cash from operating activities and an unrealized foreign exchange gain of $283 million on long-term debt due to a strengthening Canadian dollar[47] Capital Investment Total capital investment increased to $2.4 billion in H1 2025, primarily directed towards upstream sustaining and growth projects Capital Investment ($ millions) | Segment | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Upstream | 987 | 976 | 2,113 | 1,908 | | Downstream | 174 | 170 | 273 | 268 | | Corporate and Eliminations | 3 | 9 | 7 | 15 | | Total | 1,164 | 1,155 | 2,393 | 2,191 | - Capital investment in H1 2025 was mainly related to sustaining, optimization, and redevelopment programs in the Oil Sands segment, including stratigraphic test wells[52] - Significant investments were also made in the West White Rose project and growth projects in the Oil Sands segment (Sunrise growth, Foster Creek optimization, Lloydminster conventional heavy oil drilling, Narrows Lake tie-back)[52] Drilling Activity In H1 2025, drilling activity focused on stratigraphic and production wells in the Oil Sands and Conventional segments Drilling Activity (H1 2025 vs H1 2024) | Segment | Net Stratigraphic Test Wells and Observation Wells (2025) | Net Stratigraphic Test Wells and Observation Wells (2024) | Net Production Wells (2025) | Net Production Wells (2024) | | :--- | :--- | :--- | :--- | :--- | | Foster Creek | 73 | 82 | 25 | 7 | | Christina Lake | 65 | 58 | 13 | 9 | | Sunrise | 21 | 40 | 2 | — | | Lloydminster Thermal | — | — | 12 | 4 | | Lloydminster Conventional Heavy Oil | — | — | 15 | 3 | | Total Oil Sands | 159 | 180 | 67 | 23 | | Segment | Drilled (2025) | Completed (2025) | Tied-in (2025) | Drilled (2024) | Completed (2024) | Tied-in (2024) | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Conventional | 18 | 24 | 21 | 18 | 14 | 14 | - No wells were drilled or completed in the Offshore segment in H1 2025, compared to one well commenced drilling in China in H1 2024[51] Commodity Prices Underlying Our Financial Results Crude Oil and Condensate Benchmarks Global crude oil benchmarks decreased in Q2 2025, while WTI-WCS differentials narrowed due to increased market access and strong demand for heavy crude Selected Benchmark Prices (Average US$/bbl) | Metric | H1 2025 | Change (%) vs H1 2024 | H1 2024 | Q2 2025 | Q1 2025 | Q2 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Dated Brent | 71.74 | (15) | 84.09 | 67.82 | 75.66 | 84.94 | | WTI | 67.58 | (14) | 78.77 | 63.74 | 71.42 | 80.57 | | Differential WTI – WCS at Hardisty | 11.47 | (30) | 16.47 | 10.27 | 12.67 | 13.61 | | Differential WTI – WCS at Nederland | 3.21 | (50) | 6.48 | 2.74 | 3.68 | 5.88 | - Global crude oil benchmark prices (Brent and WTI) decreased in Q2 2025 due to U.S. economic uncertainty, increasing global supply from unwinding OPEC+ cuts, and geopolitical volatility[57] - WTI-WCS differential at Hardisty narrowed in H1 2025 due to the start-up of Trans Mountain Pipeline expansion (TMX), low Western Canadian Sedimentary Basin inventory, and stronger global demand for heavy crude[59] - Synthetic crude oil at Edmonton strengthened relative to WTI, and Edmonton condensate traded at a smaller discount to WTI in H1 2025, influenced by deep discounts in Q1 2024 and tight Canadian supply[62][66] Refining Benchmarks Refined product crack spreads showed mixed results in H1 2025, with Chicago declining slightly while Group 3 increased on tight inventories Refining Benchmarks (Average US$/bbl) | Metric | H1 2025 | Change (%) vs H1 2024 | H1 2024 | Q2 2025 | Q1 2025 | Q2 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Chicago Regular Unleaded Gasoline | 83.85 | (11) | 94.28 | 84.61 | 83.08 | 99.09 | | Chicago Ultra-low Sulphur Diesel | 88.01 | (14) | 102.04 | 86.91 | 89.12 | 99.80 | | Chicago 3-2-1 Crack Spread | 17.66 | (2) | 18.10 | 21.64 | 13.68 | 18.76 | | Group 3 3-2-1 Crack Spread | 19.77 | 11 | 17.82 | 23.07 | 16.48 | 18.13 | | RINs | 5.44 | 54 | 3.53 | 6.12 | 4.76 | 3.39 | - Chicago 3-2-1 crack spreads slightly declined in H1 2025, while Group 3 crack spreads increased due to tight regional gasoline inventories[68] - Crack spreads increased in Q2 2025, consistent with seasonal trends and increased demand during driving season[68] - Average RINs costs were higher in H1 2025 due to weaker U.S. production and imports of renewable diesel and biodiesel[68] Natural Gas Benchmarks AECO and NYMEX natural gas prices increased significantly in H1 2025, though the AECO discount widened due to limited takeaway capacity Natural Gas Prices | Metric | H1 2025 | Change (%) vs H1 2024 | H1 2024 | Q2 2025 | Q1 2025 | Q2 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | AECO (C$/Mcf) | 1.93 | 5 | 1.84 | 1.69 | 2.17 | 1.18 | | NYMEX (US$/Mcf) | 3.55 | 71 | 2.07 | 3.44 | 3.65 | 1.89 | - AECO prices increased in H1 2025, but the discount to NYMEX widened due to strong production and limited Western Canadian takeaway capacity[72] - NYMEX natural gas prices increased significantly, rebounding from weak 2024 pricing, supported by strong LNG demand[72] Foreign Exchange Benchmarks The Canadian dollar weakened against the U.S. dollar and Chinese Yuan in H1 2025, impacting revenues and operating expenses Foreign Exchange Rates | Metric | H1 2025 | Change (%) vs H1 2024 | H1 2024 | Q2 2025 | Q1 2025 | Q2 2024 | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | US$ per C$1 – Average | 0.710 | (4) | 0.736 | 0.723 | 0.697 | 0.731 | | RMB per C$1 – Average | 5.148 | (3) | 5.311 | 5.226 | 5.069 | 5.293 | - A weaker Canadian dollar relative to the U.S. dollar positively impacted reported revenues but negatively impacted U.S. Refining operating expenses in Q2 and H1 2025[75] - A weaker Canadian dollar relative to the RMB positively impacted reported revenues from Asia Pacific sales in Q2 and H1 2025[76] Interest Rate Benchmarks Interest rates impact various financial aspects, with the Bank of Canada holding its policy rate at 2.75% as of July 30, 2025 - Interest rates influence interest income, short-term borrowing costs, decommissioning liabilities, and fair value measurements[77] - The Bank of Canada's policy interest rate was 2.75% as of June 30, 2025, and remained at this level on July 30, 2025[77] Outlook Commodity Price Outlook Cenovus anticipates continued volatility in global crude oil prices, a narrowing WTI-WCS differential, and range-bound natural gas prices - Global crude oil prices are expected to remain volatile, influenced by OPEC+ policy, geopolitical tensions (Israel-Iran, Russia-Ukraine), non-OPEC+ supply growth, and U.S. tariff policies[78][79][80] - The WTI-WCS at Hardisty differential is expected to narrow due to the start-up of the TMX project, increasing market access for WCS crude[81] - AECO and NYMEX natural gas prices are expected to remain range-bound, with potential support from new LNG facilities[81] - The Canadian dollar's value is expected to be impacted by interest rate differentials between the U.S. and Canada, U.S. trade policies, and crude oil prices[81] Key Priorities for 2025 Priorities for 2025 include safety, executing growth projects, enhancing downstream competitiveness, maintaining shareholder returns, and advancing sustainability goals - Top priorities include top-tier safety performance, maintaining and growing competitive advantages in the Oil Sands business, and executing growth projects like West White Rose and Foster Creek optimization[85][86][87][88] - Focus on downstream competitiveness to respond to fluctuating demand and act as a natural hedge against differentials, implementing operational improvements for long-term profitability[89] - Committed to returning 100% of Excess Free Funds Flow to shareholders over time, while stewarding Net Debt towards a target of $4.0 billion[90] - Sustainability is central, with established ESG targets and continued support for the Pathways Alliance foundational project for large-scale carbon capture[93][94] 2025 Corporate Guidance Updated 2025 guidance reflects decreased upstream production due to shut-ins and increased downstream throughput from strong performance - Updated 2025 guidance includes a decrease at the midpoint of total upstream production due to temporary shut-in at Rush Lake facilities[97] - An increase at the midpoint of total downstream throughput is expected due to strong year-to-date performance[97] 2025 Corporate Guidance (Updated July 30, 2025) | Segment | Capital Investment ($ millions) | Production (MBOE/d) | Crude Oil Unit Throughput (Mbbls/d) | | :--- | :--- | :--- | :--- | | Upstream | | | | | Oil Sands | 2,700 - 2,800 | 620 - 625 | | | Conventional | 350 - 400 | 120 - 125 | | | Offshore | 900 - 1,000 | 65 - 75 | | | Upstream Total | 3,950 - 4,200 | 805 - 825 | | | Downstream | 650 - 750 | | 655 - 690 | | Corporate and Eliminations | Up to 50 | | | - Total expected capital investment range for the full year remains $4.6 billion to $5.0 billion, with $3.2 billion for sustaining capital and $1.4 billion to $1.8 billion for optimization growth capital[96] Reportable Segments Upstream Oil Sands Oil Sands production and Operating Margin decreased in Q2 2025 due to temporary shut-ins, turnarounds, and lower realized prices - Oil Sands production decreased to 579.8 thousand BOE per day in Q2 2025 (from 611.5 in Q2 2024) due to temporary shut-ins at Christina Lake and Rush Lake, and turnarounds at Foster Creek and Sunrise[100][115] Oil Sands Financial Performance | Metric | Q2 2025 ($ millions) | Q2 2024 ($ millions) | H1 2025 ($ millions) | H1 2024 ($ millions) | | :--- | :--- | :--- | :--- | :--- | | Operating Margin | 1,822 | 2,748 | 4,366 | 4,984 | | Netback ($/bbl) | 35.57 | 52.10 | 40.18 | 46.33 | | Realized Sales Price ($/bbl) | 70.78 | 88.76 | 76.16 | 80.62 | - Operating Margin decreased by $926 million in Q2 2025, primarily due to lower Realized Sales Prices and lower sales volumes[100] - Per-unit operating expenses increased at Foster Creek and Sunrise due to turnaround activities and higher GHG compliance costs, and at Lloydminster due to waste fluid handling and lower sales volumes[131][133] Conventional Conventional production decreased slightly in Q2 2025, but Operating Margin and Netback increased significantly due to higher natural gas prices - Produced 119.8 thousand BOE per day in Q2 2025 (down from 123.1 in Q2 2024) due to third-party pipeline outages and divestiture of non-core assets[139][147] Conventional Financial Performance | Metric | Q2 2025 ($ millions) | Q2 2024 ($ millions) | H1 2025 ($ millions) | H1 2024 ($ millions) | | :--- | :--- | :--- | :--- | :--- | | Operating Margin | 84 | 42 | 257 | 191 | | Netback ($/BOE) | 7.79 | 3.68 | 11.83 | 8.30 | | Realized Sales Price ($/BOE) | 24.19 | 22.20 | 29.16 | 27.50 | - Operating Margin increased by $42 million in Q2 2025, and Netback improved, primarily due to higher Realized Sales Prices (driven by natural gas) and lower operating expenses[139][146][150] - Royalties and the effective royalty rate decreased due to lower production of NGLs and light crude oil, which are subject to higher royalty rates[148] Offshore Offshore production increased in H1 2025 driven by the White Rose field ramp-up, while the West White Rose project is 92% complete - Produced 66.3 thousand BOE per day in Q2 2025 (consistent with 2024) and 67.5 thousand BOE per day in H1 2025 (up 3% from 2024)[20][152] - Atlantic production increased due to the ramp-up of the White Rose field, while Asia Pacific production decreased due to lower contracted sales in China and annual maintenance[166][167] Offshore Financial Performance | Metric | Q2 2025 ($ millions) | Q2 2024 ($ millions) | H1 2025 ($ millions) | H1 2024 ($ millions) | | :--- | :--- | :--- | :--- | :--- | | Operating Margin | 231 | 299 | 562 | 545 | | Netback ($/BOE) | 51.02 | 54.33 | 54.79 | 53.63 | - The West White Rose project reached major milestones, including concrete gravity structure installation and topsides setting, and is approximately 92% complete, targeting first oil in Q2 2026[151] - Atlantic operating expenses decreased due to the completion of the SeaRose ALE project, while China's per-unit operating expenses increased due to lower sales volumes, and Indonesia's per-unit operating expenses increased in Q2 due to higher maintenance[171][172][173] Downstream Canadian Refining Canadian Refining achieved strong throughput and utilization in H1 2025, recovering significantly from the major 2024 Upgrader turnaround - Achieved strong crude oil throughput of 112.4 thousand barrels per day and crude unit utilization of 104% in Q2 2025, a significant increase from Q2 2024 (53.8 Mbbls/d and 50%) due to ongoing improvement initiatives and high asset reliability[181][183] Canadian Refining Financial Performance | Metric | Q2 2025 ($ millions) | Q2 2024 ($ millions) | H1 2025 ($ millions) | H1 2024 ($ millions) | | :--- | :--- | :--- | :--- | :--- | | Revenues | 1,288 | 1,135 | 2,570 | 2,467 | | Operating Margin | 107 | (255) | 175 | (187) | | Adjusted Gross Margin | 236 | 165 | 445 | 387 | | Adjusted Refining Margin ($/bbl) | 19.64 | 26.23 | 18.50 | 22.34 | - Operating Margin increased by $362 million in Q2 2025, primarily due to lower operating expenses and higher sales volumes, partially offset by lower refined product pricing and higher feedstock costs from narrowing upgrading differentials[181] - Per-unit operating expenses excluding turnaround costs decreased in Q2 and H1 2025 due to lower project costs and increased total processed inputs, recovering from the major Upgrader turnaround in Q2 2024[186][187] U.S. Refining U.S. Refining financial performance declined due to lower benchmark prices and higher turnaround costs, despite consistent throughput - Safely completed turnarounds at the Toledo Refinery ahead of schedule, and at non-operated Wood River and Borger refineries[188] - Crude unit utilization was 90% in Q2 2025 (down from 93% in Q2 2024), with throughput of 553.4 thousand barrels per day (down from 568.9 Mbbls/d); total refined product production increased slightly due to improved process unit reliability[188][200][201] U.S. Refining Financial Performance | Metric | Q2 2025 ($ millions) | Q2 2024 ($ millions) | H1 2025 ($ millions) | H1 2024 ($ millions) | | :--- | :--- | :--- | :--- | :--- | | Revenues | 6,455 | 7,615 | 12,878 | 14,516 | | Operating Margin | (178) | 102 | (483) | 594 | | Adjusted Gross Margin | 679 | 711 | 1,119 | 1,620 | | Adjusted Refining Margin ($/bbl) | 12.57 | 13.15 | 10.53 | 15.23 | | Adjusted Market Capture (%) | 58 | 63 | 59 | 77 | - Operating Margin shortfall of $178 million in Q2 2025, a decrease of $280 million from Q2 2024, primarily due to narrowing WTI-WCS differential and higher operating expenses from turnaround activities[188] - Adjusted Gross Margin, Adjusted Refining Margin, and Adjusted Market Capture decreased due to lower benchmark gasoline/diesel prices, narrowing WTI-WCS differential, and a 54% increase in RINs costs[193][195][196][198] - Operating expenses increased due to $238 million in turnaround costs recognized in Q2 2025, partially offset by lower controllable operating expenses from business improvement initiatives[203][204] Corporate and Eliminations Financial Results Corporate results were impacted by lower administrative and finance costs, significant foreign exchange gains, and lower tax expenses Corporate and Eliminations Financials ($ millions) | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Realized (Gain) Loss on Risk Management | (20) | — | (25) | 3 | | Unrealized (Gain) Loss on Risk Management | (84) | — | (46) | 30 | | General and Administrative | 153 | 175 | 350 | 421 | | Finance Costs, Net | 114 | 141 | 250 | 276 | | Foreign Exchange (Gain) Loss, Net | (353) | 55 | (353) | 154 | | Total Current Tax Expense (Recovery) | 292 | 355 | 629 | 765 | - General and administrative expenses decreased due to lower long-term incentive costs[208] - Net finance costs were lower due to higher interest income[209] - Unrealized foreign exchange gains of $420 million in Q2 2025 and $401 million in H1 2025 were primarily due to the translation of U.S. denominated debt as the Canadian dollar strengthened[210] - Current tax expense decreased due to lower earnings, resulting in a lower effective tax rate of 20.3% in H1 2025 (vs. 24.0% in H1 2024)[211][212] Liquidity and Capital Resources Cash Flow Summary Cash from operations decreased due to lower Operating Margin, while cash used in financing increased in Q2 from debt repayment and share redemptions Cash Flow Summary ($ millions) | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Cash From (Used In) Operating Activities | 2,374 | 2,807 | 3,689 | 4,732 | | Cash From (Used In) Investing Activities | (1,375) | (1,170) | (2,723) | (2,305) | | Cash From (Used In) Financing Activities | (1,078) | (912) | (1,372) | (1,589) | | Increase (Decrease) in Cash and Cash Equivalents | (205) | 754 | (530) | 927 | - Cash from operating activities decreased in Q2 and H1 2025 due to lower Operating Margin, but Q2 2025 was boosted by $923 million from non-cash working capital changes[217] - Cash used in financing activities increased in Q2 2025 due to short-term borrowing repayment and $150 million in preferred share redemptions, but decreased in H1 2025 due to fewer common share buybacks and no variable dividends[219][220] Working Capital Working capital decreased to $2.3 billion due to lower inventories and cash, partially offset by higher accounts receivable - Working capital as at June 30, 2025, was $2.3 billion, a decrease from $3.1 billion at December 31, 2024[221] - The decrease was primarily driven by lower inventories and cash and cash equivalents, partially offset by higher accounts receivable[221] Returns to Shareholders Target Cenovus aims to return 100% of Excess Free Funds Flow to shareholders while maintaining a Net Debt target of $4.0 billion - The company plans to return 100% of Excess Free Funds Flow to shareholders over time, while stewarding Net Debt near $4.0 billion[223] - The Net Debt target of $4.0 billion represents a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at a WTI price of US$45.00 per barrel[222] Shareholder Returns ($ millions) | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Excess Free Funds Flow | (306) | 735 | 67 | 1,567 | | Purchase of Common Shares Under NCIB | 301 | 440 | 363 | 605 | | Preferred Share Redemption | 150 | — | 350 | — | | Total Shareholder Returns | 451 | 691 | 713 | 856 | Short-Term Borrowings Cenovus had no direct short-term borrowings, but its proportionate share of WRB facility drawings increased to US$188 million - No direct borrowings on uncommitted demand facilities as of June 30, 2025[226] - Proportionate share drawn on WRB uncommitted demand facilities increased to US$188 million (C$256 million) as of June 30, 2025, from US$120 million (C$173 million) at December 31, 2024[226] Long-Term Debt, Including Current Portion Long-term debt decreased to $7.2 billion, and the company remained in compliance with all debt covenants - Long-term debt, including current portion, was $7.2 billion as of June 30, 2025, down from $7.5 billion at December 31, 2024[227] - The debt comprises US$3.8 billion in U.S. dollar-denominated unsecured notes and $2.0 billion in Canadian dollar-denominated unsecured notes[227] - Cenovus was in compliance with all debt agreements, maintaining a debt to capitalization ratio below 65%[228] Available Sources of Liquidity As of June 30, 2025, Cenovus had significant liquidity from cash reserves and undrawn credit facilities Available Sources of Liquidity ($ millions) | Source | Maturity | Amount Available | | :--- | :--- | :--- | | Cash and Cash Equivalents | n/a | 2,563 | | Committed Credit Facility | | | | Revolving Credit Facility – Tranche A | June 26, 2028 | 3,300 | | Revolving Credit Facility – Tranche B | June 26, 2027 | 2,200 | | Uncommitted Demand Facilities | | | | Cenovus Energy Inc. | n/a | 1,068 | | WRB | n/a | 51 | - No amounts were drawn on the committed credit facility as of June 30, 2025[229] - Uncommitted demand facilities include $1.7 billion, with $1.4 billion available for general purposes and $363 million in outstanding letters of credit[230] Base Shelf Prospectus Cenovus maintains a base shelf prospectus, expiring in December 2025, for flexible access to capital markets - Cenovus has a base shelf prospectus, expiring in December 2025, to offer debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts, and units[232] Financial Metrics Key financial ratios increased as of June 30, 2025, due to lower Operating Margin and higher Net Debt Financial Ratios | Metric | June 30, 2025 | December 31, 2024 | | :--- | :--- | :--- | | Net Debt to Adjusted EBITDA Ratio (times) | 0.6 | 0.5 | | Net Debt to Adjusted Funds Flow Ratio (times) | 0.7 | 0.6 | | Net Debt to Capitalization Ratio (percent) | 14 | 13 | - Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow ratios increased due to lower Operating Margin and higher Net Debt[236] - The Net Debt to Capitalization ratio increased primarily due to higher Net Debt[236] - Targets are approximately 1.0 times for Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow, and Net Debt at or below $4.0 billion over the long-term at a WTI price of US$45.00 per barrel[235] Share Capital and Stock-Based Compensation Plans As of June 30, 2025, Cenovus had approximately 1.8 billion common shares and 12.0 million preferred shares outstanding - As of June 30, 2025, approximately 1,805.9 million common shares and 12.0 million preferred shares were outstanding[238] - Cenovus redeemed all 8.0 million Series 5 preferred shares and 6.0 million Series 7 preferred shares for a total of $350 million[237] - An employee benefit plan trust purchased 3.6 million common shares for $73 million and distributed 3.8 million for $82 million in H1 2025[239] - Approximately 3.2 million Cenovus Warrants were outstanding, expiring on January 1, 2026, each entitling the holder to acquire one common share at $6.54[240] Common Share Dividends Cenovus paid $364 million in base dividends in Q2 2025 and declared a third-quarter dividend of $0.200 per share Common Share Base Dividends | Period | Amount ($ millions) | Per Common Share ($) | | :--- | :--- | :--- | | Q2 2025 | 364 | 0.200 | | Q2 2024 | 334 | 0.180 | | H1 2025 | 691 | 0.380 | | H1 2024 | 596 | 0.320 | - The Board declared a third-quarter base dividend of $0.200 per common share, payable on September 29, 2025[243] Cumulative Redeemable Preferred Share Dividends Cenovus paid $4 million in preferred share dividends in Q2 2025 and declared a third-quarter dividend of $2 million Preferred Share Dividends Declared and Paid ($ millions) | Period | 2025 | 2024 | | :--- | :--- | :--- | | Q2 | 4 | 9 | | H1 | 10 | 18 | - The Board declared a third-quarter dividend of $2 million on Series 1 and 2 preferred shares, payable on October 1, 2025[243] Share Repurchases Under its NCIB program, Cenovus repurchased 17.2 million common shares for $301 million in Q2 2025 Common Shares Purchased and Cancelled Under NCIB | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Common Shares Purchased (millions) | 17.2 | 15.4 | 20.2 | 22.8 | | Purchase Value ($ millions) | 301 | 440 | 363 | 605 | - From July 1 to July 28, 2025, an additional 6.6 million common shares were purchased for $129 million[246] - As of July 28, 2025, the company can purchase up to 99.6 million additional common shares under the NCIB program[246] Contractual Obligations and Commitments Total contractual commitments decreased to $26.3 billion, with the majority related to transportation and storage - Total commitments were $26.3 billion as of June 30, 2025, down from $27.3 billion at December 31, 2024[249] - Of the total, $23.3 billion are for various transportation and storage commitments, with terms up to 7 years[249] - Commitments include $1.8 billion with HMLP for long-term transportation and storage[249] - Outstanding letters of credit issued as security totaled $363 million[249] Legal Proceedings Cenovus is involved in a limited number of legal claims which are not expected to materially affect its financial statements - Cenovus is involved in a limited number of legal claims associated with normal operations[250] - The company believes any liabilities from these matters are not likely to have a material effect on its interim Consolidated Financial Statements[250] Transactions with Related Parties Cenovus holds a 35% interest in HMLP, engaging in service and usage transactions with the partnership - Cenovus holds a 35% interest in and operates HMLP, accounting for it using the equity method[251] Transactions with HMLP ($ millions) | Metric | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Revenues from Construction and Management Services | 37 | 38 | 66 | 69 | | Transportation Expenses | 69 | 71 | 137 | 140 | Risk Management and Risk Factors Cenovus is exposed to various inherent industry and operational risks that could adversely affect its business and financial condition - Cenovus is exposed to various risks, both industry-wide and unique to its operations, which could adversely affect its business, reputation, financial condition, and ability to meet strategic objectives[253] - For a full understanding of these risks, readers are directed to the Risk Management and Risk Factors section of the company's 2024 annual MD&A[252] Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies The application of accounting policies involves significant management judgment and estimates that can materially impact financial results - Management's application of accounting policies involves critical judgments and estimates that can significantly impact financial results, with actual results potentially differing materially[254] - Material accounting policies are reviewed annually by the Audit Committee, and a full list of critical judgments and estimation uncertainties is in the notes to the 2024 Consolidated Financial Statements[254][255] Control Environment Management assessed internal controls over financial reporting and disclosure as effective as of June 30, 2025 - Management concluded that both ICFR and DC&P were effective as of June 30, 2025, based on the COSO Framework[256] - Internal control systems have inherent limitations and can only provide reasonable assurance regarding financial statement preparation and presentation[257] Advisory Oil and Gas Information Natural gas volumes are converted to barrels of oil equivalent (BOE) based on energy equivalency, not value equivalency - Natural gas volumes are converted to BOE using a 6 Mcf to 1 bbl ratio[258] - The BOE conversion is based on energy equivalency at the burner tip and does not represent value equivalency at the wellhead, which can be misleading[258] Forward-looking Information This document contains forward-looking statements subject to risks and uncertainties, with actual results potentially differing materially - The document contains forward-looking information based on current expectations, estimates, and projections, identified by words like 'expect,' 'will,' 'plan,' and 'outlook'[259][260] - Actual results may differ materially due to various risk factors and uncertainties, including commodity price volatility, government policies, operational disruptions, geopolitical tensions, and market conditions[261][262][264][265] - Key assumptions for 2025 guidance include Brent prices of US$69.00/bbl, WTI of US$65.00/bbl, WCS of US$53.50/bbl, AECO natural gas of $2.00/Mcf, Chicago 3-2-1 crack spread of US$18.50/bbl, and an exchange rate of $0.72 US$/C$[263] - Cenovus disclaims any intention or obligation to publicly update or revise any forward-looking statements, except as required by applicable securities laws[266] Abbreviations and Definitions This section provides a list of abbreviations and definitions for key financial, operational, and industry terms used in the report - The section lists abbreviations and definitions for crude oil and NGLs (bbl, Mbbls/d, WCS, WTI), natural gas (Mcf, MMcf, MMcf/d, AECO, NYMEX), and other terms (BOE, MBOE/d, DD&A, ESG, GHG, FPSO, NCIB, OPEC, OPEC+, USGC)[269] Specified Financial Measures Non-GAAP Financial Measures and Non-GAAP Ratios This section defines and reconciles non-GAAP measures used to provide additional insights into the company's performance and liquidity - Cenovus uses non-GAAP financial measures like Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow, Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin, and Adjusted Market Capture to provide additional insights into financial performance and liquidity[270][271] - These measures are not standardized under IFRS and may not be comparable to those presented by other issuers[270][271] Operating Margin Operating Margin is a non-GAAP measure used to assess the cash-generating performance of operations and assets - Operating Margin is a non-GAAP financial measure used to consistently measure the cash-generating performance of operations and assets[272] - It is defined as revenues less purchased product, transportation and blending expenses, operating expenses, plus realized gains less realized losses on risk management activities, excluding items from the Corporate and Eliminations segment[272] Operating Margin Reconciliation (Q2 2025 vs Q2 2024) | ($ millions) | Q2 2025 Upstream | Q2 2024 Upstream | Q2 2025 Downstream | Q2 2024 Downstream | Q2 2025 Total | Q2 2024 Total | | :--- | :--- | :--- | :--- | :--- | :--- | :--- | | Revenues | 6,773 | 7,856 | 7,743 | 8,750 | 14,516 | 16,606 | | Purchased Product | 1,111 | 815 | 6,878 | 7,796 | 7,989 | 8,611 | | Transportation and Blending | 2,621 | 3,043 | — | — | 2,621 | 3,043 | | Operating | 896 | 889 | 947 | 1,099 | 1,843 | 1,988 | | Realized (Gain) Loss on Risk Management | 8 | 20 | (11) | 8 | (3) | 28 | | Operating Margin | 2,137 | 3,089 | (71) | (153) | 2,066 | 2,936 | Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow These non-GAAP measures assess the ability to finance capital programs, meet obligations, and return capital to shareholders - Adjusted Funds Flow is a non-GAAP measure for financing capital programs and meeting financial obligations, defined as cash from operating activities, excluding settlement of decommissioning liabilities and net change in operating non-cash working capital[279] - Free Funds Flow is Adjusted Funds Flow minus capital investment, measuring available funds after capital programs[280] - Excess Free Funds Flow is used for shareholder returns and capital allocation, defined as Free Funds Flow minus base dividends, preferred dividends, employee benefit plan share purchases, decommissioning liabilities, lease repayments, and net acquisitions, plus divestiture proceeds[281] Funds Flow Reconciliation (Q2 2025 vs Q2 2024) | ($ millions) | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Cash From (Used in) Operating Activities | 2,374 | 2,807 | 3,689 | 4,732 | | Settlement of Decommissioning Liabilities | (68) | (48) | (104) | (96) | | Net Change in Non-Cash Working Capital | 923 | 494 | 62 | 225 | | Adjusted Funds Flow | 1,519 | 2,361 | 3,731 | 4,603 | | Capital Investment | 1,164 | 1,155 | 2,393 | 2,191 | | Free Funds Flow | 355 | 1,206 | 1,338 | 2,412 | | Base Dividends Paid on Common Shares | (364) | (334) | (691) | (596) | | Dividends Paid on Preferred Shares | (4) | (9) | (10) | (18) | | Purchase of Common Shares Under Employee Benefit Plan | (15) | — | (73) | — | | Settlement of Decommissioning Liabilities | (68) | (48) | (104) | (96) | | Principal Repayment of Leases | (94) | (75) | (177) | (145) | | Acquisitions, Net of Cash Acquired | (129) | (5) | (229) | (15) | | Proceeds From Divestitures | 13 | — | 13 | 25 | | Excess Free Funds Flow | (306) | 735 | 67 | 1,567 | Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture These non-GAAP measures evaluate downstream performance, with adjustments made to exclude inventory holding impacts for better comparability - Gross Margin and Adjusted Gross Margin are non-GAAP measures for downstream performance, with Adjusted Gross Margin excluding inventory holding gains/losses[282] - Adjusted Refining Margin is Adjusted Gross Margin divided by total processed inputs, and Adjusted Market Capture is Adjusted Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs[285] - Definitions for Refining Margin and Market Capture were updated as of March 31, 2025, to exclude inventory holding impacts for improved comparability and accuracy[286] U.S. Refining Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture (Q2 2025 vs Q2 2024) | ($ millions, except where indicated) | Q2 2025 | Q2 2024 | H1 2025 | H1 2024 | | :--- | :--- | :--- | :--- | :--- | | Gross Margin | 617 | 794 | 1,034 | 1,897 | | Inventory Holding (Gain) Loss | 62 | (83) | 85 | (277) | | Adjusted Gross Margin | 679 | 711 | 1,119 | 1,620 | | Total Processed Inputs (Mbbls/d) | 594.2 | 594.0 | 587.6 | 584.5 | | Adjusted Refining Margin ($/bbl) | 12.57 | 13.15 | 10.53 | 15.23 | | Weighted Average Crack Spread, Net of RINs ($/bbl) | 21.86 | 20.86 | 17.79 | 19.72 | | Adjusted Market Capture (percent) | 58 | 63 | 59 | 77 | Netback Reconciliations and Realized Sales Price Netback and Realized Sales Price are non-GAAP measures used to evaluate upstream operating performance and pricing - Netback is a non-GAAP measure for operating performance, defined as gross sales less royalties, transportation and blending, and operating expenses[302] - Realized Sales Price is a non-GAAP measure that includes gross sales, purchased diluent costs, and profits from optimization activities[303] - Conventional Netback was modified to include Cenovus's 30% equity interest in the Duvernay joint venture, and Offshore/Asia Pacific operating expenses reflect the 40% equity interest in the HCML joint venture[303] Oil Sands Netback Reconciliation (Q2 2025, Total Oil Sands) | ($ millions) | Basis of Netback Calculation | Adjustments (Condensate) | Adjustments (Third-party Sourced) | Adjustments (Other) | Total Oil Sands (from Interim Consolidated Financial Statements) | | :--- | :--- | :--- | :--- | :--- | :--- | | Gross Sales | 3,646 | 1,989 | 769 | 106 | 6,510 | | Royalties | (589) | — | — | — | (589) | | Revenues | 3,057 | 1,989 | 769 | 106 | 5,921 | | Expenses: Purchased Product | — | — | 769 | 87 | 856 | | Expenses: Transportation and Blending | 526 | 1,989 | — | 20 | 2,535 | | Expenses: Operating | 701 | — | — | (1) | 700 | | Netback | 1,830 | — | — | — | 1,830 | | Realized (Gain) Loss on Risk Management | 8 | — | — | — | 8 | | Operating Margin | 1,822 | — | — | — | 1,822 | Other Specified Financial Measures This section defines additional per-unit metrics for operating expenses, transportation expenses, and depreciation, depletion, and amortization - Per-Unit Operating Expenses are defined as total operating expenses divided by sales volumes (upstream) or total processed inputs (downstream)[336][337] - Per-Unit Transportation Expenses are total transportation expenses divided by sales volumes in upstream segments[338] - Per-Unit Depreciation, Depletion and Amortization (DD&A) is the sum of upstream depletion and associated decommissioning costs, divided by sales volumes[339] Prior Period Revisions Prior period U.S. Refining results were revised to correct the reporting of certain transactions from a gross to a net basis - Certain U.S. Refining segment transactions were previously reported on a gross basis instead of a net basis, overstating revenues and purchased product for the nine months ended September 30, 2024[340] - Prior periods were revised to reflect this change, with no impact on net earnings (loss), segment income (loss), cash flows, or financial position[340] U.S. Refining Segment Revisions (Q2 2024) | Metric | Previously Reported ($ millions) | Revisions ($ millions) | Revised Balance ($ millions) | | :--- | :--- | :--- | :--- | | Revenues | 7,918 | (303) | 7,615 | | Purchased Product | 7,124 | (303) | 6,821 |