6-K
CENOVUS ENERGY INC. (CVE)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16
under the Securities Exchange Act of 1934
For May 2025
Commission File Number: 1-34513
CENOVUS ENERGY INC.
(Translation of registrant’s name into English)
4100, 225 6 Avenue S.W.
Calgary, Alberta, Canada T2P 1N2
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐
DOCUMENTS FILED AS PART OF THIS FORM 6-K
See the Exhibit Index to this Form 6-K.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: May 8, 2025
| CENOVUS ENERGY INC. | ||
|---|---|---|
| (Registrant) | ||
| By: | /s/ Christine D. Lee | |
| --- | --- | --- |
| Name: | Christine D. Lee | |
| Title: | Assistant Corporate Secretary |
Form 6-K Exhibit Index
| Exhibit No. | |
|---|---|
| 99.1 | News Release dated May 8, 2025 |
| 99.2 | Management’s Discussion and Analysis dated May 7, 2025 for the period ended March 31, 2025 |
| 99.3 | Interim Consolidated Financial Statements (unaudited) for the period ended March 31, 2025 |
| 99.4 | Form 52-109F2 Full Certificate, dated May 8, 2025, of Jonathan M. McKenzie, President & Chief Executive Officer |
| 99.5 | Form 52-109F2 Full Certificate, dated May 8, 2025, of Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer |
Document
| Exhibit 99.1 | |
|---|---|
| News release |  |
Cenovus announces first-quarter 2025 results
Calgary, Alberta (May 8, 2025) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) today announced its first-quarter 2025 financial and operating results. The company generated more than $1.3 billion in cash from operating activities, $2.2 billion of adjusted funds flow and $983 million of free funds flow. Operating results in the quarter were strong, with Upstream production increasing to 818,900 barrels of oil equivalent per day (BOE/d)1 while Downstream crude throughput was 665,400 barrels per day (bbls/d), representing an overall utilization rate of 92%.
The Board of Directors has approved an 11% increase in the base dividend to $0.80 per share annually, beginning in the second quarter of 2025. Consistent with Cenovus’s financial framework, the base dividend is underpinned by our growth plan and resilience at a US$45 WTI oil price.
Highlights
•Upstream production of 818,900 BOE/d, maintaining near-record performance and exceeding the previous quarter.
•Continued momentum in Downstream performance, including record utilization of 104% in Canadian Refining, with 90% utilization and adjusted market capture2,3 of 62% in U.S. Refining.
•Returned $595 million to shareholders, including $62 million through share purchases, $333 million through common and preferred share dividends, and $200 million through the redemption of Cenovus’s Series 5 preferred shares on March 31, 2025. The company subsequently purchased 10.9 million common shares for $178 million between April 1 and May 5, 2025.
•Progressed all Upstream growth projects as planned, including introduction of steam to the first two well pads at Narrows Lake with first oil expected early in the third quarter, as well as completing preparations for tow-out of the concrete gravity structure (CGS) and the topsides for the West White Rose project.
“We delivered strong operational performance across our integrated portfolio, while significantly progressing our major growth projects toward completion,” said Jon McKenzie, Cenovus President & Chief Executive Officer. “Combined with our commitment to financial discipline and cost control, we are well positioned to effectively navigate market volatility and continue to grow shareholder returns.”
Financial summary
| ($ millions, except per share amounts) | 2025 Q1 | 2024 Q4 | 2024 Q1 |
|---|---|---|---|
| Cash from (used in) operating activities | 1,315 | 2,029 | 1,925 |
| Adjusted funds flow2 | 2,212 | 1,601 | 2,242 |
| Per share (diluted)2 | 1.21 | 0.87 | 1.19 |
| Capital investment | 1,229 | 1,478 | 1,036 |
| Free funds flow2 | 983 | 123 | 1,206 |
| Excess free funds flow2 | 373 | (416) | 832 |
| Net earnings (loss) | 859 | 146 | 1,176 |
| Per share (diluted) | 0.47 | 0.07 | 0.62 |
| Long-term debt, including current portion | 7,524 | 7,534 | 7,227 |
| Net debt | 5,079 | 4,614 | 4,827 |
CENOVUS ENERGY NEWS RELEASE | 1
Production and throughput
| (before royalties, net to Cenovus) | 2025 Q1 | 2024 Q4 | 2024 Q1 |
|---|---|---|---|
| Oil and NGLs (bbls/d)1 | 670,900 | 670,600 | 658,200 |
| Conventional natural gas (MMcf/d) | 887.9 | 873.3 | 855.8 |
| Total upstream production (BOE/d)1 | 818,900 | 816,000 | 800,900 |
| Total downstream crude throughput (bbls/d) | 665,400 | 666,700 | 655,200 |
1 See Advisory for production by product type.
2 Non-GAAP financial measure or contains a non-GAAP financial measure. See Advisory.
3 Adjusted Market Capture excludes the impact of inventory holding gains or losses. See Advisory for more details.
First-quarter results
Operating1
Cenovus’s total revenues were $13.3 billion in the first quarter, up from $12.8 billion in the fourth quarter of 2024, primarily due to rising commodity prices. Upstream revenues were $8.3 billion, an increase from $7.3 billion in the previous quarter, while Downstream revenues were $7.7 billion compared with $7.8 billion in the prior quarter.
Total operating margin4 was $2.8 billion, compared with $2.3 billion in the previous quarter. Upstream operating margin5 was $3.0 billion, an increase from $2.7 billion in the fourth quarter due to higher benchmark oil prices and favourable timing differences between production and sales. The company had a Downstream operating margin5 shortfall of $237 million compared with a shortfall of $396 million in the previous quarter, as adjusted market capture6 in U.S. Refining improved to 62%. Operating margin in the U.S. Refining segment included a $23 million inventory holding loss and $81 million of turnaround expenses.
Total Upstream production was 818,900 BOE/d in the first quarter, up from 816,000 BOE/d in the fourth quarter. Christina Lake production was 237,800 bbls/d, compared with 251,400 bbls/d in the prior quarter, having benefited from higher production rates following its fall turnaround. Foster Creek production was 202,700 bbls/d compared with 195,200 bbls/d in the fourth quarter, reflecting a successful well optimization program and two new sustaining well pads being brought online. Sunrise production was 52,100 bbls/d compared with 53,100 bbls/d in the fourth quarter. Production from the Lloydminster thermal assets increased to 109,900 bbls/d from 108,900 bbls/d in the prior quarter, while Lloydminster conventional heavy oil output rose to 21,800 bbls/d from 18,000 bbls/d in the fourth quarter. Production in the Conventional segment was 123,900 BOE/d, up from 117,800 BOE/d in the previous quarter.
In the Offshore segment, production was 68,800 BOE/d compared with 69,700 BOE/d in the fourth quarter. In Asia Pacific, production volumes were 57,200 BOE/d, lower than 62,200 BOE/d in the previous quarter, primarily due to timing of condensate lifting in Indonesia in the first quarter. In the Atlantic region, production was 11,600 bbls/d, an increase from 7,500 bbls/d in the prior quarter, due to increased output at the partner-operated Terra Nova field and the return to operations of the SeaRose floating production, storage and offloading (FPSO) vessel in the White Rose field.
Total Downstream crude throughput in the first quarter was 665,400 bbls/d, in line with fourth quarter throughput of 666,700 bbls/d. Crude throughput in Canadian Refining was 111,900 bbls/d, representing a record utilization rate of 104%, compared with 104,400 bbls/d in the previous quarter.
In U.S. Refining, crude throughput was 553,500 bbls/d, representing a utilization rate of 90%, compared with 562,300 bbls/d in the fourth quarter. U.S. Refining revenues were $6.4 billion, slightly lower than
CENOVUS ENERGY NEWS RELEASE | 2
$6.6 billion in the previous quarter. Adjusted market capture6 in the U.S. was 62%, compared with 52% in the fourth quarter, benefiting from improved process unit reliability and the return of the Lima Refinery to full operations following a turnaround completed in the fourth quarter of 2024, while continuing to be impacted by a narrow heavy oil price differential.
4Non-GAAP financial measure. Total operating margin is the total of Upstream operating margin plus Downstream operating margin. See Advisory.
5Specified financial measure. See Advisory.
6 Contains a non-GAAP financial measure. See Advisory.
Financial
Cash from operating activities in the first quarter was $1.3 billion, compared with $2.0 billion in the fourth quarter. Adjusted funds flow was $2.2 billion, compared with $1.6 billion in the prior quarter, and excess free funds flow (EFFF) was $373 million, compared with a shortfall of $416 million in the fourth quarter. Net earnings in the first quarter were $859 million, compared with $146 million in the previous quarter. First-quarter financial results improved in part due to higher benchmark prices, higher Upstream sales volumes and improved Downstream market capture relative to the fourth quarter.
Long-term debt, including the current portion, was $7.5 billion as at March 31, 2025. Net debt increased from December 31, 2024 to $5.1 billion as at March 31, 2025, as free funds flow of $983 million was more than offset by returns to shareholders of $595 million, including the redemption of $200 million of Cenovus’s Series 5 preferred shares on March 31, 2025, and a $861 million build of non-cash working capital. The company continues to steward toward net debt of $4.0 billion and returning 100% of EFFF to shareholders over time in accordance with its financial framework.
In the first quarter of 2025, the company received a rating upgrade from Moody’s to Baa1 with a stable outlook. Cenovus remains committed to maintaining its investment grade credit ratings at S&P Global Ratings, Moody’s, Morningstar DBRS and Fitch Ratings.
Growth projects
In the Oil Sands segment, steaming of the first two well pads in the Narrows Lake field began in late April. The project remains on track for first oil early in the third quarter of 2025, as planned. At Sunrise, one well pad was brought online in April as the company continues to progress the facility’s growth plan to access higher-quality resource and fully utilize the asset’s steam capacity. The optimization project at Foster Creek is now approximately 75% complete and remains on schedule for startup in 2026. Preparations are being made to complete critical project tie-ins during the Foster Creek turnaround in the second quarter of 2025.
The West White Rose project continues to progress toward installation and commissioning of the offshore platform later this year. Preparations are underway to tow the CGS to its field location in the second quarter, where it will be mated with the topsides in the third quarter. The West White Rose project is now approximately 90% complete and remains on-schedule for first oil in the second quarter of 2026.
“These oil sands growth projects access some of the best resources in our portfolio,” McKenzie said. “At both Narrows Lake and Sunrise, we’re moving into new higher-quality development areas, which will drive lower steam-to-oil ratios and increased production without adding any new steam capacity and at a low capital cost. Once the West White Rose project is operating, we’ll be adding around 45,000 bbls/d of light sweet oil production tied to global pricing, generating significant free cash flow.”
Dividend declarations and share purchases
CENOVUS ENERGY NEWS RELEASE | 3
The Board of Directors has declared a quarterly base dividend of $0.20 per common share, payable on June 30, 2025, to shareholders of record as of June 13, 2025.
In addition, the Board has declared a quarterly dividend on each of the Cumulative Redeemable First Preferred Shares – Series 1, Series 2 and Series 7 – payable on June 30, 2025, to shareholders of record as of June 13, 2025, as follows:
Preferred shares dividend summary
| Share series | Rate (%) | Amount ($/share) |
|---|---|---|
| Series 1 | 2.577 | 0.16106 |
| Series 2 | 4.568 | 0.28472 |
| Series 7 | 3.935 | 0.24594 |
All dividends paid on Cenovus’s common and preferred shares will be designated as “eligible dividends” for Canadian federal income tax purposes. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis.
In the first quarter, the company returned $595 million to shareholders, composed of $62 million from its purchase of 3 million shares through its normal course issuer bid (NCIB), $333 million through common and preferred share dividends and $200 million through the redemption of Cenovus’s Series 5 preferred shares. Subsequent to the quarter, the company purchased 10.9 million common shares through May 5, 2025 for $178 million.
2025 planned maintenance
The following table provides details on planned maintenance activities at Cenovus assets in 2025 and anticipated production or throughput impacts.
Potential quarterly production/throughput impact (Mbbls/d or MBOE/d)
| (MBOE/d or Mbbls/d) | Q2 | Q3 | Q4 | Annualized impact |
|---|---|---|---|---|
| Upstream | ||||
| Oil Sands | 30 - 40 | 5 - 7 | - | 10 - 12 |
| Offshore | - | 4 - 6 | - | 1 - 2 |
| Conventional | - | - | - | - |
| Downstream | ||||
| Canadian Refining | - | - | - | - |
| U.S. Refining | 35 - 45 | 2 - 4 | 6 - 10 | 13 - 17 |
Potential turnaround expenses
| ($ millions) | Q2 | Q3 | Q4 | Annualized impact |
|---|---|---|---|---|
| Downstream | ||||
| Canadian Refining | - | - | - | - |
| U.S. Refining | 240 - 295 | 80 - 95 | 40 - 50 | 440 - 520 |
CENOVUS ENERGY NEWS RELEASE | 4
Conference call today
Cenovus will host a conference call today, May 8, 2025, starting at 9 a.m. MT (11 a.m. ET).
For analysts wanting to join the call, please register in advance at Conference call registration.
To participate in the live conference call, you must complete the online registration form in advance of the conference call start time. Register ahead of time to receive a unique PIN to access the conference call via telephone. Once registered, participants can dial into the conference call from their telephone via the unique PIN or click on the "Call Me" option to receive an automated call directly on their telephone.
An audio webcast will also be available and archived for approximately 30 days.
Cenovus will also host its Annual Meeting of Shareholders today, May 8, 2025, in a virtual format beginning at 1 p.m. MT (3 p.m. ET). The webcast link to the Shareholders Meeting is available under Shareholder information in the Investors section of cenovus.com.
Advisory
Basis of Presentation
Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS) Accounting Standards.
Barrels of Oil Equivalent
Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Product types
| Product type by operating segment | Three months ended<br>March 31, 2025 |
|---|---|
| Oil Sands | |
| Bitumen (Mbbls/d) | 602.5 |
| Heavy crude oil (Mbbls/d) | 21.8 |
| Conventional natural gas (MMcf/d) | 11.4 |
| Total Oil Sands segment production (MBOE/d) | 626.2 |
| Conventional | |
| Light crude oil (Mbbls/d) | 5.2 |
| Natural gas liquids (Mbbls/d) | 20.5 |
| Conventional natural gas (MMcf/d) | 589.3 |
CENOVUS ENERGY NEWS RELEASE | 5
| Total Conventional segment production (MBOE/d) | 123.9 |
|---|---|
| Offshore | |
| Light crude oil (Mbbls/d) | 11.6 |
| Natural gas liquids (Mbbls/d) | 9.3 |
| Conventional natural gas (MMcf/d) | 287.2 |
| Total Offshore segment production (MBOE/d) | 68.8 |
| Total Upstream production (MBOE/d) | 818.9 |
Forward‐looking Information
This news release contains certain forward‐looking statements and forward‐looking information (collectively referred to as “forward‐looking information”) within the meaning of applicable securities legislation about Cenovus’s current expectations, estimates and projections about the future of the company, based on certain assumptions made in light of the company’s experiences and perceptions of historical trends. Although Cenovus believes that the expectations represented by such forward‐looking information are reasonable, there can be no assurance that such expectations will prove to be correct.
Forward‐looking information in this document is identified by words such as “anticipate”, “continue”, “deliver”, “drive”, “plan”, “position”, “progress”, “steward”, and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: Net Debt; returning Excess Free Funds Flow to shareholders; navigating market volatility and growing shareholder returns; financial discipline and cost control; growth plans and projects; delivering long-term shareholder value; production guidance; the optimization project and turnaround at Foster Creek; timing of first oil at Narrows Lake; timing of well pads and first oil at Sunrise; the installation and commissioning of, and timing of first oil from, the West White Rose project; free cash flow; 2025 planned maintenance; and dividend payments.
Developing forward‐looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward‐looking information in this news release are based include, but are not limited to: the allocation of free funds flow; commodity prices, inflation and supply chain constraints; Cenovus’s ability to produce on an unconstrained basis; Cenovus’s ability to access sufficient insurance coverage to pursue development plans; Cenovus’s ability to deliver safe and reliable operations and demonstrate strong governance; and the assumptions inherent in Cenovus’s 2025 corporate guidance available on cenovus.com.
The risk factors and uncertainties that could cause actual results to differ materially from the forward‐looking information in this news release include, but are not limited to: the accuracy of estimates regarding commodity production and operating expenses, inflation, taxes, royalties, capital costs and currency and interest rates; risks inherent in the operation of Cenovus’s business; and risks associated with climate change and Cenovus’s assumptions relating thereto and other risks identified under “Risk Management and Risk Factors” and “Advisory” in Cenovus’s Management’s Discussion and Analysis (MD&A) for the year ended December 31, 2024.
Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward‐looking information. For additional information regarding Cenovus’s material risk factors, the assumptions made, and risks and uncertainties which could cause actual results to differ from the anticipated results, refer to “Risk Management and Risk Factors” and “Advisory” in Cenovus’s MD&A for the periods ended December 31,
CENOVUS ENERGY NEWS RELEASE | 6
2024 and March 31, 2025 and to the risk factors, assumptions and uncertainties described in other documents Cenovus files from time to time with securities regulatory authorities in Canada (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and Cenovus’s website at cenovus.com).
Specified Financial Measures
This news release contains references to certain specified financial measures that do not have standardized meanings prescribed by IFRS Accounting Standards. Readers should not consider these measures in isolation or as a substitute for analysis of the company’s results as reported under IFRS Accounting Standards. These measures are defined differently by different companies and, therefore, might not be comparable to similar measures presented by other issuers. For information on the composition of these measures, as well as an explanation of how the company uses these measures, refer to the Specified Financial Measures Advisory located in Cenovus’s MD&A for the period ended March 31, 2025 (available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on Cenovus's website at cenovus.com) which is incorporated by reference into this news release.
Upstream Operating Margin and Downstream Operating Margin
Upstream Operating Margin and Downstream Operating Margin, and the individual components thereof, are included in Note 1 to the interim Consolidated Financial Statements.
Total Operating Margin
Total Operating Margin is the total of Upstream Operating Margin plus Downstream Operating Margin.
| Upstream (7) | Downstream (7) | Total | |||||||
|---|---|---|---|---|---|---|---|---|---|
| ($ millions) | Q1 2025 | Q4 2024 | Q1 2024 | Q1 2025 | Q4 2024 | Q1 2024 | Q1 2025 | Q4 2024 | Q1 2024 |
| Revenues | |||||||||
| Gross Sales | 9,252 | 8,240 | 7,864 | 7,705 | 7,837 | 8,233 | 16,957 | 16,077 | 16,097 |
| Less: Royalties | (906) | (914) | (747) | — | — | — | (906) | (914) | (747) |
| 8,346 | 7,326 | 7,117 | 7,705 | 7,837 | 8,233 | 16,051 | 15,163 | 15,350 | |
| Expenses | |||||||||
| Purchased Product | 1,167 | 1,000 | 771 | 7,082 | 7,364 | 6,885 | 8,249 | 8,364 | 7,656 |
| Transportation and Blending | 3,247 | 2,816 | 2,811 | — | — | — | 3,247 | 2,816 | 2,811 |
| Operating | 893 | 842 | 898 | 854 | 866 | 787 | 1,747 | 1,708 | 1,685 |
| Realized (Gain) Loss on Risk Management | (9) | (2) | 6 | 6 | 3 | 1 | (3) | 1 | 7 |
| Operating Margin | 3,048 | 2,670 | 2,631 | (237) | (396) | 560 | 2,811 | 2,274 | 3,191 |
7Found in the March 31, 2025, or the December 31, 2024, interim Consolidated Financial Statements. Revenues and purchased product for Q1 2024 Downstream operations were revised. See Note 21 of our March 31, 2025, interim Consolidated Financial Statements.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
The following table provides a reconciliation of cash from (used in) operating activities found in Cenovus’s Consolidated Financial Statements to Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow. Adjusted Funds Flow per Share – Basic and Adjusted Funds Flow per Share – Diluted are calculated by dividing Adjusted Funds Flow by the respective basic or diluted weighted average number of common shares outstanding during the period and may be useful to evaluate a company’s ability to generate cash.
CENOVUS ENERGY NEWS RELEASE | 7
| Three Months Ended | |||
|---|---|---|---|
| ($ millions) | March 31, 2025 | December 31, 2024 | March 31, 2024 |
| Cash From (Used in) Operating Activities (8) | 1,315 | 2,029 | 1,925 |
| (Add) Deduct: | |||
| Settlement of Decommissioning Liabilities | (36) | (64) | (48) |
| Net Change in Non-Cash Working Capital | (861) | 492 | (269) |
| Adjusted Funds Flow | 2,212 | 1,601 | 2,242 |
| Capital Investment | 1,229 | 1,478 | 1,036 |
| Free Funds Flow | 983 | 123 | 1,206 |
| Add (Deduct): | |||
| Base Dividends Paid on Common Shares | (327) | (330) | (262) |
| Purchase of Common Shares under Employee Benefit Plan | (58) | (43) | — |
| Dividends Paid on Preferred Shares | (6) | (18) | (9) |
| Settlement of Decommissioning Liabilities | (36) | (64) | (48) |
| Principal Repayment of Leases | (83) | (80) | (70) |
| Acquisitions, Net of Cash Acquired | (100) | (3) | (10) |
| Proceeds From Divestitures | — | (1) | 25 |
| Excess Free Funds Flow | 373 | (416) | 832 |
8 Found in the March 31, 2025, or the December 31, 2024, interim Consolidated Financial Statements.
Adjusted Market Capture
Adjusted market capture contains a non-GAAP financial measure and is used in the company’s U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. Cenovus defines adjusted market capture as refining margin, net of holding gains and losses, divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.
The company previously disclosed market capture which did not exclude the effect of inventory holding gains or losses. Cenovus replaced market capture with adjusted market capture to exclude the impact of inventory holding gains or losses. The company believes this metric provides more comparability and accuracy when measuring the cash generating performance of our downstream operations. Comparative periods were revised to conform with our current presentation.
CENOVUS ENERGY NEWS RELEASE | 8
| ($ millions) | Three months ended<br>March 31, 2025 | Three months ended<br><br>December 31, 2024 |
|---|---|---|
| Revenues (9) | 6,423 | 6,574 |
| Purchased Product (9) | 6,006 | 6,296 |
| Gross Margin | 417 | 278 |
| Inventory Holding (Gain) Loss | 23 | 45 |
| Adjusted Gross Margin | 440 | 323 |
| Total Processed Inputs (Mbbls/d) | 581.0 | 588.4 |
| Adjusted Gross Margin ($/bbl) | 8.41 | 5.98 |
| Operable Capacity (Mbbls/d) | 612.3 | 612.3 |
| Operable Capacity by Regional Benchmark (percent) | ||
| Chicago 3-2-1 Crack Spread Weighting | 81 | 81 |
| Group 3 3-2-1 Crack Spread Weighting | 19 | 19 |
| Benchmark Prices and Exchange Rate | ||
| Chicago 3-2-1 Crack Spread (US$/bbl) | 13.68 | 12.12 |
| Group 3 3-2-1 Crack Spread (US$/bbl) | 16.48 | 12.66 |
| RINs (US$/bbl) | 4.76 | 4.02 |
| US$ per C$1 - Average | 0.697 | 0.715 |
| Weighted Average Crack Spread, Net of RINs ($/bbl) | 13.58 | 11.47 |
| Adjusted Market Capture (percent) | 62 | 52 |
9 Found in Note 1 of the March 31, 2025, or the December 31, 2024, interim Consolidated Financial Statements.
Cenovus Energy Inc.
Cenovus Energy Inc. is an integrated energy company with oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States. The company is committed to maximizing value by developing its assets in a safe, responsible and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Cenovus common shares and warrants are listed on the Toronto and New York stock exchanges, and the company’s preferred shares are listed on the Toronto Stock Exchange. For more information, visit cenovus.com.
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Cenovus contacts
Investors
Investor Relations general line
403-766-7711
Media
Media Relations general line
403-766-7751
CENOVUS ENERGY NEWS RELEASE | 9
Document
Exhibit 99.2
Cenovus Energy Inc.
Management’s Discussion and Analysis (unaudited)
For the Period Ended March 31, 2025
(Canadian Dollars)
MANAGEMENT’S DISCUSSION AND ANALYSIS
| For the period ended March 31, 2025 | |
|---|---|
| TABLE OF CONTENTS | |
| --- | |
| OVERVIEW OF CENOVUS | 3 |
| --- | --- |
| QUARTERLY RESULTS OVERVIEW | 4 |
| OPERATING AND FINANCIAL RESULTS | 6 |
| COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS | 10 |
| OUTLOOK | 14 |
| REPORTABLE SEGMENTS | 16 |
| UPSTREAM | 16 |
| OIL SANDS | 16 |
| CONVENTIONAL | 20 |
| OFFSHORE | 22 |
| DOWNSTREAM | 25 |
| CANADIAN REFINING | 25 |
| U.S. REFINING | 27 |
| CORPORATE AND ELIMINATIONS | 29 |
| LIQUIDITY AND CAPITAL RESOURCES | 30 |
| RISK MANAGEMENT AND RISK FACTORS | 34 |
| CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES | 35 |
| CONTROL ENVIRONMENT | 35 |
| ADVISORY | 35 |
| ABBREVIATIONS AND DEFINITIONS | 38 |
| SPECIFIED FINANCIAL MEASURES | 39 |
| PRIOR PERIOD REVISIONS | 49 |
This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated May 7, 2025, should be read in conjunction with our March 31, 2025 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2024 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2024 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as at May 7, 2025, unless otherwise indicated. This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (“the Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on May 7, 2025. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, do not constitute part of this MD&A.
Basis of Presentation
This MD&A and the interim Consolidated Financial Statements were prepared in Canadian dollars (which includes references to “dollar” or “$”), except where another currency is indicated, and in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”). Production volumes are presented on a before royalties basis. Refer to the Abbreviations and Definitions section for commonly used oil and gas terms.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 2 |
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| OVERVIEW OF CENOVUS | |
| --- |
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian-based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”).
Our upstream operations include oil sands projects in northern Alberta; thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada; crude oil production offshore Newfoundland and Labrador; and natural gas and NGLs production offshore China and Indonesia. Our downstream operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada.
Our operations involve activities across the full value chain to develop, produce, refine, transport and market crude oil, natural gas and refined petroleum products in Canada and internationally. Our physically and economically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil price differentials and contribute to our net earnings by capturing value from crude oil, natural gas and NGLs production through to the sale of finished products such as transportation fuels.
Our Strategy
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include: delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and absolute and per share free funds flow growth.
On December 12, 2024, we released our 2025 corporate guidance which focused on disciplined capital allocation in support of increasing shareholder returns over time. We will continue to be focused on controlling costs, improving the profitability of our strategic downstream business and optimizing our advantaged portfolio to deliver value for our shareholders. For further details, see our 2025 corporate guidance dated December 11, 2024, available on our website at cenovus.com.
Our Operations
The Company operates through the following reportable segments:
Upstream Segments
•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.
•Conventional, includes assets rich in NGLs and natural gas in Alberta and British Columbia in the Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth and Wapiti. The segment also includes interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.
•Offshore, includes offshore operations, exploration and development activities in the east coast of Canada and the Asia Pacific region, representing China and the equity-accounted investment in Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for, and production of, NGLs and natural gas in offshore Indonesia.
Downstream Segments
•Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.
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•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.
Corporate and Eliminations
Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
| QUARTERLY RESULTS OVERVIEW |
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During the first quarter of 2025, we saw strong operational performance across our upstream assets and improved operational performance in our downstream operations. Crude oil benchmark prices, market crack spreads and economic markets were volatile in the quarter due to uncertainty around a rapidly changing tariff environment and anticipation of increasing global crude oil supply, which impacted our financial results.
•Delivered safe and reliable operations. We delivered safe operations across our business, and we continue to strive to improve our safety record. Safety continues to be our top priority.
•Maintained strong upstream production. Upstream production was 818.9 thousand barrels of oil equivalent per day, compared with 816.0 thousand barrels of oil equivalent per day in the fourth quarter of 2024. Production increased due to strong results from our optimization programs and new sustaining well pads brought online in the quarter at Foster Creek. In the Conventional segment, production increased due to strong base performance and bringing on wells in 2025 that had been deferred in 2024 due to lower AECO pricing. The increases were offset by lower production at Christina Lake as our fourth quarter production benefited from positive post-turnaround impacts.
•Progressed key Oil Sands growth projects. The Narrows Lake tie-back to Christina Lake began steaming in April and is on track for first oil early in the third quarter, as planned. Construction of the Foster Creek optimization project is on track and on budget, and was approximately 75 percent complete as at March 31, 2025. At our Lloydminster conventional heavy oil assets, we progressed our drilling program and production continued to ramp up from new development wells coming online.
•Achieved Offshore milestones. The SeaRose floating production storage and offloading (“FPSO”) vessel resumed operations and production safely restarted at the White Rose field in the first quarter. The West White Rose project was approximately 90 percent complete as at March 31, 2025, and preparations are underway to tow the concrete gravity structure to the field in the second quarter, with the transport of the topsides expected to occur in the third quarter.
•Achieved record crude oil unit throughput at our Canadian Refining assets. The Lloydminster Upgrader (the “Upgrader”) and the Lloydminster Refinery ran at, or above, capacity during the quarter. Average crude oil unit throughput (or “throughput”) was 111.9 thousand barrels per day and crude unit utilization was 104 percent, compared with 104.4 thousand barrels per day and crude unit utilization of 97 percent in the fourth quarter of 2024.
•Building operational momentum in our U.S. Refining segment. Revenues from U.S. Refining decreased two percent to $6.4 billion; however, Adjusted Refining Margin(1) increased 41 percent to $8.41 per barrel and Adjusted Market Capture(1) increased to 62 percent from 52 percent in the fourth quarter of 2024, primarily due to improved process unit reliability at our operated refineries. We began turnarounds at both of our non-operated refineries in March and the Toledo Refinery turnaround began in April.
•Reported solid financial results. Adjusted Funds Flow increased to $2.2 billion from $1.6 billion in the fourth quarter of 2024, mainly due to increased sales volumes and higher realized pricing in our upstream operations. Cash from operating activities was $1.3 billion, down from $2.0 billion in the fourth quarter of 2024, mainly due to changes in non-cash working capital.
•Redemption of preferred shares. On March 31, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares at a price of $25.00 per share, for a total of $200 million.
•Credit rating upgrade. On March 31, 2025, we received a rating upgrade from Moody’s to Baa1 with a Stable outlook.
•Base dividend increase. On May 7, 2025, the Board declared a second quarter base dividend of $0.200 per common share, an increase of 11 percent from the first quarter dividend declared in February 2025.
(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Adjusted Refining Margin is the Gross Margin after adjusting for inventory holding gains or losses, on a per-barrel basis. Adjusted Market Capture is an indication of margin captured relative to what was available in the market based on widely-used benchmarks, after adjusting for inventory holding gains or losses.
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Summary of Quarterly Results
| 2024 | 2023 | |||||||
|---|---|---|---|---|---|---|---|---|
| ( millions, except where indicated) | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 |
| Upstream Production Volumes (1) (MBOE/d) | 818.9 | 816.0 | 771.3 | 800.8 | 800.9 | 808.6 | 797.0 | 729.9 |
| Downstream Total Processed Inputs (2) (3) (Mbbls/d) | 700.5 | 700.5 | 674.4 | 652.9 | 683.8 | 605.7 | 691.3 | 566.9 |
| Crude Oil Unit Throughput (2) (Mbbls/d) | 665.4 | 666.7 | 642.9 | 622.7 | 655.2 | 579.1 | 664.3 | 537.8 |
| Downstream Production Volumes (1) (2) (Mbbls/d) | 722.4 | 722.6 | 685.2 | 659.5 | 702.1 | 627.4 | 706.0 | 571.9 |
| Revenues (4) | 13,299 | 12,813 | 13,819 | 14,582 | 13,063 | 13,134 | 14,577 | 12,231 |
| Operating Margin (5) | 2,811 | 2,274 | 2,408 | 2,936 | 3,191 | 2,151 | 4,369 | 2,400 |
| Operating Margin – Upstream (6) | 3,048 | 2,670 | 2,731 | 3,089 | 2,631 | 2,455 | 3,447 | 2,257 |
| Operating Margin – Downstream (6) | (237) | (396) | (323) | (153) | 560 | (304) | 922 | 143 |
| Cash From (Used In) Operating Activities | 1,315 | 2,029 | 2,474 | 2,807 | 1,925 | 2,946 | 2,738 | 1,990 |
| Adjusted Funds Flow (5) | 2,212 | 1,601 | 1,960 | 2,361 | 2,242 | 2,062 | 3,447 | 1,899 |
| Per Share – Basic (5) () | 1.21 | 0.88 | 1.06 | 1.27 | 1.20 | 1.10 | 1.82 | 1.00 |
| Per Share – Diluted (5) () | 1.21 | 0.87 | 1.05 | 1.26 | 1.19 | 1.08 | 1.81 | 0.98 |
| Capital Investment | 1,229 | 1,478 | 1,346 | 1,155 | 1,036 | 1,170 | 1,025 | 1,002 |
| Free Funds Flow (5) | 983 | 123 | 614 | 1,206 | 1,206 | 892 | 2,422 | 897 |
| Excess Free Funds Flow (5) | 373 | (416) | 146 | 735 | 832 | 471 | 1,989 | 505 |
| Net Earnings (Loss) | 859 | 146 | 820 | 1,000 | 1,176 | 743 | 1,864 | 866 |
| Per Share – Basic () | 0.47 | 0.08 | 0.44 | 0.53 | 0.62 | 0.39 | 0.98 | 0.45 |
| Per Share – Diluted () | 0.47 | 0.07 | 0.42 | 0.53 | 0.62 | 0.32 | 0.97 | 0.44 |
| Total Assets | 56,380 | 56,539 | 54,680 | 56,000 | 54,994 | 53,915 | 54,427 | 53,747 |
| Long-Term Debt, Including Current Portion | 7,524 | 7,534 | 7,199 | 7,275 | 7,227 | 7,108 | 7,224 | 8,534 |
| Net Debt | 5,079 | 4,614 | 4,196 | 4,258 | 4,827 | 5,060 | 5,976 | 6,367 |
| Cash Returns to Common and Preferred Shareholders | 595 | 706 | 1,070 | 1,034 | 436 | 731 | 1,225 | 584 |
| Common Shares – Base Dividends | 327 | 330 | 329 | 334 | 262 | 261 | 264 | 265 |
| Base Dividends Per Common Share () | 0.180 | 0.180 | 0.180 | 0.180 | 0.140 | 0.140 | 0.140 | 0.140 |
| Common Shares – Variable Dividends | — | — | — | 251 | — | — | — | — |
| Variable Dividends Per Common Share () | — | — | — | 0.135 | — | — | — | — |
| Purchase of Common Shares Under NCIB (7) | 62 | 108 | 732 | 440 | 165 | 350 | 361 | 310 |
| Payment for Purchase of Warrants | — | — | — | — | — | 111 | 600 | — |
| Dividends Paid on Preferred Shares | 6 | 18 | 9 | 9 | 9 | 9 | — | 9 |
| Preferred Share Redemptions | 200 | 250 | — | — | — | — | — | — |
All values are in US Dollars.
(1)Refer to the Operating and Financial Results section of this MD&A for a summary of total production by product type.
(2)Represents Cenovus’s net interest in refining operations.
(3)Total processed inputs include crude oil and other feedstocks. Blending is excluded.
(4)2024 comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
(5)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(6)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(7)Normal course issuer bid (“NCIB”).
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 5 |
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| OPERATING AND FINANCIAL RESULTS | |
| --- |
Selected Operating and Financial Results — Upstream
| Percent Change | |||
| 2024 | |||
| Production Volumes by Segment (1) (MBOE/d) | |||
| Oil Sands | 2 | 615.3 | |
| Conventional (2) | 3 | 120.7 | |
| Offshore (3) | 6 | 64.9 | |
| Total Production Volumes | 2 | 800.9 | |
| Production Volumes by Product (1) | |||
| Bitumen (Mbbls/d) | 1 | 595.4 | |
| Heavy Crude Oil (Mbbls/d) | 22 | 17.9 | |
| Light Crude Oil (Mbbls/d) | 34 | 12.5 | |
| NGLs (Mbbls/d) | (8) | 32.4 | |
| Conventional Natural Gas (MMcf/d) | 4 | 855.8 | |
| Total Production Volumes (MBOE/d) | 2 | 800.9 | |
| Per-Unit Operating Expenses by Segment (/BOE) | |||
| Oil Sands (4) | (1) | 11.86 | |
| Conventional (2) (5) | (16) | 13.05 | |
| Offshore (3) (5) | (10) | 17.31 |
All values are in US Dollars.
(1)Refer to the Oil Sands, Conventional or Offshore reportable segments section of this MD&A for a summary of production by product type by segment.
(2)For the three months ended March 31, 2025, reported Conventional segment production and per-unit operating expenses includes Cenovus’s 30 percent equity interest in the Duvernay Energy Corporation (“Duvernay”) joint venture, which is accounted for using the equity method in the interim Consolidated Financial Statements. Operating expenses for the Conventional segment, excluding our equity interests in the Duvernay joint venture, for the three months ended March 31, 2025, were $127 million.
(3)Reported Offshore segment production and per-unit operating expenses includes Cenovus’s 40 percent equity interest in the HCML joint venture, which is accounted for using the equity method in the interim Consolidated Financial Statements. Operating expenses for the Offshore segment, excluding our equity interests in the HCML joint venture, for the three months ended March 31, 2025, were $89 million (2024 – $85 million).
(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(5)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Production
Total upstream production increased in the first quarter of 2025 compared with 2024 due to:
•Successful results from our optimization programs and new sustaining well pads at Foster Creek.
•Strong performance at the Terra Nova field and the safe restart of production at the White Rose field as the SeaRose FPSO resumed operations in our Atlantic region.
•Solid base production and new development wells at our Lloydminster conventional heavy oil assets.
Per-Unit Operating Expenses
For the three months ended March 31, 2025, per-unit operating expenses were relatively consistent in the Oil Sands segment, compared with the same period in 2024. Per-unit operating expenses decreased in the Conventional segment mainly due to lower processing and gathering costs. Per-unit operating expenses decreased in the Offshore segment compared with 2024, primarily due to higher sales volumes in our Atlantic operations. We continue to focus on controlling costs through securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.
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Selected Operating and Financial Results — Downstream
| Percent Change | |||
| 2024 | |||
| Crude Oil Unit Throughput by Segment (Mbbls/d) | |||
| Canadian Refining | 7 | 104.1 | |
| U.S. Refining | — | 551.1 | |
| Total Crude Oil Unit Throughput | 2 | 655.2 | |
| Production Volumes by Product (1) (Mbbls/d) | |||
| Gasoline | 1 | 281.9 | |
| Distillates (2) | 5 | 213.0 | |
| Synthetic Crude Oil | 11 | 47.1 | |
| Asphalt | 1 | 41.7 | |
| Ethanol | (20) | 5.4 | |
| Other | 1 | 113.0 | |
| Total Production Volumes | 3 | 702.1 | |
| Per-Unit Operating Expenses by Segment (3) (/bbl) | |||
| Canadian Refining | (27) | 14.83 | |
| U.S. Refining | 18 | 11.65 | |
| Per-Unit Operating Expenses – Excluding Turnaround Costs by Segment (3) (/bbl) | |||
| Canadian Refining | (19) | 13.36 | |
| U.S. Refining | 10 | 11.01 |
All values are in US Dollars.
(1)Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product by segment.
(2)Includes diesel and jet fuel.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.
In the first quarter of 2025, total downstream throughput and refined product production increased slightly compared with the same period in 2024. The increases were primarily due to our Canadian Refining assets running at, or above, capacity and improved process unit reliability at our operated refineries in the U.S. Refining segment.
In the first quarter of 2025, per-unit operating expenses, excluding turnaround costs, decreased in the Canadian Refining segment compared with the same period in 2024, primarily due to record throughput as a result of high reliability, combined with less overall project expenses. Per-unit operating expenses, excluding turnaround costs, in the U.S. Refining segment increased quarter-over-quarter, primarily due to higher energy costs and the weakening of the Canadian dollar relative to the U.S. dollar. On average, the Canadian dollar was six percent weaker than the U.S. dollar compared with the first quarter of 2024. Overall, controllable operating expenses excluding turnaround costs in the U.S. Refining segment decreased slightly when compared with the first quarter of 2024.
Selected Consolidated Financial Results
Revenues
Revenues increased two percent to $13.3 billion compared with the first quarter of 2024. Upstream revenue increased 17 percent compared with 2024, primarily due to the narrowing of the WTI-WCS and condensate-WCS differentials, and increased sales volumes. Downstream revenues decreased six percent compared with 2024, primarily due to lower refined product pricing.
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Operating Margin
Operating Margin is a non-GAAP financial measure and is used to provide a consistent measure of the cash-generating performance of our assets for comparability of our underlying financial performance between periods.
| ( millions) | 2025 | 2024 |
| Gross Sales | ||
| External Sales (1) | 14,205 | 13,810 |
| Intersegment Sales | 2,752 | 2,287 |
| 16,957 | 16,097 | |
| Royalties | (906) | (747) |
| Revenues (1) | 16,051 | 15,350 |
| Expenses | ||
| Purchased Product (1) | 8,249 | 7,656 |
| Transportation and Blending | 3,247 | 2,811 |
| Operating Expenses | 1,747 | 1,685 |
| Realized (Gain) Loss on Risk Management Activities | (3) | 7 |
| Operating Margin | 2,811 | 3,191 |
All values are in US Dollars.
(1)Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.
Operating Margin by Segment
Three Months Ended March 31, 2025 and 2024
Operating Margin decreased compared with the first quarter of 2024, primarily due to:
•Lower market crack spreads impacting our U.S. Refining segment.
•Higher heavy crude feedstock costs in both our Canadian and U.S. Refining segments, as the narrowing of the WTI-WCS differential increased the costs of some feedstocks entering our refineries.
The decreases were partially offset by higher Operating Margin in our Oil Sands segment due to higher Realized Sales Prices as a result of the narrowing of the WTI-WCS differential following the startup of the Trans Mountain Pipeline expansion project (“TMX”) and higher overall sales volumes. The increase was partially offset by higher transportation expenses.
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Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations.
| ( millions) | 2025 | 2024 |
| Cash From (Used in) Operating Activities | 1,315 | 1,925 |
| (Add) Deduct: | ||
| Settlement of Decommissioning Liabilities | (36) | (48) |
| Net Change in Non-Cash Working Capital | (861) | (269) |
| Adjusted Funds Flow | 2,212 | 2,242 |
All values are in US Dollars.
Adjusted Funds Flow was relatively consistent in the first quarter of 2025 compared with 2024, as the decrease in Operating Margin was mainly offset by a decrease in stock-based compensation costs.
Cash from operating activities decreased in the first quarter of 2025 compared with the same period in 2024, primarily due to changes in non-cash working capital, combined with lower Operating Margin. The net change in non-cash working capital resulted in a use of cash of $861 million due to decreased accounts payable and income taxes payable. In the first quarter of 2024, changes in non-cash working capital resulted in a use of cash of $269 million.
Net Earnings (Loss)
Net earnings in the first quarter of 2025 was $859 million (2024 – $1.2 billion). The decrease was primarily due to lower Operating Margin, higher depreciation, depletion and amortization expense, and a gain on divestiture of assets in 2024. The decrease was partially offset by lower income tax expense, minimal foreign exchange gains or losses in 2025 compared with a net foreign exchange loss of $99 million in 2024, and lower general and administrative costs.
Net Debt
| As at ($ millions) | March 31, 2025 | December 31, 2024 |
|---|---|---|
| Short-Term Borrowings | 323 | 173 |
| Current Portion of Long-Term Debt | 192 | 192 |
| Long-Term Portion of Long-Term Debt | 7,332 | 7,342 |
| Total Debt | 7,847 | 7,707 |
| Cash and Cash Equivalents | (2,768) | (3,093) |
| Net Debt | 5,079 | 4,614 |
Total debt increased primarily due to higher short-term borrowings under the WRB uncommitted demand facilities. Net Debt increased by $465 million from December 31, 2024, mainly due to capital investment of $1.2 billion, base dividends of $327 million, preferred share redemptions of $200 million and the increase in short-term borrowings, as discussed above, partially offset by cash from operating activities of $1.3 billion. For further details, see the Liquidity and Capital Resources section of this MD&A.
Capital Investment (1)
| ( millions) | 2025 | 2024 | ||
| Upstream | ||||
| Oil Sands | 763 | 647 | ||
| Conventional | 122 | 126 | ||
| Offshore | 241 | 159 | ||
| Total Upstream | 1,126 | 932 | ||
| Downstream | ||||
| Canadian Refining | 22 | 31 | ||
| U.S. Refining | 77 | 67 | ||
| Total Downstream | 99 | 98 | ||
| Corporate and Eliminations | 4 | 6 | ||
| Total Capital Investment | 1,229 | 1,036 |
All values are in US Dollars.
(1)Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets and capitalized interest. Excludes capital expenditures related to equity interests in joint ventures accounted for using the equity method in the interim Consolidated Financial Statements.
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Capital investment in the first quarter of 2025 was mainly related to:
•Sustaining, redevelopment and optimization programs in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program.
•The progression of the West White Rose project.
•Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
•Growth projects in our Oil Sands segment, including the Narrows Lake tie-back to Christina Lake, the optimization project at Foster Creek, the Sunrise growth program and the progression of the drilling program at our Lloydminster conventional heavy oil assets.
•Sustaining activities in our refining segments.
Drilling Activity
| Net Stratigraphic Test Wells<br><br>and Observation Wells | Net Production Wells (1) | |||
|---|---|---|---|---|
| Three Months Ended March 31, | 2025 | 2024 | 2025 | 2024 |
| Foster Creek | 73 | 82 | 8 | 7 |
| Christina Lake | 65 | 58 | 5 | 1 |
| Sunrise | 21 | 40 | — | — |
| Lloydminster Thermal | — | — | 2 | 3 |
| Lloydminster Conventional Heavy Oil | — | — | 9 | 2 |
| 159 | 180 | 24 | 13 |
(1)Steam-assisted gravity drainage well pairs in the Oil Sands segment are counted as a single producing well.
Stratigraphic test wells were drilled to help identify future well pad locations and to further evaluate our assets. Observation wells were drilled to gather information and monitor reservoir conditions.
| Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | |||||
|---|---|---|---|---|---|---|
| (net wells) | Drilled | Completed | Tied-in | Drilled | Completed | Tied-in |
| Conventional (1) | 13 | 14 | 13 | 16 | 11 | 5 |
(1)Includes values attributable to Cenovus’s 30 percent equity interest in the Duvernay joint venture.
In the Offshore segment, no wells were drilled or completed in the first quarter of 2025 or 2024.
| COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS |
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Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and refining crack spreads, as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
| (Average US$/bbl, unless otherwise indicated) | Q1 2025 | Percent Change | Q1 2024 | Q4 2024 |
|---|---|---|---|---|
| Dated Brent | 75.66 | (9) | 83.24 | 74.69 |
| WTI | 71.42 | (7) | 76.96 | 70.27 |
| Differential Dated Brent – WTI | 4.24 | (32) | 6.28 | 4.42 |
| WCS at Hardisty | 58.75 | 2 | 57.65 | 57.71 |
| Differential WTI – WCS at Hardisty | 12.67 | (34) | 19.31 | 12.56 |
| WCS at Hardisty (C$/bbl) | 84.31 | 8 | 77.77 | 80.74 |
| WCS at Nederland | 67.74 | (3) | 69.89 | 65.69 |
| Differential WTI – WCS at Nederland | 3.68 | (48) | 7.07 | 4.58 |
| Condensate (C5 at Edmonton) | 69.88 | (4) | 72.78 | 70.66 |
| Differential Condensate – WTI Premium/(Discount) | (1.54) | (63) | (4.18) | 0.39 |
| Differential Condensate – WCS at Hardisty Premium/(Discount) | 11.13 | (26) | 15.13 | 12.95 |
| Condensate (C$/bbl) | 100.29 | 2 | 98.18 | 98.84 |
(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices refer to the Netback tables in the Upstream Reportable Segments section of this MD&A.
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Selected Benchmark Prices and Exchange Rates — Continued (1)
| (Average US$/bbl, unless otherwise indicated) | Q1 2025 | Percent Change | Q1 2024 | Q4 2024 |
|---|---|---|---|---|
| Synthetic at Edmonton | 69.07 | (1) | 69.42 | 71.11 |
| Differential Synthetic – WTI Premium/(Discount) | (2.35) | (69) | (7.54) | 0.84 |
| Synthetic at Edmonton (C$/bbl) | 99.12 | 6 | 93.65 | 99.45 |
| Refined Product Prices | ||||
| Chicago Regular Unleaded Gasoline (“RUL”) | 83.08 | (7) | 89.48 | 78.95 |
| Chicago Ultra-low Sulphur Diesel (“ULSD”) | 89.12 | (15) | 104.27 | 89.28 |
| Refining Benchmarks | ||||
| Chicago 3-2-1 Crack Spread (2) | 13.68 | (22) | 17.45 | 12.12 |
| Group 3 3-2-1 Crack Spread (2) | 16.48 | (6) | 17.50 | 12.66 |
| Renewable Identification Numbers (“RINs”) | 4.76 | 29 | 3.68 | 4.02 |
| Upgrading Differential (3) (C$/bbl) | 14.69 | (6) | 15.65 | 18.64 |
| Natural Gas Prices | ||||
| AECO (4) (C$/Mcf) | 2.17 | (13) | 2.50 | 1.48 |
| NYMEX (5) (US$/Mcf) | 3.65 | 63 | 2.24 | 2.79 |
| Foreign Exchange Rates | ||||
| US$ per C$1 – Average | 0.697 | (6) | 0.741 | 0.715 |
| US$ per C$1 – End of Period | 0.696 | (6) | 0.738 | 0.695 |
| RMB per C$1 – Average | 5.069 | (5) | 5.330 | 5.142 |
(1)These benchmark prices are not our Realized Sales Prices and represent approximate values. For our Realized Sales Prices refer to the Netback tables in the Upstream Reportable Segments section of this MD&A.
(2)The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last-in, first-out accounting basis.
(3)The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our Canadian Refining assets; however, it is used as a general market indicator.
(4)Alberta Energy Company ("AECO") 5A natural gas daily index.
(5)New York Mercantile Exchange (“NYMEX”) natural gas monthly index.
Crude Oil and Condensate Benchmarks
In the first quarter of 2025, crude oil benchmark prices, Brent and WTI, decreased compared with the first quarter of 2024, due to uncertainty surrounding the U.S. economy, tariff policies and anticipation of increasing global supply with the potential unwinding of OPEC+ voluntary production cuts starting in May 2025. Relative to the fourth quarter of 2024, crude oil benchmark prices increased due to volatility in prices from continued geopolitical uncertainty, new U.S. sanctions targeting Iran and Venezuela, and low global and U.S. crude inventories. Geopolitical events related to Russia and Ukraine, Israel and Gaza, Iran, Venezuela and Guyana have added to volatility and risk premiums, but had a limited impact on physical supply and demand in global oil markets.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices, and the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties.
WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude, and the cost of transport. For the first quarter of 2025, the WTI-WCS differential at Hardisty narrowed compared with the first quarter of 2024, due to the start-up of TMX increasing market access for WCS crude, low inventory levels in the Western Canadian Sedimentary Basin and stronger global demand for heavy crude.
WCS at Nederland is a heavy oil benchmark for sales of our product at the U.S. Gulf Coast (“USGC”). The WTI-WCS at Nederland differential is representative of the heavy oil quality differential and is influenced by global heavy oil refining capacity and global heavy oil supply. In the first quarter of 2025, the WTI-WCS at Nederland differential narrowed compared with the first and fourth quarters of 2024, due to strong global demand for heavy crudes, declining output from Mexico and continued voluntary production cuts from OPEC+ members, including Saudi Arabia.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized for HSB is primarily driven by the price of WTI, and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
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In the first quarter of 2025, synthetic crude oil at Edmonton was priced at a smaller discount to WTI, compared with the first quarter of 2024. The increase in pricing relative to the first quarter of 2024 was a function of deep discounts in the first quarter of 2024 due to high synthetic crude oil production in Alberta and the supply of light crude oil being above pipeline capacity on light crude oil pipelines with limited local storage capacity. The synthetic crude oil price at Edmonton was priced at a discount to WTI in the first quarter of 2025, compared with a premium in the fourth quarter of 2024, as production of Canadian light crude oil is near record highs and the threat of tariffs has decreased the value relative to U.S. light crude oil grades.
Crude Oil Benchmark Prices (1)
(1)Forward pricing as at April 4, 2025.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 20 percent to 35 percent. The Condensate-WCS differential is an important benchmark, as a higher premium generally results in a decrease in Operating Margin when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending, as well as timing of blended product sales.
In the first quarter of 2025, the average Edmonton condensate benchmark traded at a smaller discount to WTI compared with the first quarter of 2024, due to the same factors impacting the synthetic crude oil to WTI differential, as discussed above.
Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread. The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel, using current-month WTI- based crude oil feedstock prices and valued on a last-in, first-out basis.
In the first quarter of 2025, refined product prices declined compared with the first quarter in 2024, due to high global and regional supply of refined products as a result of incremental global refining capacity additions and U.S. refineries operating at high utilization rates for most of the quarter, especially in PADD 2 where some expected spring maintenance was deferred to later in the year. The average cost of RINs were higher in the first quarter of 2025 compared with the first and fourth quarters of 2024, due to weaker U.S. production, and imports of renewable diesel and biodiesel causing a decline in RINs generation.
North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices. The strength of refining market crack spreads in the U.S. Midwest and Midcontinent generally reflects the differential between Brent and WTI benchmark prices.
Our refining margins are affected by various other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as our feedstock is valued on a first-in, first-out (“FIFO”) accounting basis. The benchmark market crack spreads do not precisely mirror the configuration and product output of our refineries, or the location we sell product; however, they are used as a general market indicator.
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Refined Product Benchmarks (1)
(1)Forward pricing as at April 4, 2025.
Natural Gas Benchmarks
In the first quarter of 2025, AECO prices increased compared with the fourth quarter of 2024, but weakened compared with the first quarter of 2024, due to strong production levels and limited Western Canadian takeaway capacity. NYMEX natural gas prices increased compared with the first and fourth quarters of 2024, due to strong liquified natural gas (“LNG”) demand and low level of supply in U.S. inventory. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.
Foreign Exchange Benchmarks
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. dollar benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. Changes in foreign exchange rates also impact the translation of our U.S. and Asia Pacific operations.
In the first quarter of 2025, on average, the Canadian dollar weakened relative to the U.S. dollar compared with the first quarter of 2024, positively impacting our reported revenues and negatively impacting our U.S. Refining operating expenses. Although volatile throughout the period, the Canadian dollar ended the quarter unchanged compared with December 31, 2024.
A portion of our long-term sales contracts in the Asia Pacific region are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. In the first quarter of 2025, on average, the Canadian dollar weakened relative to RMB, compared with the first quarter of 2024, positively impacting our reported revenues.
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net finance costs, affect how certain liabilities are measured, and impact our cash flow and financial results.
As at March 31, 2025, the Bank of Canada’s Policy Interest Rate was 2.75 percent. On April 16, 2025, the Bank of Canada held the overnight rate at 2.75 percent.
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| OUTLOOK | |
| --- |
Commodity Price Outlook
Recent U.S. tariffs announcements, pauses, delays and modifications have introduced significant uncertainty in the market and raised the probabilities of a global recession. We expect heightened price volatility across all commodities to continue until there is a firm resolution on the duration and magnitude of the tariffs.
Global crude oil prices have trended lower between the first quarter of 2024 and the first quarter of 2025. OPEC+ policy continues to remain crucial to global oil supply and demand balances, and prices. The potential unwinding of OPEC+ voluntary production cuts starting in May 2025 has weighed on oil prices. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers. Price volatility remained heightened over the first quarter of 2025 with continued geopolitical risks.
The policies around tariffs, trade relations and global conflicts will be key considerations for energy prices. Global policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shift global trade patterns. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-OPEC+ supply growth, developments relating to conflicts involving Iran and attacks on vessels in the Red Sea, and tensions between Venezuela and Guyana.
In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth.
Refined product prices have trended lower in 2024 and 2025, as a result of incremental global capacity additions and U.S. refineries operating at very high utilization rates. Forward curves are showing signs of refined product crack spreads strengthening later in 2025.
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
•In the near-term, there is a higher risk of a tariff induced global economic slowdown that could slow oil demand.
•We expect the WTI-WCS at Hardisty differential will remain largely tied to global supply factors and heavy crude oil processing capacity, as long as supply does not exceed Canadian crude oil export capacity. As expected, the start-up of TMX in 2024 is having a narrowing impact on the WTI-WCS differential.
•Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America and globally.
•NYMEX and AECO natural gas prices are expected to remain range bound. The prospect of new LNG facilities in the U.S. and Canada coming into service or ramping up in the next year could increase demand and support North American natural gas prices. Weather will continue to be a key driver of demand and impact prices.
•We expect the Canadian dollar to continue to be impacted by the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, the U.S. Administration policies toward Canada-U.S. trade, crude oil prices and emerging macro-economic factors.
Most of our upstream crude oil and downstream refined product production is exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane, and is used as crude oil feedstock at our downstream refining operations. Condensate extracted from our blended crude oil is sold back to our Oil Sands segment.
Our refining capacity is focused in the U.S. Midwest, along with smaller exposures in the USGC and Alberta, exposing Cenovus to market crack spreads in these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly.
Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our refining capacity, and to a lesser degree, in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differentials, which could be subject to transportation constraints.
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While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product differentials through the following:
•Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.
•Integration – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil and spreads on refined products.
•Monitoring market fundamentals and optimizing run rates at our refineries accordingly.
•Traditional crude oil storage tanks in various geographic locations.
Key Priorities for 2025
Our 2025 priorities are focused on top-tier safety performance, capitalizing on operational momentum in our downstream business, maintaining and growing our competitive advantages in our Oil Sands business and execution on our growth projects. We will continue to maintain returns to shareholders, and focus on cost and sustainability improvements.
Top-tier Safety Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best-in-class operators for each of our major assets and businesses.
Downstream Competitiveness
A competitive, reliable downstream business is essential to our integrated business. It allows us to be agile in our response to fluctuating demand for refined products and serves as a natural partial hedge in times of widening location and heavy oil differentials.
We will continue to capitalize on our operational momentum in our downstream assets, leveraging our upstream expertise to maximize the long-term profitability of our assets.
Oil Sands Business
Our Oil Sands business is the backbone of our company. Maintaining and growing our competitive advantages, while operating safely and reliably, is critical to our company.
Project Execution
Investing in future growth is a focus for us, with several key projects underway, including the West White Rose project, the optimization and sulphur recovery projects at Foster Creek, the Narrows Lake tie-back to Christina Lake project, the Sunrise growth program and the Lloydminster conventional heavy oil growth project.
Cost Leadership
We aim to maximize shareholder value through a continued focus on low-cost structures and margin optimization across our business. We are focused on reducing operating, capital, and general and administrative costs, realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus.
Returns to Shareholders
Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. We plan to steward Net Debt to $4.0 billion and return 100 percent of Excess Free Funds Flow to shareholders over time. For further details, see the Liquidity and Capital Resources section of this MD&A.
Sustainability
Sustainability is central to Cenovus’s culture. We have established ambitious targets in our environmental, social and governance (“ESG”) focus areas, and we continue to advance work to support progress against these targets.
We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale carbon capture projects, while maintaining global competitiveness. It is critical that the federal and provincial governments provide support at a level consistent with what similar large-scale carbon capture projects are receiving globally to enable Canada to achieve its greenhouse gas (“GHG”) emissions goals.
Additional information on Cenovus’s performance in safety, Indigenous reconciliation, and inclusion and diversity is available in Cenovus’s 2023 Corporate Social Responsibility report on our website at cenovus.com.
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| REPORTABLE SEGMENTS | |
| --- |
UPSTREAM
Oil Sands
In the first quarter of 2025, we:
•Delivered safe and reliable operations.
•Produced 626.2 thousand BOE per day (2024 – 615.3 thousand BOE per day).
•Delivered successful results from our sustaining and optimization programs.
•Generated Operating Margin of $2.5 billion, an increase of $308 million compared with 2024, due to higher Realized Sales Prices as a result of the narrowing of the WTI-WCS differential since the startup of TMX and higher overall sales volumes. The increase was partially offset by increased transportation expenses due in part to the use of TMX.
•Earned a Netback of $44.34 per barrel (2024 – $40.79 per barrel).
•Invested capital of $763 million, primarily for sustaining activities and our integrated winter program, as well as growth projects. We continued to progress the Foster Creek optimization project and the Lloydminster conventional heavy oil drilling program. The Narrows Lake tie-back to Christina Lake began steaming in April and is on track for first oil early in the third quarter, as planned.
Financial Results
| Three Months Ended March 31, | ||
|---|---|---|
| ($ millions) | 2025 | 2024 |
| Gross Sales | ||
| External Sales | 5,904 | 5,013 |
| Intersegment Sales | 1,953 | 1,615 |
| 7,857 | 6,628 | |
| Royalties | (861) | (697) |
| Revenues | 6,996 | 5,931 |
| Expenses | ||
| Purchased Product | 632 | 289 |
| Transportation and Blending | 3,151 | 2,733 |
| Operating | 677 | 660 |
| Realized (Gain) Loss on Risk Management | (8) | 13 |
| Operating Margin | 2,544 | 2,236 |
| Unrealized (Gain) Loss on Risk Management | (7) | (13) |
| Depreciation, Depletion and Amortization | 834 | 774 |
| Exploration Expense | 4 | 3 |
| (Income) Loss from Equity-Accounted Affiliates | — | — |
| Segment Income (Loss) | 1,713 | 1,472 |
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 16 | |
| --- | --- |
Operating Margin Variance
Three Months Ended March 31, 2025
(1)Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.
(2)Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil or natural gas.
Operating Results
| 2024 | |
| Total Sales Volumes (1) (MBOE/d) | 606.9 |
| Crude Oil Production by Asset (Mbbls/d) | |
| Foster Creek | 196.0 |
| Christina Lake | 236.5 |
| Sunrise | 48.8 |
| Lloydminster Thermal | 114.1 |
| Lloydminster Conventional Heavy Oil | 17.9 |
| Total Crude Oil Production (2) (Mbbls/d) | 613.3 |
| Natural Gas (1) (MMcf/d) | 11.9 |
| Total Production (MBOE/d) | 615.3 |
| Effective Royalty Rate (3) (percent) | |
| Foster Creek | 24.9 |
| Christina Lake | 25.0 |
| Sunrise | 3.8 |
| Lloydminster (4) | 6.8 |
| Total Effective Royalty Rate | 19.3 |
| Netback (5) (/bbl) | |
| Realized Sales Price | 72.79 |
| Royalties | 12.60 |
| Transportation and Blending | 7.54 |
| Operating | 11.86 |
| Total Netback (/bbl) | 40.79 |
| Per-Unit DD&A (6) (/BOE) | 13.35 |
All values are in US Dollars.
(1)Bitumen, heavy crude oil and natural gas. Natural gas is a conventional natural gas product type.
(2)Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.
(3)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(4)Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.
(5)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(6)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
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Revenues
Gross sales increased in the first quarter of 2025 compared with 2024, due to higher realized pricing and higher sales volumes.
Price
Our bitumen and heavy oil production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our Netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized bitumen and heavy oil sales price decreases.
Our Realized Sales Price increased 11 percent in the first quarter of 2025 compared with 2024, mainly due to narrower WTI-WCS and condensate-WCS differentials, partially offset by a decrease in the WTI benchmark.
In first quarter of 2025, approximately 37 percent (2024 – 23 percent) of our crude oil sales volumes were sold to destinations outside of Alberta, including sales to our U.S. Refining operations. In the first quarter of 2025, approximately 25 percent (2024 – 20 percent) of our sales volumes were sold to our Canadian and U.S. downstream operations.
Cenovus makes storage and transportation decisions to use our marketing and transportation infrastructure, including storage and pipeline assets, in order to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability.
Production Volumes
Oil Sands crude oil production increased in the first quarter of 2025 compared with 2024, primarily due to:
•Increased production from our optimization programs and new sustaining well pads at Foster Creek.
•Strong base production and new development wells as we progress the execution of our drilling program at our Lloydminster conventional heavy oil assets.
•Successful results from our optimization programs and new sustaining well pads at our Sunrise asset.
The increases were partially offset by lower production at our Lloydminster thermal assets due to wells being offline for the execution of our redevelopment program in the first quarter of 2025, compared with 2024.
Production at our Christina Lake asset in the first quarter of 2025 was relatively consistent compared with 2024.
Royalties
Our Alberta oil sands royalty projects are based on government prescribed pre- and post-payout royalty rates. Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes each project's Crown and freehold split.
Refer to our 2024 annual MD&A for further details.
In the first quarter of 2025, Oil Sands royalties increased compared with 2024, primarily due to higher realized pricing and sales volumes. The Oil Sands effective royalty rate increased primarily due to higher realized prices, partially offset by lower Alberta sliding scale oil sands royalty rates.
Expenses
Transportation and Blending
In the first quarter of 2025, blending expenses increased $270 million compared with 2024, due primarily to higher sales volumes.
In the first quarter of 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, due to higher sales volumes on TMX and increased pipeline transportation rates on shipments to U.S. destinations.
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Per-Unit Transportation Expenses (1)
| Three Months Ended March 31, | ||
|---|---|---|
| ($/bbl) | 2025 | 2024 |
| Foster Creek | 15.85 | 10.25 |
| Christina Lake | 6.12 | 5.40 |
| Sunrise | 18.07 | 18.51 |
| Lloydminster (2) | 3.42 | 3.89 |
| Total Oil Sands | 9.85 | 7.54 |
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
At Foster Creek, per-unit transportation expenses increased primarily due to the use of TMX, partially offset by lower rail transportation costs. In 2025, 32 percent and 35 percent of our total sales volumes at Foster Creek were sold at West Coast and U.S. destinations, respectively (2024 – nil and 34 percent, respectively).
At Christina Lake, per-unit transportation expenses increased primarily due to increased pipeline transportation rates and higher rail transportation costs. In 2025, we shipped 15 percent (2024 – 11 percent) of our total sales volumes at Christina Lake to U.S. destinations.
At Sunrise, per-unit transportation expenses decreased primarily due to lower sales volumes to U.S. destinations, partially offset by the higher use of TMX. In 2025, 73 percent and 27 percent of our total sales volumes at Sunrise were sold at West Coast and U.S. destinations, respectively (2024 – nil and 94 percent, respectively).
At Lloydminster, per-unit transportation expenses decreased primarily due to lower sales volumes to U.S. destinations. In 2025, we shipped two percent (2024 – four percent) of our total sales volumes at Lloydminster to U.S. destinations.
Operating
Primary drivers of our operating expenses in the first quarter of 2025 were fuel, workforce, and repairs and maintenance. Total operating expenses increased compared with the same period in 2024, due to increased workover activity and GHG compliance costs. The increases were partially offset by lower fuel costs as a result of lower AECO benchmark prices and lower electricity costs. We continue to focus on controlling costs through securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.
Per-Unit Operating Expenses (1)
| Three Months Ended March 31, | |||
|---|---|---|---|
| ($/bbl) | 2025 | Percent <br>Change | 2024 |
| Foster Creek | |||
| Fuel | 2.41 | (25) | 3.22 |
| Non-Fuel | 7.41 | (2) | 7.59 |
| Total | 9.82 | (9) | 10.81 |
| Christina Lake | |||
| Fuel | 2.50 | (9) | 2.76 |
| Non-Fuel | 6.26 | 9 | 5.75 |
| Total | 8.76 | 3 | 8.51 |
| Sunrise | |||
| Fuel | 4.33 | — | 4.32 |
| Non-Fuel | 13.22 | 4 | 12.70 |
| Total | 17.55 | 3 | 17.02 |
| Lloydminster (2) | |||
| Fuel | 3.68 | (11) | 4.15 |
| Non-Fuel | 14.78 | 6 | 13.90 |
| Total | 18.46 | 2 | 18.05 |
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
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Per-Unit Operating Expenses — Continued (1)
| Three Months Ended March 31, | |||
|---|---|---|---|
| ($/bbl) | 2025 | Percent <br>Change | 2024 |
| Total Oil Sands | |||
| Fuel | 2.85 | (14) | 3.31 |
| Non-Fuel | 8.92 | 4 | 8.55 |
| Total | 11.77 | (1) | 11.86 |
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Per-unit fuel expenses decreased overall due to lower AECO natural gas prices, as discussed above. Sunrise per-unit fuel expenses were relatively consistent in the first quarter of 2025 compared with 2024, as lower natural gas prices were fully offset by increased consumption volumes from well pads coming online.
Overall, non-fuel expenses increased in the first quarter of 2025 compared with 2024, due to:
•Higher GHG compliance costs and lower sales volumes, partially offset by lower waste fluid handling and trucking costs at our Christina Lake assets.
•Higher GHG compliance costs, workover activity and chemical costs, partially offset by increased sales volumes and lower electricity costs at our Sunrise assets.
•Higher workover activity and lower sales volumes at our Lloydminster assets.
The increases were partially offset by a decrease in non-fuel expenses at our Foster Creek assets due to increased sales volumes, lower chemical and GHG compliance costs, partially offset by increased repairs and maintenance.
Conventional
In the first quarter of 2025, we:
•Delivered safe and reliable operations.
•Produced 123.9 thousand BOE per day (2024 – 120.7 thousand BOE per day).
•Generated Operating Margin of $173 million, an increase of $24 million from 2024.
•Earned a Netback of $15.77 per BOE (2024 – $13.04 per BOE).
•Invested capital of $122 million primarily related to drilling, completion, tie-in and infrastructure projects. Completions and tie-in activities increased in the first quarter, due in part to well development activities that were deferred in the second half of 2024 due to lower natural gas benchmark prices.
Financial Results
| Three Months Ended March 31, | ||
|---|---|---|
| ($ millions) | 2025 | 2024 |
| Gross Sales | ||
| External Sales | 443 | 377 |
| Intersegment Sales | 501 | 502 |
| 944 | 879 | |
| Royalties | (20) | (24) |
| Revenues | 924 | 855 |
| Expenses | ||
| Purchased Product | 535 | 482 |
| Transportation and Blending | 90 | 78 |
| Operating | 127 | 153 |
| Realized (Gain) Loss on Risk Management | (1) | (7) |
| Operating Margin | 173 | 149 |
| Unrealized (Gain) Loss on Risk Management | — | 6 |
| Depreciation, Depletion and Amortization | 120 | 110 |
| Exploration Expense | — | — |
| (Income) Loss From Equity-Accounted Affiliates | — | 1 |
| Segment Income (Loss) | 53 | 32 |
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 20 | |
| --- | --- |
Operating Margin Variance
Three Months Ended March 31, 2025
(1)Changes to price include the impact of realized risk management gains and losses.
(2)Reflects Operating Margin from processing facilities.
Operating Results
| 2024 | |
| Total Sales Volumes (1) (MBOE/d) | 120.7 |
| Realized Sales Price (1) (2) (/BOE) | |
| Light Crude Oil (/bbl) | 87.97 |
| NGLs (/bbl) | 57.40 |
| Conventional Natural Gas (/Mcf) | 4.00 |
| Production by Product (1) | |
| Light Crude Oil (Mbbls/d) | 5.3 |
| NGLs (Mbbls/d) | 22.0 |
| Conventional Natural Gas (MMcf/d) | 560.5 |
| Total Production (MBOE/d) | 120.7 |
| Conventional Natural Gas Production (percentage of total) | 77 |
| Crude Oil and NGLs Production (percentage of total) | 23 |
| Effective Royalty Rate (1) (3) (percent) | 9.9 |
| Netback (1) (2) (/BOE) | |
| Realized Sales Price | 32.92 |
| Royalties | 2.16 |
| Transportation and Blending | 4.67 |
| Operating | 13.05 |
| Total Netback (/BOE) | 13.04 |
| Per-Unit DD&A (4) (/BOE) | 9.90 |
All values are in US Dollars.
(1)For the three months ended March 31, 2025, reported production volumes, sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 30 percent equity interest in the Duvernay joint venture.
(2)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(3)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(4)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 21 |
|---|
Revenues
Gross sales increased in the first quarter of 2025 compared with 2024, due to higher Realized Sales Price and increased sales volumes.
Price
Our total Realized Sales Price increased in the first quarter of 2025, compared with 2024. For the three months ended March 31, 2025, 27 percent (2024 – 28 percent) of our sales volumes of natural gas were sold to U.S. destinations where NYMEX natural gas benchmark prices are higher. These increases were partially offset by a reduction in the AECO natural gas benchmark price. For the three months ended March 31, 2025, the AECO natural gas benchmark price was $2.17 per Mcf (2024 – $2.50 per Mcf) and the NYMEX natural gas benchmark price was US$3.65 per Mcf (2024 – US$2.24 per Mcf).
Production Volumes
Production volumes increased in the first quarter of 2025, compared with 2024, primarily due to strong base performance and bringing on wells in 2025 that had been deferred in 2024 due to lower AECO pricing.
Royalties
Royalties decreased in the first quarter of 2025, compared with 2024, primarily due to lower natural gas benchmark prices used to calculate our royalties.
Expenses
Transportation
Our transportation expenses reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. In the first quarter of 2025, transportation expenses and per-unit transportation expenses increased compared with 2024, primarily due to increased pipeline transportation rates.
Operating
Primary drivers of operating expenses in the first quarter of 2025 were repairs and maintenance, workforce and property tax costs. Total operating expenses and per-unit operating expenses decreased compared with 2024, mainly due to lower processing and gathering costs. The decrease in per-unit operating expenses was also due to higher sales volumes.
Offshore
In the first quarter of 2025, we:
•Delivered safe and reliable operations.
•Produced 68.8 thousand BOE per day of light crude oil, NGLs and natural gas (2024 – 64.9 thousand BOE per day).
•Generated Operating Margin of $331 million, an increase of $85 million from 2024, primarily due to increased sales volumes, partially offset by lower realized pricing in our Atlantic operations.
•Earned a Netback of $58.03 per BOE (2024 – $52.80 per BOE).
•Invested capital of $241 million, mainly related to the progression of the West White Rose project.
The West White Rose project continues to progress toward installation and commissioning of the offshore platform. Preparations are underway to tow the concrete gravity structure to the field in the second quarter, with the transport of the topsides expected to occur in the third quarter. As at March 31, 2025, the project was approximately 90 percent completed and we remain on track to deliver first oil in the second quarter of 2026. Since our decision in 2022 to restart the project, we have invested approximately $1.8 billion.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 22 |
|---|
Financial Results
| Three Months Ended March 31, | ||||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | |||||
| ($ millions) | Atlantic | Asia Pacific | Offshore | Atlantic | Asia Pacific | Offshore |
| Gross Sales | ||||||
| External Sales | 146 | 305 | 451 | 42 | 315 | 357 |
| Intersegment Sales | — | — | — | — | — | — |
| 146 | 305 | 451 | 42 | 315 | 357 | |
| Royalties | (2) | (23) | (25) | (2) | (24) | (26) |
| Revenues | 144 | 282 | 426 | 40 | 291 | 331 |
| Expenses | ||||||
| Purchased Product | — | — | — | — | — | — |
| Transportation and Blending | 6 | — | 6 | — | — | — |
| Operating | 64 | 25 | 89 | 57 | 28 | 85 |
| Operating Margin (1) | 74 | 257 | 331 | (17) | 263 | 246 |
| Depreciation, Depletion and Amortization | 130 | 131 | ||||
| Exploration Expense | 1 | 4 | ||||
| (Income) Loss from Equity-Accounted Affiliates | (8) | (10) | ||||
| Segment Income (Loss) | 208 | 121 |
(1)Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Specified Financial Measures Advisory of this MD&A.
Operating Margin Variance
Three Months Ended March 31, 2025
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 23 |
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Operating Results
| Three Months Ended March 31, | ||
|---|---|---|
| 2025 | 2024 | |
| Sales Volumes | ||
| Atlantic (Mbbls/d) | 15.8 | 3.9 |
| Asia Pacific (MBOE/d) | ||
| China | 42.0 | 43.7 |
| Indonesia (1) | 15.2 | 14.0 |
| Total Asia Pacific | 57.2 | 57.7 |
| Total Sales Volumes (MBOE/d) | 73.0 | 61.6 |
| Production by Product | ||
| Atlantic – Light Crude Oil (Mbbls/d) | 11.6 | 7.2 |
| Asia Pacific (1) | ||
| NGLs (Mbbls/d) | 9.3 | 10.4 |
| Conventional Natural Gas (MMcf/d) | 287.2 | 283.4 |
| Total Asia Pacific (MBOE/d) | 57.2 | 57.7 |
| Total Production (MBOE/d) | 68.8 | 64.9 |
| Effective Royalty Rate (2) (percent) | ||
| Atlantic | 1.0 | 4.5 |
| Asia Pacific (1) | 12.6 | 7.6 |
| Per-Unit DD&A (3) ($/BOE) | 19.07 | 29.17 |
(1)Reported production volumes, sales volumes, associated per-unit values and royalty rates reflect Cenovus’s 40 percent equity interest in the HCML joint venture.
(2)Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.
(3)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Netbacks (1)
| Three Months Ended March 31, 2025 | ||||||
|---|---|---|---|---|---|---|
| ($/BOE, except where indicated) | Atlantic (/bbl) | China | Indonesia | Total Offshore (2) | ||
| Realized Sales Price | 81.01 | 64.65 | 82.26 | |||
| Royalties | 6.13 | 19.44 | 7.81 | |||
| Transportation and Blending | — | — | 0.92 | |||
| Operating Expenses | 6.00 | 10.67 | 15.50 | |||
| Netback | 68.88 | 34.54 | 58.03 |
All values are in US Dollars.
| Three Months Ended March 31, 2024 | ||||||
|---|---|---|---|---|---|---|
| ($/BOE, except where indicated) | Atlantic (/bbl) | China | Indonesia | Total Offshore (2) | ||
| Realized Sales Price | 79.21 | 53.05 | 75.48 | |||
| Royalties | 6.00 | 4.10 | 5.51 | |||
| Transportation and Blending | — | — | (0.14) | |||
| Operating Expenses | 6.28 | 11.86 | 17.31 | |||
| Netback | 66.93 | 37.09 | 52.80 |
All values are in US Dollars.
(1)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)Reported per-unit values reflect Cenovus’s 40 percent equity interest in the HCML joint venture.
Revenues
Gross sales increased in the first quarter of 2025, compared with 2024, primarily due to increased sales volumes, partially offset by a lower Realized Sales Price at our Atlantic operations.
Price
Our Atlantic Realized Sales Price on light crude oil decreased in the first quarter of 2025, compared with 2024, due to lower Brent benchmark pricing. The prices we receive for natural gas sold in Asia Pacific are set under long-term contracts.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 24 |
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Production Volumes
Atlantic production increased in the first quarter of 2025, compared with 2024, primarily due to strong performance at the Terra Nova field and the safe restart of production at the White Rose field. Atlantic production in 2024 was lower as production at the White Rose field was suspended in late December 2023 in preparation for the SeaRose Asset Life Extension (“ALE”) project and production at Terra Nova was ramping up after its ALE project. Light crude oil production from the White Rose and Terra Nova fields are offloaded from the SeaRose and Terra Nova FPSO vessels, respectively, to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales.
Asia Pacific production was consistent in the first quarter of 2025, compared with 2024.
Royalties
For the three months ended March 31, 2025, the Atlantic effective royalty rate decreased compared with 2024. The decrease was primarily due to a lower effective royalty rate applied to Terra Nova field sales in the first quarter of 2025, compared with a higher effective royalty rate applicable to White Rose field sales in the first quarter of 2024. There were no White Rose field sales in 2025.
Royalty rates in Asia Pacific are governed by production-sharing contracts, in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for Asia Pacific for the first quarter of 2025 increased compared with 2024, primarily due to credits received in 2024.
Expenses
Transportation
Transportation expenses include the costs of transporting crude oil from the Terra Nova and SeaRose FPSOs to onshore terminals and storage costs. Transportation expenses for the first quarter of 2025 increased to $6 million (2024 – $nil) primarily due to increased sales volumes, compared with minimal sales in the first quarter of 2024.
Operating
Primary drivers of our Atlantic operating expenses in the first quarter of 2025 were repairs and maintenance, costs related to vessels and air services, and workforce. Operating expenses increased compared with 2024, primarily due to a significant increase in sales volumes, partially offset by lower repairs and maintenance costs. Per-unit operating expenses decreased in the first quarter of 2025, compared with 2024, mainly due to the increase in sales volumes as a result of the timing of lifts.
Primary drivers of our China operating expenses in the first quarter of 2025 were repairs and maintenance, workforce costs and insurance. Operating expenses decreased compared with 2024, primarily due to lower insurance costs, partially offset by increased repairs and maintenance costs. Per-unit operating expenses decreased compared with 2024, due to the factors discussed above, partially offset by lower sales volumes.
Primary drivers of our Indonesia operating expenses in the first quarter of 2025 were repairs and maintenance, workforce costs, and costs related to vessel services. Indonesia per-unit operating expenses decreased in the first quarter of 2025, compared with 2024, due to higher sales volumes.
DOWNSTREAM
Canadian Refining
In the first quarter of 2025, we:
•Delivered safe and reliable operations.
•Achieved record throughput of 111.9 thousand barrels per day (2024 – 104.1 thousand barrels per day).
•Incurred per-unit operating expenses excluding turnaround costs of $10.81 per barrel (2024 – $13.36 per barrel).
•Recorded Operating Margin of $68 million as increased production and lower operating expenses were offset by lower refined product prices (2024 – $68 million).
•Invested capital of $22 million, primarily focused on sustaining activities.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 25 |
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Financial and Operating Results
| ( millions) | 2025 | 2024 |
| Revenues | 1,282 | 1,332 |
| Purchased Product | 1,076 | 1,087 |
| Gross Margin (1) | 206 | 245 |
| Expenses | ||
| Operating | 138 | 177 |
| Operating Margin | 68 | 68 |
| Depreciation, Depletion and Amortization | 47 | 44 |
| Segment Income (Loss) | 21 | 24 |
All values are in US Dollars.
(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
| Three Months Ended March 31, | ||
|---|---|---|
| ($ millions, except where indicated) | 2025 | 2024 |
| Gross Margin | 206 | 245 |
| Inventory Holding (Gain) Loss (1) | 3 | (23) |
| Adjusted Gross Margin (2) | 209 | 222 |
| Adjusted Refining Margin (3) ($/bbl) | 17.33 | 20.23 |
(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the FIFO or weighted average cost basis, as required by IFRS Accounting Standards.
(2)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(3)Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A. Revenues from the Upgrader, the Lloydminster Refinery and the commercial fuels business for the three months ended March 31, 2025, were $1.2 billion (2024 – $1.2 billion).
The Upgrader processes blended heavy crude oil and bitumen into high-value synthetic crude oil and low-sulphur diesel. Upgrading Gross Margin is primarily dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil and bitumen feedstock.
The Lloydminster Refinery processes blended heavy crude oil into asphalt, bulk distillates and industrial products. Gross Margin is largely dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year.
Revenues decreased in the first quarter of 2025, compared with 2024, primarily due to lower diesel benchmark prices, partially offset by an increase in sales volumes.
Adjusted Gross Margin and Adjusted Refining Margin decreased quarter-over-quarter, primarily due to lower benchmark diesel prices, as discussed above, combined with higher heavy crude oil and bitumen feedstock costs as a result of the narrowing of the WTI-WCS differential. The upgrading differential narrowed six percent compared with the first quarter of 2024.
| Three Months Ended March 31, | |||
|---|---|---|---|
| (Mbbls/d, except where indicated) | 2025 | 2024 | |
| Operable Capacity | 108.0 | 108.0 | |
| Total Processed Inputs | 119.5 | 108.8 | |
| Crude Oil Unit Throughput | 111.9 | 104.1 | |
| Crude Unit Utilization (percent) | 104 | 96 | |
| Total Production | 126.5 | 116.2 | |
| Synthetic Crude Oil | 52.4 | 47.1 | |
| Asphalt | 16.6 | 15.6 | |
| Diesel | 15.5 | 12.9 | |
| Other | 37.7 | 35.2 | |
| Ethanol | 4.3 | 5.4 |
The Upgrader and Lloydminster Refinery source their crude oil feedstock from our Oil Sands segment. In the first quarter of 2025, 14 percent of our Oil Sands segment’s sales volumes were purchased by our Canadian Refining segment (2024 – 13 percent).
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 26 |
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Throughput and total production increased in the first quarter of 2025 compared with 2024, as our assets ran at, or above, capacity for the majority of the quarter. This was due in part to the benefits of the turnaround and projects completed in 2024.
Operating Expenses
The following table and discussion represent operating expenses associated with the Upgrader, the Lloydminster Refinery and the commercial fuels business.
| ( millions, except where indicated) | 2025 | 2024 |
| Operating Expenses – Upgrading and Refining | 116 | 147 |
| Operating Expenses – Excluding Turnaround Costs | 116 | 132 |
| Operating Expenses – Turnaround Costs | — | 15 |
| Per-Unit Operating Expenses (1) (/bbl) | 10.81 | 14.83 |
| Per-Unit Operating Expenses – Excluding Turnaround Costs | 10.81 | 13.36 |
| Per-Unit Operating Expenses – Turnaround Costs | — | 1.47 |
All values are in US Dollars.
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were workforce, and repairs and maintenance costs. In the first quarter of 2025, operating expenses excluding turnaround costs decreased compared with 2024, primarily due to lower project expenses in 2025. The decrease in operating expenses, combined with increased total processed inputs, resulted in decreased per-unit operating expenses compared with 2024.
U.S. Refining
In the first quarter of 2025, we:
•Delivered safe and reliable operations.
•Achieved a crude unit utilization of 90 percent (2024 – 90 percent) and throughput of 553.5 thousand barrels per day compared with 551.1 thousand barrels per day in the first quarter of 2024.
•Incurred per-unit operating expenses excluding turnaround costs of $12.15 per barrel (2024 – $11.01 per barrel), primarily due to increased energy costs and the weakening of the Canadian dollar, on average, relative to the U.S. dollar.
•Recorded an Operating Margin shortfall of $305 million, a decrease of $797 million from the first quarter of 2024. The decrease was primarily due to lower market crack spreads, a narrower WTI-WCS differential and higher operating costs.
•Invested capital of $77 million, primarily focused on sustaining activities.
Financial and Operating Results
| ( millions) | 2025 | 2024 |
| Revenues (1) | 6,423 | 6,901 |
| Purchased Product (1) | 6,006 | 5,798 |
| Gross Margin (2) | 417 | 1,103 |
| Expenses | ||
| Operating | 716 | 610 |
| Realized (Gain) Loss on Risk Management | 6 | 1 |
| Operating Margin | (305) | 492 |
| Unrealized (Gain) Loss on Risk Management | (8) | 8 |
| Depreciation, Depletion and Amortization | 158 | 111 |
| Segment Income (Loss) | (455) | 373 |
All values are in US Dollars.
(1)Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.
(2)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 27 | |
|---|---|---|
| --- | --- | |
| ( millions, except where indicated) | 2025 | 2024 |
| Gross Margin | 417 | 1,103 |
| Inventory Holding (Gain) Loss (1) | 23 | (194) |
| Adjusted Gross Margin (2) | 440 | 909 |
| Adjusted Refining Margin (2) (/bbl) | 8.41 | 17.37 |
| Adjusted Market Capture (2) (percent) | 62 | 93 |
All values are in US Dollars.
(1)Inventory holding (gain) loss reflects the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the FIFO or weighted average cost basis, as required by IFRS Accounting Standards.
(2)Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
Market crack spreads do not precisely mirror the refinery configuration for crude diet and product yields, or the location we sell product; however, they are used as a general market indicator. In the first quarter of 2025, the Chicago 3-2-1 crack spread decreased 22 percent and the Group 3 3-2-1 crack spread decreased six percent, compared with the first quarter of 2024.
The Adjusted Refining Margin, which is the Adjusted Gross Margin on a per-barrel basis, is affected by many factors. Some of these factors include the type of crude oil feedstock processed; refinery configuration and the proportion of gasoline, distillates and secondary product output, and the cost of feedstock.
Revenues decreased in the first quarter of 2025, compared with 2024, due to declines in benchmark gasoline and diesel prices and a slight decrease in sales volumes.
Adjusted Gross Margin and Adjusted Refining Margin decreased quarter-over-quarter, primarily due to the decline in benchmark market crack spreads, as discussed above, partially offset by increased process unit reliability at our operated refineries.
The WTI-WCS differential narrowed by 34 percent to US$12.67 per barrel in the first quarter of 2025, compared with 2024, as the start-up of TMX increased the cost of heavy crude entering our refineries, which negatively impacted our Adjusted Gross Margin and Adjusted Market Capture.
| Three Months Ended March 31, | |||
|---|---|---|---|
| (Mbbls/d, except where indicated) | 2025 | 2024 | |
| Operable Capacity | 612.3 | 612.3 | |
| Total Processed Inputs | 581.0 | 575.0 | |
| Crude Oil Unit Throughput | 553.5 | 551.1 | |
| Heavy Crude Oil | 226.3 | 224.7 | |
| Light/Medium Crude Oil | 327.2 | 326.4 | |
| Crude Unit Utilization (percent) | 90 | 90 | |
| Total Refined Product Production | 595.9 | 585.9 | |
| Gasoline | 284.7 | 281.9 | |
| Distillates (1) | 208.8 | 200.1 | |
| Asphalt | 25.7 | 26.1 | |
| Other | 76.7 | 77.8 |
(1)Includes diesel and jet fuel.
Throughput was relatively consistent and total refined product production increased slightly in the first quarter of 2025, compared with 2024. This was primarily due to higher process unit reliability at our operated refineries, partially offset by turnarounds that began at both of our non-operated refineries in March. These are expected to be completed in the second quarter.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 28 |
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Operating Expenses
| ( millions, except where indicated) | 2024 | 2024 |
| Operating Expenses | 716 | 610 |
| Operating Expenses – Excluding Turnaround Costs | 635 | 576 |
| Operating Expenses – Turnaround Costs | 81 | 34 |
| Per-Unit Operating Expenses (1) (/bbl) | 13.69 | 11.65 |
| Per-Unit Operating Expenses – Excluding Turnaround Costs | 12.15 | 11.01 |
| Per-Unit Operating Expenses – Turnaround Costs | 1.54 | 0.64 |
All values are in US Dollars.
(1)Specified financial measure. See the Specified Financial Measures Advisory of this MD&A.
Primary drivers of operating expenses were workforce, repairs and maintenance, and turnaround costs. In the first quarter of 2025, operating expenses increased mainly due to turnaround and workforce costs, as we prepared the Toledo Refinery for the East Side turnaround, which began in April. Our non-operated refineries began turnarounds in March.
Operating expenses, operating expenses excluding turnaround costs and related per-unit metrics increased due to higher energy costs and the weakening of the Canadian dollar relative to the U.S. dollar. On average, the Canadian dollar was six percent weaker than the U.S. dollar compared with the first quarter of 2024. The increases were partially offset by lower repairs and maintenance expense. Overall, controllable operating expenses excluding turnaround costs decreased slightly when compared with the first quarter of 2024. Per-unit operating expense increases were partially offset by slightly higher total processed inputs.
CORPORATE AND ELIMINATIONS
Financial Results
| ( millions) | 2025 | 2024 |
| Realized (Gain) Loss on Risk Management | (5) | 3 |
| Unrealized (Gain) Loss on Risk Management | 38 | 30 |
| General and Administrative | 197 | 246 |
| Finance Costs, Net | 136 | 135 |
| Foreign Exchange (Gain) Loss, Net | — | 99 |
All values are in US Dollars.
General and Administrative
Primary drivers of our general and administrative expenses for the three months ended March 31, 2025, were workforce costs and information technology related costs. The decrease in general and administrative expenses was primarily due to lower long-term incentive costs, as our closing common share price decreased from $21.79 on December 31, 2024 to $20.00 on March 31, 2025, compared with an increase from $22.08 on December 31, 2023 to $27.08 on March 31, 2024.
Finance Costs, Net
Net finance costs were consistent in the first quarter of 2025, compared with the same quarter in 2024. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The annualized weighted average interest rate on outstanding debt for the three months ended March 31, 2025, was 4.54 percent (2024 – 4.47 percent).
Foreign Exchange (Gain) Loss, Net
| ( millions) | 2025 | 2024 |
| Unrealized Foreign Exchange (Gain) Loss | 19 | 124 |
| Realized Foreign Exchange (Gain) Loss | (19) | (25) |
| — | 99 |
All values are in US Dollars.
For the three months ended March 31, 2025, unrealized and realized foreign exchange losses and gains were primarily related to working capital.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 29 |
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Income Taxes
| ( millions) | 2025 | 2024 |
| Current Tax | ||
| Canada | 279 | 346 |
| United States | — | 11 |
| Asia Pacific | 45 | 44 |
| Other International | 13 | 9 |
| Total Current Tax Expense (Recovery) | 337 | 410 |
| Deferred Tax Expense (Recovery) | (66) | (32) |
| 271 | 378 |
All values are in US Dollars.
For the three months ended March 31, 2025, we recorded current tax expense related to operations in all jurisdictions in which we operate except the U.S. The decrease in current tax expense is due to lower earnings compared with the same period in 2024.
The effective tax rate in the first three months of 2025 was 24.0 percent, consistent with the same period in the prior year (2024 – 24.3 percent). Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax basis and other legislation.
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.
| LIQUIDITY AND CAPITAL RESOURCES |
|---|
Our capital allocation framework enables us to preserve our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders.
We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents, and other sources of liquidity. Our other sources of liquidity include draws on our committed credit facility, draws on our uncommitted demand facilities and other corporate and financial opportunities, which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Ratings, Morningstar DBRS and Fitch Ratings. In the first quarter of 2025, we received a rating upgrade from Moody’s to Baa1 with a Stable outlook. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions.
| ( millions) | 2025 | 2024 |
| Cash From (Used In) | ||
| Operating Activities | 1,315 | 1,925 |
| Investing Activities | (1,348) | (1,135) |
| Net Cash Provided (Used) Before Financing Activities | (33) | 790 |
| Financing Activities | (294) | (677) |
| Effect of Foreign Exchange on Cash and Cash Equivalents | 2 | 60 |
| Increase (Decrease) in Cash and Cash Equivalents | (325) | 173 |
| March 31, | December 31, | |
| As at ( millions) | 2025 | 2024 |
| Cash and Cash Equivalents | 2,768 | 3,093 |
| Total Debt | 7,847 | 7,707 |
All values are in US Dollars.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 30 |
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Cash From (Used in) Operating Activities
In the first quarter of 2025, cash from operating activities decreased compared with the same period in 2024, primarily due to changes in non-cash working capital, combined with lower Operating Margin. The net change in non-cash working capital resulted in a use of cash of $861 million in the quarter, primarily due to decreased accounts payable and income taxes payable. In the first quarter of 2024, changes in non-cash working capital resulted in a use of cash of $269 million.
Cash From (Used in) Investing Activities
Cash used in investing activities increased in the first quarter of 2025 compared with 2024, primarily due to an increase in capital investment in the quarter.
Cash From (Used in) Financing Activities
Cash used in financing activities decreased in the first quarter of 2025 compared with 2024. The decrease was primarily due to the issuance of short-term borrowings, compared with a repayment in the first quarter of 2024, partially offset by the redemption of $200 million of preferred shares.
Working Capital
Working capital as at March 31, 2025, was $3.2 billion (December 31, 2024 – $3.1 billion). The increase was primarily driven by lower income taxes payable and accounts payable, partially offset by lower cash and inventories.
We anticipate that we will continue to meet our payment obligations as they come due.
Returns to Shareholders Target
Maintaining a strong balance sheet, with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle, is a key element of Cenovus’s capital allocation framework. Our Net Debt target is $4.0 billion and represents a Net Debt to Adjusted Funds Flow ratio target of approximately 1.0 times at the bottom of the commodity pricing cycle, which we believe is a WTI price of approximately US$45.00 per barrel.
We plan to return 100 percent of Excess Free Funds Flow to shareholders over time, while stewarding Net Debt near $4.0 billion. Working capital movements, foreign exchange rate changes and other factors may result in periods where shareholder returns are less than, or exceed, Excess Free Funds Flow and Net Debt is above or below our target. The allocation of Excess Free Funds Flow to shareholder returns may be accelerated, deferred or reallocated between quarters at Management’s discretion.
| ( millions) | 2025 | 2024 |
| Excess Free Funds Flow (1) | 373 | 832 |
| Target Return (2) | 373 | 416 |
| Shareholder Returns by way of: | ||
| Purchase of Common Shares Under NCIB | 62 | 165 |
| Preferred Share Redemption | 200 | — |
| Total | 262 | 165 |
All values are in US Dollars.
(1)Non-GAAP financial measure. See the Specified Financial Measures Advisory of this MD&A.
(2)The target return for the three months ended March 31, 2025, was 100 percent of Excess Free Funds Flow. The target return for the three months ended March 31, 2024, was 50 percent of Excess Free Funds Flow.
Short-Term Borrowings
There were no direct borrowings on our uncommitted demand facilities as at March 31, 2025, or December 31, 2024. As at March 31, 2025, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$225 million (C$323 million) (December 31, 2024 – US$120 million (C$173 million)).
Long-Term Debt, Including Current Portion
Long-term debt, including the current portion, as at March 31, 2025, was $7.5 billion (December 31, 2024 – $7.5 billion). We hold U.S. dollar denominated unsecured notes of US$3.8 billion (C$5.5 billion) (December 31, 2024 – US$3.8 billion (C$5.5 billion)) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2024 – $2.0 billion).
As at March 31, 2025, we were in compliance with all of the terms of our debt agreements, which includes the terms of our committed credit facility. We are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are below this limit.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 31 |
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Available Sources of Liquidity
The following sources of liquidity are available as at March 31, 2025:
| ($ millions) | Maturity | Amount Available |
|---|---|---|
| Cash and Cash Equivalents | n/a | 2,768 |
| Committed Credit Facility (1) | ||
| 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. (2) | n/a | 1,064 |
| WRB (3) | n/a | — |
(1)No amounts were drawn on the committed credit facility as at March 31, 2025 (December 31, 2024 – $nil).
(2)Represents amounts available for cash draws. Our uncommitted demand facilities include $1.7 billion, of which $1.4 billion may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at March 31, 2025, there were outstanding letters of credit aggregating to $368 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).
(3)Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at March 31, 2025, US$225 million (C$323 million) of this capacity was drawn (December 31, 2024 – US$120 million (C$173 million)).
Base Shelf Prospectus
We have a base shelf prospectus that allows us to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, Total Debt, the Net Debt to Adjusted EBITDA ratio, the Net Debt to Adjusted Funds Flow ratio and the Net Debt to Capitalization ratio. Refer to Note 10 of the interim Consolidated Financial Statements for further details.
We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholder’s Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA ratio, as net earnings (loss) before finance costs, net, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, (gain) loss on divestiture of assets, re-measurement of contingent payments and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength.
| As at | March 31, 2025 | December 31, 2024 |
|---|---|---|
| Net Debt to Adjusted EBITDA Ratio (times) | 0.5 | 0.5 |
| Net Debt to Adjusted Funds Flow Ratio (times) | 0.6 | 0.6 |
| Net Debt to Capitalization Ratio (percent) | 14 | 13 |
Our Net Debt to Adjusted EBITDA ratio and our Net Debt to Adjusted Funds Flow ratio targets are approximately 1.0 times and Net Debt at or below $4.0 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, steward working capital, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common or preferred shares for cancellation, issue new debt, or issue new shares.
Our Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio as at March 31, 2025, were consistent with December 31, 2024, as a result of higher Net Debt offset by higher Operating Margin. See the Operating and Financial Results section of this MD&A for more information on changes in Operating Margin and Net Debt.
Our Net Debt to Capitalization ratio as at March 31, 2025, increased compared with December 31, 2024, primarily due to higher Net Debt.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 32 |
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Share Capital and Stock-Based Compensation Plans
Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Our cumulative redeemable preferred shares series 1, 2 and 7 are listed on the TSX. On March 31, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares at a price of $25.00 per share, for a total of $200 million.
As at March 31, 2025, there were approximately 1,822.7 million common shares outstanding (December 31, 2024 – 1,825.0 million common shares) and 18.0 million preferred shares outstanding (December 31, 2024 – 26.0 million preferred shares). In the fourth quarter of 2024, Cenovus established an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans. For the three months ended March 31, 2025, the Trust purchased 2.8 million common shares for a total of $58 million and distributed 3.8 million common shares for a total of $81 million under the employee benefit plan. As at March 31, 2025, there were 1.0 million common shares held by the Trust (December 31, 2024 – 2.0 million common shares). Refer to Note 13 of the interim Consolidated Financial Statements for further details.
As at March 31, 2025, there were approximately 3.4 million Cenovus Warrants outstanding (December 31, 2024 – 3.6 million). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years from the date of issue at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 13 of the interim Consolidated Financial Statements for further details.
Refer to Note 15 of the interim Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows:
| As at May 5, 2025 | Units Outstanding<br><br>(thousands) | Units Exercisable<br><br>(thousands) |
|---|---|---|
| Common Shares | 1,813,779 | n/a |
| Cenovus Warrants | 3,411 | n/a |
| Series 1 First Preferred Shares | 10,740 | n/a |
| Series 2 First Preferred Shares | 1,260 | n/a |
| Series 7 First Preferred Shares | 6,000 | n/a |
| Stock Options | 12,107 | 6,033 |
| Other Stock-Based Compensation Plans | 20,095 | 1,988 |
Common Share Dividends
In the three months ended March 31, 2025, we paid base dividends of $327 million or $0.180 per common share (2024 – $262 million or $0.140 per common share).
On May 7, 2025, the Board declared a second quarter base dividend of $0.200 per common share, an increase of 11 percent from the first quarter dividend declared in February 2025. The dividend is payable on June 30, 2025, to common shareholders of record as at June 13, 2025. The increase is aligned with our long-term value proposition and our plans to sustainably grow our base dividend.
The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.
Cumulative Redeemable Preferred Share Dividends
In the three months ended March 31, 2025, dividends of $6 million were paid on the series 1, 2, 5 and 7 preferred shares. For the three months ended March 31, 2024, dividends of $9 million were paid on the series 1, 2, 3, 5 and 7 preferred shares.
On May 7, 2025, the Board declared a second quarter dividend on the series 1, 2 and 7 preferred shares for a total of $4 million, payable on June 30, 2025, to preferred shareholders of record as at June 13, 2025.
The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 33 |
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Share Repurchases
We have an NCIB program to purchase up to 127.5 million common shares from November 11, 2024, to November 10, 2025.
| 2025 | 2024 | |
| Common Shares Purchased and Cancelled Under NCIB (millions of common shares) | 3.0 | 7.4 |
| Weighted Average Price per Common Share () | 20.68 | 22.30 |
| Purchase of Common Shares Under NCIB ( millions) | 62 | 165 |
All values are in US Dollars.
From April 1, 2025, to May 5, 2025, the Company purchased an additional 10.9 million common shares for $178 million. As at May 5, 2025, the Company can further purchase up to 112.5 million common shares under the NCIB.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from our total commitments disclosed below. For further information, see Note 20 of the interim Consolidated Financial Statements.
Our total commitments were $27.5 billion as at March 31, 2025 (December 31, 2024 – $27.3 billion), of which $24.3 billion are for various transportation and storage commitments. Transportation commitments include $833 million that are subject to regulatory approval, or were approved, but are not yet in service. Terms are up to 20 years on commencement and should help align with the Company’s future transportation requirements.
As at March 31, 2025, our total commitments included commitments with HMLP of $1.8 billion related to long-term transportation and storage commitments (December 31, 2024 – $1.8 billion).
As at March 31, 2025, outstanding letters of credit issued as security for performance under certain contracts totaled $368 million (December 31, 2024 – $355 million).
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our interim Consolidated Financial Statements.
Transactions with Related Parties
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company charges HMLP for construction and management services, and incurs costs for the use of HMLP’s pipeline systems, as well as transportation and storage services.
The following table summarizes revenues and associated expenses related to HMLP:
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Revenues from Construction and Management Services | 29 | 31 |
| Transportation Expenses | 68 | 69 |
| RISK MANAGEMENT AND RISK FACTORS | ||
| --- |
For a full understanding of the risks that impact us, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2024 annual MD&A.
We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, our business, reputation, financial condition, results of operations and cash flows, which may, without limitation, reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 34 |
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| CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES | |
| --- |
Management is required to make estimates and assumptions, as well as use judgment, in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.
Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. A full list of the critical judgments used in applying accounting policies and key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2024.
| CONTROL ENVIRONMENT |
|---|
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at March 31, 2025. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at March 31, 2025.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
| ADVISORY |
|---|
Oil and Gas Information
Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “continue”, “could”, “estimate”, “expect”, “focus”, “may”, “objective”, “opportunities”, “plan”, “position”, “priority”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our five strategic objectives; shareholder value and returns; safety performance; sustainability; our commitment to the Pathways Alliance foundational project; maximizing value; disciplined capital allocation; Free Funds Flow; cash flow volatility and stability; price alignment and volatility management strategies; growing our base dividend; focus on cost and sustainability improvements; liquidity; growth of our base business; capital investment; our 2025 corporate guidance; realizing the full value of our integrated strategy; capitalizing on opportunities; Net Debt; allocating Excess Free Funds Flow; absolute and per share Free Funds Flow growth; our competitive, reliable downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; project execution; progression of our drilling program and production increases; growing our competitive advantages while operating safely and reliably monitoring market fundamentals and optimizing run rates at our refineries; safe and reliable operations; being best-in-class operators; maintaining a strong balance sheet; costs; margins; long-term value for Cenovus; downstream reliability and profitability; timing of completion of the West White Rose project; progressing growth projects,
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including the Narrows Lake tie-back to Christina Lake, the Foster Creek optimization, Lloydminster drilling program and Sunrise growth projects; our ESG focus areas; provision for income taxes; funding near-term cash requirements; credit ratings; meeting payment obligations; volatility of refined product prices; impact of U.S. tariffs on market benchmarks and Cenovus; Net Debt to Adjusted Funds Flow ratio; the Company’s capital allocation framework; capitalizing on opportunities throughout the commodity price cycle; Net Debt to Adjusted EBITDA ratio; maintaining sufficient liquidity; financial resilience; liabilities from legal proceedings; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar, the factors that affect such outlook, and the influences and effects on Cenovus.
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include, but are not limited to: forecast bitumen, crude oil and natural gas, NGLs, condensate and refined products prices, and light-heavy crude oil price differentials; the Company’s ability to realize the anticipated benefits of acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and crude throughput volumes and timing thereof; forecast prices and costs, projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, royalty regimes, interest rates, inflation, foreign exchange rates, global economic activity, competitive conditions and the supply and demand for bitumen, crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, third party actions, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long-term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the Company’s ability to use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange rate and interest rates; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments and development plans and dividends, including any increase thereto; our downstream business allowing us to be agile in our response to fluctuating demand for refined products and serving as a natural partial hedge in times of widening location and heavy oil differentials; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of its inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, NGLs from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and divestitures, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third-party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2025 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities.
2025 guidance dated December 11, 2024, and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$70.00 per barrel; WCS of US$56.00 per barrel; Differential WTI-WCS of US$14.00 per barrel; AECO natural gas prices of $2.05 per Mcf; Chicago 3-2-1 crack spread of US$18.50 per barrel; and an exchange rate of $0.72 US$/C$.
The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; the Company’s ability to successfully integrate acquired business with its own in a timely and cost effective manner; unforeseen or underestimated liabilities associated with acquisitions; risks associated with acquisitions and divestitures; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of ESG targets and ambitions and the commercial viability and scalability of ESG strategies and related technology and products; the development and execution of implementing strategies to meet ESG targets and ambitions; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; the Company’s ability to integrate upstream and
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downstream operations to help mitigate the impact of volatility in light-heavy crude oil differentials and contribute to its net earnings; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity being sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential remaining largely tied to global supply factors and heavy crude processing capacity; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of the Company’s outlook for commodity prices, the impact of tariffs and responses thereto, currency and interest rates; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA and Net Debt to Adjusted Funds Flow; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; the ability to complete and optimize drilling, completion, tie in and infrastructure projects; the ability of the Company to ramp up activities at its refineries on its anticipated timelines; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; tax audits and reassessments; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and refining processes; the occurrence of unexpected events resulting in operational interruptions, including at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics and pandemics; and catastrophic events, including, but not limited to, war, adverse sea conditions, extreme weather events, natural disasters, acts of activism, vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and downstream operations and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying refining or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system or storage capacity; availability of, and the Company’s ability to attract and retain, critical and diverse talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communities; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.
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Except as required by applicable securities laws, Cenovus disclaims any intention or obligation to publicly update or revise any forward‐looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in the Company’s most recently filed Annual MD&A, and the risk factors described in other documents the Company files from time to time with securities regulatory authorities in Canada, available on SEDAR+ at sedarplus.ca, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Company’s website at cenovus.com.
Information on or connected to the Company’s website at cenovus.com does not form part of this MD&A unless expressly incorporated by reference herein.
ABBREVIATIONS AND DEFINITIONS
Abbreviations
The following abbreviations and definitions are used in this document:
| Crude Oil and NGLs | Natural Gas | Other | |||
|---|---|---|---|---|---|
| bbl | barrel | Mcf | thousand cubic feet | BOE | barrel of oil equivalent |
| Mbbls/d | thousand barrels per day | MMcf | million cubic feet | MBOE/d | thousand barrels of oil <br> equivalent per day |
| WCS | Western Canadian Select | MMcf/d | million cubic feet per day | DD&A | depreciation, depletion and<br> amortization |
| WTI | West Texas Intermediate | ESG | environmental, social and <br> governance | ||
| GHG | greenhouse gas | ||||
| FPSO | floating production, storage and <br> offloading unit | ||||
| NCIB | normal course issuer bid | ||||
| AECO | Alberta Energy Company | ||||
| NYMEX | New York Mercantile Exchange | ||||
| OPEC | Organization of Petroleum<br> Exporting Countries | ||||
| OPEC+ | OPEC and a group of 11 <br> non-OPEC members | ||||
| USGC | U.S. Gulf Coast | ||||
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 38 | ||||
| --- | --- |
SPECIFIED FINANCIAL MEASURES
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS Accounting Standards including Operating Margin, Operating Margin by asset, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Realized Sales Price, Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses, Netbacks (including the total Netback per BOE), Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture.
These measures may not be comparable to similar measures presented by other issuers. These measures are described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation, or as a substitute for, measures prepared in accordance with IFRS Accounting Standards. The definition and reconciliation, if applicable, of each specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results section of this MD&A. Refer to the Specified Financial Measures Advisory of the relevant period’s MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow for prior period information from 2024 that is not found below.
Non-GAAP Financial Measures and Non-GAAP Ratios
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for upstream or downstream operations are specified financial measures. These are used to provide a consistent measure of the cash-generating performance of our operations and assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending expenses, operating expenses, plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. The following tables provide a reconciliation to our interim Consolidated Financial Statements.
Operating Margin
| Three Months Ended March 31, | |||||||
|---|---|---|---|---|---|---|---|
| 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||
| ($ millions) | Upstream (1) | Downstream (1) | Total | ||||
| Gross Sales | |||||||
| External Sales (2) | 6,798 | 5,747 | 7,407 | 8,063 | 14,205 | 13,810 | |
| Intersegment Sales | 2,454 | 2,117 | 298 | 170 | 2,752 | 2,287 | |
| 9,252 | 7,864 | 7,705 | 8,233 | 16,957 | 16,097 | ||
| Royalties | (906) | (747) | — | — | (906) | (747) | |
| Revenues (2) | 8,346 | 7,117 | 7,705 | 8,233 | 16,051 | 15,350 | |
| Expenses | |||||||
| Purchased Product (2) | 1,167 | 771 | 7,082 | 6,885 | 8,249 | 7,656 | |
| Transportation and Blending | 3,247 | 2,811 | — | — | 3,247 | 2,811 | |
| Operating | 893 | 898 | 854 | 787 | 1,747 | 1,685 | |
| Realized (Gain) Loss on Risk Management | (9) | 6 | 6 | 1 | (3) | 7 | |
| Operating Margin | 3,048 | 2,631 | (237) | 560 | 2,811 | 3,191 |
(1)Found in Note 1 of the interim Consolidated Financial Statements.
(2)Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 39 |
|---|
Operating Margin by Asset
| ( millions) | Atlantic | Asia Pacific | Offshore (1) |
| Gross Sales | 146 | 305 | 451 |
| Royalties | (2) | (23) | (25) |
| Revenues | 144 | 282 | 426 |
| Expenses | |||
| Transportation and Blending | 6 | — | 6 |
| Operating | 64 | 25 | 89 |
| Operating Margin | 74 | 257 | 331 |
All values are in US Dollars.
| ( millions) | Atlantic | Asia Pacific | Offshore (1) |
| Gross Sales | 42 | 315 | 357 |
| Royalties | (2) | (24) | (26) |
| Revenues | 40 | 291 | 331 |
| Expenses | |||
| Transportation and Blending | — | — | — |
| Operating | 57 | 28 | 85 |
| Operating Margin | (17) | 263 | 246 |
All values are in US Dollars.
(1)Found in Note 1 of the interim Consolidated Financial Statements.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations, in total and on a per-share basis. Adjusted Funds Flow is defined as cash from (used in) operating activities excluding settlement of decommissioning liabilities and net change in operating non-cash working capital. Operating non-cash working capital is composed of accounts receivable and accrued revenues, income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), accounts payable and accrued liabilities, and income tax payable. Adjusted Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares. Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of shares.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities, excluding settlement of decommissioning liabilities and net change in operating non-cash working capital, minus capital investment.
Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds Flow minus base dividends paid on common shares, dividends paid on preferred shares, net purchases of common shares under the employee benefit plan, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and expenditures for acquisitions net of cash acquired, plus proceeds from, or payments related to, divestitures.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 40 | |
|---|---|---|
| --- | --- | --- |
| ( millions) | 2025 | 2024 |
| Cash From (Used in) Operating Activities | 1,315 | 1,925 |
| (Add) Deduct: | ||
| Settlement of Decommissioning Liabilities | (36) | (48) |
| Net Change in Non-Cash Working Capital | (861) | (269) |
| Adjusted Funds Flow | 2,212 | 2,242 |
| Capital Investment | 1,229 | 1,036 |
| Free Funds Flow | 983 | 1,206 |
| Add (Deduct): | ||
| Base Dividends Paid on Common Shares | (327) | (262) |
| Dividends Paid on Preferred Shares | (6) | (9) |
| Purchase of Common Shares Under Employee Benefit Plan | (58) | — |
| Settlement of Decommissioning Liabilities | (36) | (48) |
| Principal Repayment of Leases | (83) | (70) |
| Acquisitions, Net of Cash Acquired | (100) | (10) |
| Proceeds From Divestitures | — | 25 |
| Excess Free Funds Flow | 373 | 832 |
All values are in US Dollars.
Gross Margin, Adjusted Gross Margin, Adjusted Refining Margin and Adjusted Market Capture
Gross Margin and Adjusted Gross Margin are non-GAAP financial measures that are used to evaluate the performance of our downstream operations. We define Gross Margin as revenues less purchased product and Adjusted Gross Margin as revenues less purchased product, excluding the impact of inventory holding gains or losses.
Inventory holding gains or losses reflects the difference between the cost of volumes produced at current-period costs, which is an indication of current market conditions, and the cost of volumes produced under the FIFO or weighted average cost basis as required by IFRS Accounting Standards, which generally reflects the market conditions at the time feedstock was purchased. The purchase and sale of inventories creates a timing difference that could be anywhere from several weeks to several months. This measure is an estimate of the impact of current-period costs to FIFO or weighted average cost, and assumes that all opening volumes are sold in the current period. Cenovus uses inventory holding gains or losses to analyze the performance of our assets and increase comparability with refining peers.
Adjusted Refining Margin and Adjusted Market Capture contain non-GAAP financial measures. Adjusted Refining Margin is used to evaluate our downstream operations after adjusting for inventory holding gains or losses. Adjusted Market Capture is used in our U.S. Refining segment to provide an indication of margin captured relative to what was available in the market based on widely-used benchmarks. These measures are useful to consistently measure the performance of our downstream operations.
We define Adjusted Refining Margin as Adjusted Gross Margin divided by total processed inputs and Adjusted Market Capture as Adjusted Refining Margin divided by the weighted average 3-2-1 market benchmark crack, net of RINs, expressed as a percentage. The weighted average crack spread, net of RINs, is calculated on Cenovus’s operable capacity-weighted average of the Chicago and Group 3 3-2-1 benchmark market crack spreads, net of RINs.
We previously disclosed Refining Margin and Market Capture, which did not exclude the effect of inventory holding gains or losses. We have added Adjusted Gross Margin, and replaced our definitions of Refining Margin and Market Capture to exclude the impact of inventory holding gains or losses. We believe these changes provide more comparability and accuracy when measuring the performance of our downstream operations.
Comparative period information has been provided below for these new metrics.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 41 |
|---|
Canadian Refining
| Three Months Ended March 31, 2025 | |||
|---|---|---|---|
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining (2) |
| Revenues | 1,221 | 61 | 1,282 |
| Purchased Product | 1,037 | 39 | 1,076 |
| Gross Margin | 184 | 22 | 206 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | 3 | — | 3 |
| Adjusted Gross Margin | 187 | 22 | 209 |
| Total Processed Inputs (Mbbls/d) | 119.5 | ||
| Adjusted Refining Margin ($/bbl) | 17.33 |
(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.
| Three Months Ended March 31, 2024 | |||
|---|---|---|---|
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining (2) |
| Revenues | 1,249 | 83 | 1,332 |
| Purchased Product | 1,024 | 63 | 1,087 |
| Gross Margin | 225 | 20 | 245 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | (24) | 1 | (23) |
| Adjusted Gross Margin | 201 | 21 | 222 |
| Total Processed Inputs (Mbbls/d) | 108.8 | ||
| Adjusted Refining Margin ($/bbl) | 20.23 |
(1)Includes ethanol operations and crude-by-rail operations.
(2)Revenues and purchased product are found in Note 1 of the interim Consolidated Financial Statements.
| Three Months Ended December 31, 2024 | |||
|---|---|---|---|
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining |
| Revenues | 1,207 | 56 | 1,263 |
| Purchased Product | 1,032 | 36 | 1,068 |
| Gross Margin | 175 | 20 | 195 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | — | — | — |
| Adjusted Gross Margin | 175 | 20 | 195 |
| Total Processed Inputs (Mbbls/d) | 112.1 | ||
| Adjusted Refining Margin ($/bbl) | 16.96 |
(1)Includes ethanol operations and crude-by-rail operations.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 42 | ||
|---|---|---|---|
| Three Months Ended September 30, 2024 | |||
| --- | --- | --- | --- |
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining |
| Revenues | 1,493 | 87 | 1,580 |
| Purchased Product | 1,292 | 61 | 1,353 |
| Gross Margin | 201 | 26 | 227 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | 15 | 1 | 16 |
| Adjusted Gross Margin | 216 | 27 | 243 |
| Total Processed Inputs (Mbbls/d) | 106.4 | ||
| Adjusted Refining Margin ($/bbl) | 22.17 |
(1)Includes ethanol operations and crude-by-rail operations.
| Three Months Ended June 30, 2024 | |||
|---|---|---|---|
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining |
| Revenues | 1,065 | 70 | 1,135 |
| Purchased Product | 930 | 45 | 975 |
| Gross Margin | 135 | 25 | 160 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | 5 | — | 5 |
| Adjusted Gross Margin | 140 | 25 | 165 |
| Total Processed Inputs (Mbbls/d) | 58.9 | ||
| Adjusted Refining Margin ($/bbl) | 26.23 |
(1)Includes ethanol operations and crude-by-rail operations.
| Year Ended December 31, 2024 | |||
|---|---|---|---|
| ($ millions, except where indicated) | Lloydminster Upgrader and Lloydminster Refinery Total | Other (1) | Total Canadian<br><br>Refining |
| Revenues | 5,014 | 296 | 5,310 |
| Purchased Product | 4,278 | 205 | 4,483 |
| Gross Margin | 736 | 91 | 827 |
| Add (Deduct): | |||
| Inventory Holding (Gain) Loss | (4) | 2 | (2) |
| Adjusted Gross Margin | 732 | 93 | 825 |
| Total Processed Inputs (Mbbls/d) | 96.6 | ||
| Adjusted Refining Margin ($/bbl) | 20.72 |
(1)Includes ethanol operations and crude-by-rail operations.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 43 |
|---|
U.S. Refining
| ( millions, except where indicated) | 2025 | 2024 |
| Revenues (1) | 6,423 | 6,901 |
| Purchased Product (1) | 6,006 | 5,798 |
| Gross Margin | 417 | 1,103 |
| Add (Deduct): | ||
| Inventory Holding (Gain) Loss | 23 | (194) |
| Adjusted Gross Margin | 440 | 909 |
| Total Processed Inputs (Mbbls/d) | 581.0 | 575.0 |
| Adjusted Refining Margin (/bbl) | 8.41 | 17.37 |
| Operable Capacity (Mbbls/d) | 612.3 | 612.3 |
| Operable Capacity by Regional Benchmark (percent) | ||
| Chicago 3-2-1 Crack Spread Weighting | 81 | 81 |
| Group 3 3-2-1 Crack Spread Weighting | 19 | 19 |
| Benchmark Prices and Exchange Rate | ||
| Chicago 3-2-1 Crack Spread (US/bbl) | 13.68 | 17.45 |
| Group 3 3-2-1 Crack Spread (US/bbl) | 16.48 | 17.50 |
| RINs (US/bbl) | 4.76 | 3.68 |
| US per C1 – Average | 0.697 | 0.741 |
| Weighted Average Crack Spread, Net of RINs (/bbl) | 13.58 | 18.59 |
| Adjusted Market Capture (percent) | 62 | 93 |
All values are in US Dollars.
(1)Found in Note 1 of the interim Consolidated Financial Statements. Comparative period reflects certain revisions. See the Prior Period Revisions section of this MD&A for further details.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 44 | |||
|---|---|---|---|---|
| Three Months Ended | Twelve Months Ended | |||
| --- | --- | --- | --- | --- |
| ($ millions, except where indicated) | December 31, 2024 | September 30, 2024 | June 30,<br>2024 | December 31, 2024 |
| Revenues (1) | 6,574 | 7,218 | 7,615 | 28,308 |
| Purchased Product (1) | 6,296 | 6,854 | 6,821 | 25,769 |
| Gross Margin | 278 | 364 | 794 | 2,539 |
| Add (Deduct): | ||||
| Inventory Holding (Gain) Loss | 45 | 209 | (83) | (23) |
| Adjusted Gross Margin | 323 | 573 | 711 | 2,516 |
| Total Processed Inputs (Mbbls/d) | 588.4 | 568.0 | 594.0 | 581.4 |
| Adjusted Refining Margin ($/bbl) | 5.98 | 10.97 | 13.15 | 11.83 |
| Operable Capacity (Mbbls/d) | 612.3 | 612.3 | 612.3 | 612.3 |
| Operable Capacity by Regional Benchmark (percent) | ||||
| Chicago 3-2-1 Crack Spread Weighting | 81 | 81 | 81 | 81 |
| Group 3 3-2-1 Crack Spread Weighting | 19 | 19 | 19 | 19 |
| Benchmark Prices and Exchange Rate | ||||
| Chicago 3-2-1 Crack Spread (US$/bbl) | 12.12 | 18.62 | 18.76 | 16.74 |
| Group 3 3-2-1 Crack Spread (US$/bbl) | 12.66 | 18.95 | 18.13 | 16.81 |
| RINs (US$/bbl) | 4.02 | 3.89 | 3.39 | 3.74 |
| US$ per C$1 – Average | 0.715 | 0.733 | 0.731 | 0.730 |
| Weighted Average Crack Spread, Net of RINs ($/bbl) | 11.47 | 20.18 | 20.86 | 17.82 |
| Adjusted Market Capture (percent) | 52 | 54 | 63 | 67 |
(1)Comparative periods reflect certain revisions. See the Prior Period Revisions section of this MD&A for further details.
Netback Reconciliations and Realized Sales Price
Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is substantially aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netback is defined as gross sales less royalties, transportation and blending, and operating expenses. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. Condensate or butane (diluent) is blended with crude oil to transport it to market. Netback per barrel of oil equivalent contains a non-GAAP measure. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Per-unit measures are divided by sales volumes.
Realized Sales Price contains a non-GAAP measure. It includes our gross sales, purchased diluent costs and profit from optimization activities, such as cogeneration, third-party processing and trading. Conventional, Offshore and Asia Pacific Per-Unit Operating Expenses contain non-GAAP measures. In the three months ended March 31, 2025, modifications were made to our Conventional Netback to include our 30 percent equity interest in the Duvernay joint venture. These modifications resulted in minor adjustments that are captured in the netback calculation on a prospective basis. Offshore and Asia Pacific operating expenses, as used in the basis of our Netback calculations, reflect our 40 percent equity interest in the HCML joint venture. The Duvernay and HCML joint ventures are accounted for using the equity method in the interim Consolidated Financial Statements.
The following tables provide a reconciliation of Netback to Operating Margin found in our interim Consolidated Financial Statements.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 45 |
|---|
Oil Sands
| Basis of Netback Calculation | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended March 31, 2025 ($ millions) | Foster Creek | Christina Lake | Sunrise | Lloydminster (1) | Total Oil Sands (2) | ||||||||
| Gross Sales | 1,717 | 1,619 | 389 | 910 | 4,635 | ||||||||
| Royalties | (342) | (398) | (20) | (99) | (859) | ||||||||
| Revenues | 1,375 | 1,221 | 369 | 811 | 3,776 | ||||||||
| Expenses | |||||||||||||
| Purchased Product | — | — | — | — | — | ||||||||
| Transportation and Blending | 312 | 132 | 80 | 39 | 563 | ||||||||
| Operating | 193 | 189 | 78 | 213 | 673 | ||||||||
| Netback | 870 | 900 | 211 | 559 | 2,540 | ||||||||
| Realized (Gain) Loss on Risk Management | (8) | ||||||||||||
| Operating Margin | 2,548 | Basis of Netback Calculation | Adjustments | ||||||||||
| --- | --- | --- | --- | --- | --- | --- | |||||||
| Three Months Ended March 31, 2025 ($ millions) | Total Oil Sands (2) | Condensate | Third-party Sourced | Other (3) | Total Oil Sands (4) | ||||||||
| Gross Sales | 4,635 | 2,575 | 553 | 94 | 7,857 | ||||||||
| Royalties | (859) | — | — | (2) | (861) | ||||||||
| Revenues | 3,776 | 2,575 | 553 | 92 | 6,996 | ||||||||
| Expenses | |||||||||||||
| Purchased Product | — | — | 553 | 79 | 632 | ||||||||
| Transportation and Blending | 563 | 2,575 | — | 13 | 3,151 | ||||||||
| Operating | 673 | — | — | 4 | 677 | ||||||||
| Netback | 2,540 | — | — | (4) | 2,536 | ||||||||
| Realized (Gain) Loss on Risk Management | (8) | — | — | — | (8) | ||||||||
| Operating Margin | 2,548 | — | — | (4) | 2,544 |
(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(2)Includes bitumen and heavy oil.
(3)Other includes construction, transportation and blending.
(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
| Basis of Netback Calculation | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended March 31, 2024 ($ millions) | Foster Creek | Christina Lake | Sunrise | Lloydminster (1) | Total Oil Sands (2) | ||||||||
| Gross Sales | 1,356 | 1,474 | 340 | 850 | 4,020 | ||||||||
| Royalties | (293) | (339) | (11) | (54) | (697) | ||||||||
| Revenues | 1,063 | 1,135 | 329 | 796 | 3,323 | ||||||||
| Expenses | |||||||||||||
| Purchased Product | — | — | — | — | — | ||||||||
| Transportation and Blending | 181 | 119 | 71 | 45 | 416 | ||||||||
| Operating | 191 | 188 | 65 | 211 | 655 | ||||||||
| Netback | 691 | 828 | 193 | 540 | 2,252 | ||||||||
| Realized (Gain) Loss on Risk Management | 13 | ||||||||||||
| Operating Margin | 2,239 | Basis of Netback Calculation | Adjustments | ||||||||||
| --- | --- | --- | --- | --- | --- | --- | |||||||
| Three Months Ended March 31, 2024 ($ millions) | Total Oil Sands (2) | Condensate | Third-party Sourced | Other (3) | Total Oil Sands (4) | ||||||||
| Gross Sales | 4,020 | 2,305 | 213 | 90 | 6,628 | ||||||||
| Royalties | (697) | — | — | — | (697) | ||||||||
| Revenues | 3,323 | 2,305 | 213 | 90 | 5,931 | ||||||||
| Expenses | |||||||||||||
| Purchased Product | — | — | 213 | 76 | 289 | ||||||||
| Transportation and Blending | 416 | 2,305 | — | 12 | 2,733 | ||||||||
| Operating | 655 | — | — | 5 | 660 | ||||||||
| Netback | 2,252 | — | — | (3) | 2,249 | ||||||||
| Realized (Gain) Loss on Risk Management | 13 | — | — | — | 13 | ||||||||
| Operating Margin | 2,239 | — | — | (3) | 2,236 |
(1)Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
(2)Includes bitumen and heavy oil.
(3)Other includes construction, transportation and blending.
(4)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 46 |
|---|
Conventional
| Basis of Netback Calculation | Adjustments | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended March 31, 2025 ($ millions) | Conventional (1) | Third-party Sourced | Other (1) (2) | Conventional (3) | ||||||
| Gross Sales | 379 | 534 | 31 | 944 | ||||||
| Royalties | (20) | — | — | (20) | ||||||
| Revenues | 359 | 534 | 31 | 924 | ||||||
| Expenses | ||||||||||
| Purchased Product | — | 534 | 1 | 535 | ||||||
| Transportation and Blending | 61 | — | 29 | 90 | ||||||
| Operating | 122 | — | 5 | 127 | ||||||
| Netback | 176 | — | (4) | 172 | ||||||
| Realized (Gain) Loss on Risk Management | (1) | — | — | (1) | ||||||
| Operating Margin | 177 | — | (4) | 173 | Basis of Netback Calculation | Adjustments | ||||
| --- | --- | --- | --- | --- | ||||||
| Three Months Ended March 31, 2024 ($ millions) | Conventional | Third-party Sourced | Other (2) | Conventional (3) | ||||||
| Gross Sales | 362 | 482 | 35 | 879 | ||||||
| Royalties | (24) | — | — | (24) | ||||||
| Revenues | 338 | 482 | 35 | 855 | ||||||
| Expenses | ||||||||||
| Purchased Product | — | 482 | — | 482 | ||||||
| Transportation and Blending | 51 | — | 27 | 78 | ||||||
| Operating | 143 | — | 10 | 153 | ||||||
| Netback | 144 | — | (2) | 142 | ||||||
| Realized (Gain) Loss on Risk Management | (7) | — | — | (7) | ||||||
| Operating Margin | 151 | — | (2) | 149 |
(1)Inclusive of revenues and expenses related to the Duvernay joint venture.
(2)Other includes the reclassification of costs primarily related to third-party cogeneration, processing and transportation.
(3)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
Offshore
| Basis of Netback Calculation | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Three Months Ended March 31, 2025 ($ millions) | Atlantic | China | Indonesia (1) | Total<br>Asia Pacific | Total Offshore | Equity Adjustment (1) | Total Offshore (2) | ||||||||
| Gross Sales | 146 | 305 | 89 | 394 | 540 | (89) | 451 | ||||||||
| Royalties | (2) | (23) | (27) | (50) | (52) | 27 | (25) | ||||||||
| Revenues | 144 | 282 | 62 | 344 | 488 | (62) | 426 | ||||||||
| Expenses | |||||||||||||||
| Purchased Product | — | — | — | — | — | — | — | ||||||||
| Transportation and Blending | 6 | — | — | — | 6 | — | 6 | ||||||||
| Operating | 64 | 23 | 15 | 38 | 102 | (13) | 89 | ||||||||
| Netback | 74 | 259 | 47 | 306 | 380 | (49) | 331 | ||||||||
| Realized (Gain) Loss on Risk Management | — | — | — | ||||||||||||
| Operating Margin | 380 | (49) | 331 | Basis of Netback Calculation | |||||||||||
| --- | --- | --- | --- | --- | --- | --- | |||||||||
| Three Months Ended March 31, 2024 ($ millions) | Atlantic | China | Indonesia (1) | Total<br>Asia Pacific | Total Offshore | Equity Adjustment (1) | Total Offshore (2) | ||||||||
| Gross Sales | 42 | 315 | 68 | 383 | 425 | (68) | 357 | ||||||||
| Royalties | (2) | (24) | (5) | (29) | (31) | 5 | (26) | ||||||||
| Revenues | 40 | 291 | 63 | 354 | 394 | (63) | 331 | ||||||||
| Expenses | |||||||||||||||
| Purchased Product | — | — | — | — | — | — | — | ||||||||
| Transportation and Blending | — | — | — | — | — | — | — | ||||||||
| Operating | 57 | 25 | 15 | 40 | 97 | (12) | 85 | ||||||||
| Netback | (17) | 266 | 48 | 314 | 297 | (51) | 246 | ||||||||
| Realized (Gain) Loss on Risk Management | — | — | — | ||||||||||||
| Operating Margin | 297 | (51) | 246 |
(1)Revenues and expenses related to the HCML joint venture.
(2)These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 47 |
|---|
Upstream Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:
| Three Months Ended March 31, | |||
|---|---|---|---|
| (MBOE/d) | 2025 | 2024 | |
| Oil Sands (2) | |||
| Foster Creek | 218.6 | 194.0 | |
| Christina Lake | 239.6 | 242.2 | |
| Sunrise | 49.5 | 42.3 | |
| Lloydminster | 128.1 | 128.4 | |
| Total Oil Sands | 635.8 | 606.9 | |
| Conventional (3) | 123.9 | 120.7 | |
| Offshore | |||
| Atlantic | 15.8 | 3.9 | |
| Asia Pacific | |||
| China | 42.0 | 43.7 | |
| Indonesia (4) | 15.2 | 14.0 | |
| Total Asia Pacific | 57.2 | 57.7 | |
| Total Offshore | 73.0 | 61.6 |
(1)Sales volumes exclude the impact of purchased condensate.
(2)Includes bitumen and heavy crude oil sales.
(3)For the three months ended March 31, 2025, reported sales volumes reflect Cenovus’s 30 percent equity interest in the Duvernay joint venture.
(4)Reported sales volumes reflect Cenovus’s 40 percent equity interest in the HCML joint venture.
Other Specified Financial Measures
Per-Unit Operating Expenses
Per-unit operating expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. Our upstream per-unit operating expenses are defined as total operating expenses divided by sales volumes and are part of our Netback calculation, which can be found above.
We define Canadian Refining per-unit operating expenses as total operating expenses from the Upgrader, the Lloydminster Refinery and the commercial fuels business, divided by total processed inputs. We define U.S. Refining per-unit operating expenses as operating expenses divided by total processed inputs.
Per-Unit Transportation Expenses
Per-unit transportation expenses are specified financial measures used to measure transportation expenses on a per-unit basis in our upstream segments. We define per-unit transportation expenses as the total transportation expenses divided by sales volumes. Our upstream per-unit transportation expenses are part of the transportation and blending line in our Netback calculation, which can be found above.
Per-Unit Depreciation, Depletion and Amortization
Per-unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define per-unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties, and the associated decommissioning costs, divided by sales volumes.
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 48 |
|---|---|
| PRIOR PERIOD REVISIONS | |
| --- |
In December 2024, it was identified that certain transactions in the U.S Refining segment were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the nine months ended September 30, 2024. The prior periods were revised to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:
| U.S. Refining Segment | Consolidated | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended <br>March 31, 2024 | Previously Reported | Revisions | Revised Balance | Previously Reported | Revisions | Revised Balance | ||||||||
| Revenues | 7,235 | (334) | 6,901 | 13,397 | (334) | 13,063 | ||||||||
| Purchased Product | 6,132 | (334) | 5,798 | 6,133 | (334) | 5,799 | ||||||||
| Transportation and Blending | — | — | — | 2,575 | — | 2,575 | ||||||||
| Purchased Product, Transportation <br> and Blending | 6,132 | (334) | 5,798 | 8,708 | (334) | 8,374 | ||||||||
| 1,103 | — | 1,103 | 4,689 | — | 4,689 | U.S. Refining Segment | Consolidated | |||||||
| --- | --- | --- | --- | --- | --- | --- | ||||||||
| For the three months ended <br>June 30, 2024 | Previously Reported | Revisions | Revised Balance | Previously Reported | Revisions | Revised Balance | ||||||||
| Revenues | 7,918 | (303) | 7,615 | 14,885 | (303) | 14,582 | ||||||||
| Purchased Product | 7,124 | (303) | 6,821 | 7,184 | (303) | 6,881 | ||||||||
| Transportation and Blending | — | — | — | 2,865 | — | 2,865 | ||||||||
| Purchased Product, Transportation <br> and Blending | 7,124 | (303) | 6,821 | 10,049 | (303) | 9,746 | ||||||||
| 794 | — | 794 | 4,836 | — | 4,836 | U.S. Refining Segment | Consolidated | |||||||
| --- | --- | --- | --- | --- | --- | --- | ||||||||
| For the three months ended <br>September 30, 2024 | Previously Reported | Revisions | Revised Balance | Previously Reported | Revisions | Revised Balance | ||||||||
| Revenues | 7,648 | (430) | 7,218 | 14,249 | (430) | 13,819 | ||||||||
| Purchased Product | 7,284 | (430) | 6,854 | 7,556 | (430) | 7,126 | ||||||||
| Transportation and Blending | — | — | — | 2,489 | — | 2,489 | ||||||||
| Purchased Product, Transportation <br> and Blending | 7,284 | (430) | 6,854 | 10,045 | (430) | 9,615 | ||||||||
| 364 | — | 364 | 4,204 | — | 4,204 | |||||||||
| Cenovus Energy Inc. – Q1 2025 Management's Discussion and Analysis | 49 | |||||||||||||
| --- | --- |
Document
Exhibit 99.3
Cenovus Energy Inc.
Interim Consolidated Financial Statements (unaudited)
For the Period Ended March 31, 2025
(Canadian Dollars)
CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
| For the period ended March 31, 2025 | |||
|---|---|---|---|
| TABLE OF CONTENTS | |||
| --- | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED) | 3 | |
| --- | --- | ||
| CONSOLIDATED BALANCE SHEETS (UNAUDITED) | 4 | ||
| CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED) | 5 | ||
| CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) | 6 | ||
| NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) | 7 | ||
| 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES | 7 | ||
| 2.BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE | 12 | ||
| 3. FINANCE COSTS, NET | 12 | ||
| 4. FOREIGN EXCHANGE (GAIN) LOSS, NET | 12 | ||
| 5. INCOME TAXES | 12 | ||
| 6. PER SHARE AMOUNTS | 13 | ||
| 7. EXPLORATION AND EVALUATION ASSETS, NET | 14 | ||
| 8. PROPERTY, PLANT AND EQUIPMENT, NET | 14 | ||
| 9. LEASES | 15 | ||
| 10. DEBT AND CAPITAL STRUCTURE | 15 | ||
| 11. DECOMMISSIONING LIABILITIES | 18 | ||
| 12. OTHER LIABILITIES | 18 | ||
| 13. SHARE CAPITAL AND WARRANTS | 18 | ||
| 14. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | 20 | ||
| 15. STOCK-BASED COMPENSATION PLANS | 20 | ||
| 16. RELATED PARTY TRANSACTIONS | 21 | ||
| 17. FINANCIAL INSTRUMENTS | 22 | ||
| 18. RISK MANAGEMENT | 23 | ||
| 19. SUPPLEMENTARY CASH FLOW INFORMATION | 25 | ||
| 20. COMMITMENTS AND CONTINGENCIES | 26 | ||
| 21. PRIOR PERIOD REVISIONS | 27 | ||
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 2 | ||
| --- | --- | ||
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited) | |||
| --- |
For the period ended March 31,
($ millions, except per share amounts)
| Three Months Ended | ||||
|---|---|---|---|---|
| Notes | 2025 | 2024 | ||
| Revenues (1) | 1 | 13,299 | 13,063 | |
| Expenses | 1 | |||
| Purchased Product, Transportation and Blending (1) | 8,870 | 8,374 | ||
| Operating | 1,629 | 1,555 | ||
| (Gain) Loss on Risk Management | 17 | 15 | 41 | |
| Depreciation, Depletion, Amortization and Exploration Expense | 8,9 | 1,319 | 1,202 | |
| (Income) Loss From Equity-Accounted Affiliates | 7 | (9) | ||
| General and Administrative | 197 | 246 | ||
| Finance Costs, Net | 3 | 136 | 135 | |
| Integration, Transaction and Other Costs | 2 | 33 | ||
| Foreign Exchange (Gain) Loss, Net | 4 | — | 99 | |
| (Gain) Loss on Divestiture of Assets | — | (105) | ||
| Re-measurement of Contingent Payments | — | 28 | ||
| Other (Income) Loss, Net | (6) | (90) | ||
| Earnings (Loss) Before Income Tax | 1,130 | 1,554 | ||
| Income Tax Expense (Recovery) | 5 | 271 | 378 | |
| Net Earnings (Loss) | 859 | 1,176 | ||
| Other Comprehensive Income (Loss), Net of Tax | 14 | |||
| Items That Will not be Reclassified to Profit or Loss: | ||||
| Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits | 2 | 14 | ||
| Change in the Fair Value of Equity Instruments at FVOCI (2) | 17 | (2) | — | |
| Items That may be Reclassified to Profit or Loss: | ||||
| Foreign Currency Translation Adjustment | (10) | 268 | ||
| Total Other Comprehensive Income (Loss), Net of Tax | (10) | 282 | ||
| Comprehensive Income (Loss) | 849 | 1,458 | ||
| Net Earnings (Loss) Per Common Share ($) | 6 | |||
| Basic | 0.47 | 0.62 | ||
| Diluted | 0.47 | 0.62 |
(1)Comparative period reflects certain revisions. See Note 21.
(2)Fair value through other comprehensive income (loss) (“FVOCI”).
See accompanying Notes to the interim Consolidated Financial Statements (unaudited).
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 3 |
|---|---|
| CONSOLIDATED BALANCE SHEETS (unaudited) | |
| --- |
As at
($ millions)
| March 31, | December 31, | ||
|---|---|---|---|
| Notes | 2025 | 2024 | |
| Assets | |||
| Current Assets | |||
| Cash and Cash Equivalents | 2,768 | 3,093 | |
| Accounts Receivable and Accrued Revenues | 2,711 | 2,614 | |
| Income Tax Receivable | 308 | 231 | |
| Inventories | 4,316 | 4,496 | |
| Total Current Assets | 10,103 | 10,434 | |
| Restricted Cash | 244 | 241 | |
| Exploration and Evaluation Assets, Net | 1,7 | 511 | 484 |
| Property, Plant and Equipment, Net | 1,8 | 38,637 | 38,568 |
| Right-of-Use Assets, Net | 1,9 | 1,947 | 1,950 |
| Income Tax Receivable | 25 | 25 | |
| Investments in Equity-Accounted Affiliates | 362 | 399 | |
| Other Assets | 440 | 451 | |
| Deferred Income Taxes | 1,188 | 1,064 | |
| Goodwill | 1 | 2,923 | 2,923 |
| Total Assets | 56,380 | 56,539 | |
| Liabilities and Equity | |||
| Current Liabilities | |||
| Accounts Payable and Accrued Liabilities | 5,948 | 6,242 | |
| Income Tax Payable | 66 | 396 | |
| Short-Term Borrowings | 10 | 323 | 173 |
| Long-Term Debt | 10 | 192 | 192 |
| Lease Liabilities | 9 | 381 | 359 |
| Total Current Liabilities | 6,910 | 7,362 | |
| Long-Term Debt | 10 | 7,332 | 7,342 |
| Lease Liabilities | 9 | 2,544 | 2,568 |
| Decommissioning Liabilities | 11 | 4,608 | 4,534 |
| Other Liabilities | 12 | 892 | 919 |
| Deferred Income Taxes | 4,047 | 4,045 | |
| Total Liabilities | 26,333 | 26,770 | |
| Shareholders’ Equity | 30,032 | 29,754 | |
| Non-Controlling Interest | 15 | 15 | |
| Total Liabilities and Equity | 56,380 | 56,539 | |
| Commitments and Contingencies | 20 |
See accompanying Notes to the interim Consolidated Financial Statements (unaudited).
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 4 |
|---|---|
| CONSOLIDATED STATEMENTS OF EQUITY (unaudited) | |
| --- |
($ millions)
| Shareholders’ Equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Common Shares | Treasury<br>Shares | Preferred Shares | Warrants | Paid in<br><br>Surplus | Retained<br><br>Earnings | AOCI (1) | Total | |
| (Note 13) | (Note 13) | (Note 13) | (Note 13) | (Note 14) | ||||
| As at December 31, 2023 | 16,031 | — | 519 | 25 | 2,002 | 8,913 | 1,208 | 28,698 |
| Net Earnings (Loss) | — | — | — | — | — | 1,176 | — | 1,176 |
| Other Comprehensive Income <br>(Loss), Net of Tax | — | — | — | — | — | — | 282 | 282 |
| Total Comprehensive Income (Loss) | — | — | — | — | — | 1,176 | 282 | 1,458 |
| Common Shares Issued Under<br>Stock Option Plans | 5 | — | — | — | (1) | — | — | 4 |
| Purchase of Common Shares Under<br><br>NCIB (2) | (63) | — | — | — | (102) | — | — | (165) |
| Warrants Exercised | 3 | — | — | (1) | — | — | — | 2 |
| Stock-Based Compensation<br>Expense | — | — | — | — | 5 | — | — | 5 |
| Base Dividends on Common Shares | — | — | — | — | — | (262) | — | (262) |
| Dividends on Preferred Shares | — | — | — | — | — | (9) | — | (9) |
| As at March 31, 2024 | 15,976 | — | 519 | 24 | 1,904 | 9,818 | 1,490 | 29,731 |
| As at December 31, 2024 | 15,659 | (43) | 356 | 12 | 944 | 10,513 | 2,313 | 29,754 |
| Net Earnings (Loss) | — | — | — | — | — | 859 | — | 859 |
| Other Comprehensive Income<br>(Loss), Net of Tax | — | — | — | — | — | — | (10) | (10) |
| Total Comprehensive Income (Loss) | — | — | — | — | — | 859 | (10) | 849 |
| Common Shares Issued Under<br>Stock Option Plans | 4 | — | — | — | (1) | — | — | 3 |
| Purchase of Common Shares Under<br><br>NCIB (2) | (25) | — | — | — | (37) | — | — | (62) |
| Purchase of Common Shares Under<br>Employee Benefit Plan | — | (58) | — | — | — | — | — | (58) |
| Common Shares Issued Under<br>Employee Benefit Plan | — | 81 | — | — | (6) | — | — | 75 |
| Preferred Shares Redeemed | — | — | (140) | — | (60) | — | — | (200) |
| Warrants Exercised | 2 | — | — | (1) | — | — | — | 1 |
| Stock-Based Compensation<br>Expense | — | — | — | — | 3 | — | — | 3 |
| Base Dividends on Common Shares | — | — | — | — | — | (327) | — | (327) |
| Dividends on Preferred Shares | — | — | — | — | — | (6) | — | (6) |
| As at March 31, 2025 | 15,640 | (20) | 216 | 11 | 843 | 11,039 | 2,303 | 30,032 |
(1)Accumulated other comprehensive income (loss) (“AOCI”).
(2)Normal course issuer bid (“NCIB”). Includes taxes payable on purchase of shares.
See accompanying Notes to the interim Consolidated Financial Statements (unaudited).
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 5 |
|---|---|
| CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) | |
| --- |
For the period ended March 31,
($ millions)
| Three Months Ended | ||||
|---|---|---|---|---|
| Notes | 2025 | 2024 | ||
| Operating Activities | ||||
| Net Earnings (Loss) | 859 | 1,176 | ||
| Depreciation, Depletion and Amortization | 8,9 | 1,314 | 1,195 | |
| Deferred Income Tax Expense (Recovery) | 5 | (66) | (32) | |
| Unrealized (Gain) Loss on Risk Management | 17 | 23 | 31 | |
| Unrealized Foreign Exchange (Gain) Loss | 4 | 19 | 124 | |
| (Gain) Loss on Divestiture of Assets | — | (105) | ||
| Re-measurement of Contingent Payments | — | 28 | ||
| Unwinding of Discount on Decommissioning Liabilities | 11 | 58 | 57 | |
| (Income) Loss From Equity-Accounted Affiliates | 7 | (9) | ||
| Distributions Received From Equity-Accounted Affiliates | 25 | 31 | ||
| Stock-Based Compensation, Net of Payments | 7 | (154) | ||
| Other | (34) | (100) | ||
| Settlement of Decommissioning Liabilities | 11 | (36) | (48) | |
| Net Change in Non-Cash Working Capital | 19 | (861) | (269) | |
| Cash From (Used in) Operating Activities | 1,315 | 1,925 | ||
| Investing Activities | ||||
| Acquisitions, Net of Cash Acquired | (100) | (10) | ||
| Capital Investment | 1 | (1,229) | (1,036) | |
| Proceeds From Divestitures | — | 25 | ||
| Net Change in Investments and Other | 4 | (13) | ||
| Net Change in Non-Cash Working Capital | 19 | (23) | (101) | |
| Cash From (Used in) Investing Activities | (1,348) | (1,135) | ||
| Net Cash Provided (Used) Before Financing Activities | (33) | 790 | ||
| Financing Activities | 19 | |||
| Net Issuance (Repayment) of Short-Term Borrowings | 150 | (175) | ||
| Repayment of Long-Term Debt | (12) | — | ||
| Principal Repayment of Leases | 9 | (83) | (70) | |
| Common Shares Issued Under Stock Option Plans | 3 | 4 | ||
| Purchase of Common Shares Under NCIB | 13 | (62) | (165) | |
| Purchase of Common Shares Under Employee Benefit Plan | 13 | (58) | — | |
| Redemption of Preferred Shares | 13 | (200) | — | |
| Proceeds From Exercise of Warrants | 1 | 2 | ||
| Dividends Paid | 6 | (333) | (271) | |
| Net Proceeds on Repurchase Agreements | 300 | — | ||
| Other | — | (2) | ||
| Cash From (Used in) Financing Activities | (294) | (677) | ||
| Effect of Foreign Exchange on Cash and Cash Equivalents | 2 | 60 | ||
| Increase (Decrease) in Cash and Cash Equivalents | (325) | 173 | ||
| Cash and Cash Equivalents, Beginning of Period | 3,093 | 2,227 | ||
| Cash and Cash Equivalents, End of Period | 2,768 | 2,400 |
See accompanying Notes to the interim Consolidated Financial Statements (unaudited).
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 6 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES |
|---|
Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”).
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange. Cenovus’s cumulative redeemable preferred shares series 1, 2 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these interim Consolidated Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin.
The Company operates through the following reportable segments:
Upstream Segments
•Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise, Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.
•Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas in Alberta and British Columbia in the Edson, Clearwater and Rainbow Lake operating areas, in addition to the Northern Corridor, which includes Elmworth and Wapiti. The segment also includes interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported, with additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.
•Offshore, includes offshore operations, exploration and development activities in the east coast of Canada and the Asia Pacific region, representing China and the equity-accounted investment in Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for, and production of, NGLs and natural gas in offshore Indonesia.
Downstream Segments
•Canadian Refining, includes the owned and operated Lloydminster upgrading and asphalt refining complex, which converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value.
•U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries. The U.S. Refining segment also includes the jointly-owned Wood River and Borger refineries held through WRB Refining LP (“WRB”), a jointly-owned entity with operator Phillips 66. Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt.
Corporate and Eliminations
Corporate and Eliminations, includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 7 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
A) Results of Operations – Segment and Operational Information
| Upstream | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended | Oil Sands | Conventional | Offshore | Total | ||||||||||||
| March 31, | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||
| Gross Sales | ||||||||||||||||
| External Sales | 5,904 | 5,013 | 443 | 377 | 451 | 357 | 6,798 | 5,747 | ||||||||
| Intersegment Sales | 1,953 | 1,615 | 501 | 502 | — | — | 2,454 | 2,117 | ||||||||
| 7,857 | 6,628 | 944 | 879 | 451 | 357 | 9,252 | 7,864 | |||||||||
| Royalties | (861) | (697) | (20) | (24) | (25) | (26) | (906) | (747) | ||||||||
| Revenues | 6,996 | 5,931 | 924 | 855 | 426 | 331 | 8,346 | 7,117 | ||||||||
| Expenses | ||||||||||||||||
| Purchased Product | 632 | 289 | 535 | 482 | — | — | 1,167 | 771 | ||||||||
| Transportation and Blending | 3,151 | 2,733 | 90 | 78 | 6 | — | 3,247 | 2,811 | ||||||||
| Operating | 677 | 660 | 127 | 153 | 89 | 85 | 893 | 898 | ||||||||
| Realized (Gain) Loss on Risk<br> Management | (8) | 13 | (1) | (7) | — | — | (9) | 6 | ||||||||
| Operating Margin | 2,544 | 2,236 | 173 | 149 | 331 | 246 | 3,048 | 2,631 | ||||||||
| Unrealized (Gain) Loss on Risk<br><br>Management | (7) | (13) | — | 6 | — | — | (7) | (7) | ||||||||
| Depreciation, Depletion and<br> Amortization | 834 | 774 | 120 | 110 | 130 | 131 | 1,084 | 1,015 | ||||||||
| Exploration Expense | 4 | 3 | — | — | 1 | 4 | 5 | 7 | ||||||||
| (Income) Loss From Equity-<br> Accounted Affiliates | — | — | — | 1 | (8) | (10) | (8) | (9) | ||||||||
| Segment Income (Loss) | 1,713 | 1,472 | 53 | 32 | 208 | 121 | 1,974 | 1,625 | Downstream | |||||||
| --- | --- | --- | --- | --- | --- | --- | ||||||||||
| Canadian Refining | U.S. Refining | Total | ||||||||||||||
| For the three months ended March 31, | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||||
| Gross Sales | ||||||||||||||||
| External Sales (1) | 985 | 1,163 | 6,422 | 6,900 | 7,407 | 8,063 | ||||||||||
| Intersegment Sales | 297 | 169 | 1 | 1 | 298 | 170 | ||||||||||
| 1,282 | 1,332 | 6,423 | 6,901 | 7,705 | 8,233 | |||||||||||
| Royalties | — | — | — | — | — | — | ||||||||||
| Revenues (1) | 1,282 | 1,332 | 6,423 | 6,901 | 7,705 | 8,233 | ||||||||||
| Expenses | ||||||||||||||||
| Purchased Product (1) | 1,076 | 1,087 | 6,006 | 5,798 | 7,082 | 6,885 | ||||||||||
| Transportation and Blending | — | — | — | — | — | — | ||||||||||
| Operating | 138 | 177 | 716 | 610 | 854 | 787 | ||||||||||
| Realized (Gain) Loss on Risk Management | — | — | 6 | 1 | 6 | 1 | ||||||||||
| Operating Margin | 68 | 68 | (305) | 492 | (237) | 560 | ||||||||||
| Unrealized (Gain) Loss on Risk Management | — | — | (8) | 8 | (8) | 8 | ||||||||||
| Depreciation, Depletion and Amortization | 47 | 44 | 158 | 111 | 205 | 155 | ||||||||||
| Exploration Expense | — | — | — | — | — | — | ||||||||||
| (Income) Loss From Equity-Accounted Affiliates | — | — | — | — | — | — | ||||||||||
| Segment Income (Loss) | 21 | 24 | (455) | 373 | (434) | 397 |
(1)Comparative period reflects certain revisions. See Note 21.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 8 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| Corporate and Eliminations | Consolidated | ||||||
|---|---|---|---|---|---|---|---|
| For the three months ended March 31, | 2025 | 2024 | 2025 | 2024 | |||
| Gross Sales | |||||||
| External Sales (1) | — | — | 14,205 | 13,810 | |||
| Intersegment Sales | (2,752) | (2,287) | — | — | |||
| (2,752) | (2,287) | 14,205 | 13,810 | ||||
| Royalties | — | — | (906) | (747) | |||
| Revenues (1) | (2,752) | (2,287) | 13,299 | 13,063 | |||
| Expenses | |||||||
| Purchased Product (1) | (2,370) | (1,857) | 5,879 | 5,799 | |||
| Transportation and Blending | (256) | (236) | 2,991 | 2,575 | |||
| Purchased Product, Transportation and Blending (1) | (2,626) | (2,093) | 8,870 | 8,374 | |||
| Operating | (118) | (130) | 1,629 | 1,555 | |||
| Realized (Gain) Loss on Risk Management | (5) | 3 | (8) | 10 | |||
| Unrealized (Gain) Loss on Risk Management | 38 | 30 | 23 | 31 | |||
| Depreciation, Depletion and Amortization | 25 | 25 | 1,314 | 1,195 | |||
| Exploration Expense | — | — | 5 | 7 | |||
| (Income) Loss From Equity-Accounted Affiliates | 15 | — | 7 | (9) | |||
| Segment Income (Loss) | (81) | (122) | 1,459 | 1,900 | |||
| General and Administrative | 197 | 246 | 197 | 246 | |||
| Finance Costs, Net | 136 | 135 | 136 | 135 | |||
| Integration, Transaction and Other Costs | 2 | 33 | 2 | 33 | |||
| Foreign Exchange (Gain) Loss, Net | — | 99 | — | 99 | |||
| (Gain) Loss on Divestiture of Assets | — | (105) | — | (105) | |||
| Re-measurement of Contingent Payments | — | 28 | — | 28 | |||
| Other (Income) Loss, Net | (6) | (90) | (6) | (90) | |||
| 329 | 346 | 329 | 346 | ||||
| Earnings (Loss) Before Income Tax | 1,130 | 1,554 | |||||
| Income Tax Expense (Recovery) | 271 | 378 | |||||
| Net Earnings (Loss) | 859 | 1,176 |
(1)Comparative period reflects certain revisions. See Note 21.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 9 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
B) External Sales by Product
| Upstream | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| For the three months ended | Oil Sands | Conventional | Offshore | Total | ||||||||||||
| March 31, | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||
| Crude Oil | 5,423 | 4,875 | 38 | 55 | 146 | 41 | 5,607 | 4,971 | ||||||||
| Natural Gas and Other | 78 | 80 | 304 | 236 | 228 | 233 | 610 | 549 | ||||||||
| NGLs (1) | 403 | 58 | 101 | 86 | 77 | 83 | 581 | 227 | ||||||||
| External Sales | 5,904 | 5,013 | 443 | 377 | 451 | 357 | 6,798 | 5,747 | Downstream | |||||||
| --- | --- | --- | --- | --- | --- | --- | ||||||||||
| Canadian Refining | U.S. Refining | Total | ||||||||||||||
| For the three months ended March 31, | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||||||
| Gasoline | 49 | 103 | 3,114 | 3,318 | 3,163 | 3,421 | ||||||||||
| Distillates (2) | 356 | 392 | 2,485 | 2,731 | 2,841 | 3,123 | ||||||||||
| Synthetic Crude Oil | 404 | 465 | — | — | 404 | 465 | ||||||||||
| Asphalt | 70 | 73 | 194 | 146 | 264 | 219 | ||||||||||
| Other Products and Services (3) | 106 | 130 | 629 | 705 | 735 | 835 | ||||||||||
| External Sales | 985 | 1,163 | 6,422 | 6,900 | 7,407 | 8,063 |
(1)Third-party condensate sales are included within NGLs.
(2)Includes diesel and jet fuel.
(3)Comparative period reflects certain revisions. See Note 21.
C) Geographical Information
| Revenues (1) | ||
|---|---|---|
| For the three months ended March 31, | 2025 | 2024 |
| Canada | 6,184 | 5,204 |
| United States (2) | 6,833 | 7,568 |
| China | 282 | 291 |
| Consolidated | 13,299 | 13,063 |
(1)Revenues from external customers by country are classified based on the jurisdiction in which the selling entities are located.
(2)Comparative period reflects certain revisions. See Note 21.
| Non-Current Assets (1) | ||
|---|---|---|
| March 31, | December 31, | |
| As at | 2025 | 2024 |
| Canada | 37,235 | 37,006 |
| United States | 5,833 | 5,902 |
| China | 1,168 | 1,249 |
| Indonesia | 272 | 295 |
| Consolidated | 44,508 | 44,452 |
(1)Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 10 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
D) Assets by Segment
| E&E Assets | PP&E | ROU Assets | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| March 31, | December 31, | March 31, | December 31, | March 31, | December 31, | |||||||
| As at | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | ||||||
| Oil Sands | 484 | 461 | 24,711 | 24,646 | 1,025 | 1,018 | ||||||
| Conventional | 19 | 15 | 2,234 | 2,230 | 53 | 57 | ||||||
| Offshore | 8 | 8 | 3,468 | 3,365 | 92 | 95 | ||||||
| Canadian Refining | — | — | 2,488 | 2,511 | 41 | 39 | ||||||
| U.S. Refining | — | — | 5,471 | 5,538 | 342 | 342 | ||||||
| Corporate and Eliminations | — | — | 265 | 278 | 394 | 399 | ||||||
| Consolidated | 511 | 484 | 38,637 | 38,568 | 1,947 | 1,950 | Goodwill | Total Assets | ||||
| --- | --- | --- | --- | --- | ||||||||
| March 31, | December 31, | March 31, | December 31, | |||||||||
| As at | 2025 | 2024 | 2025 | 2024 | ||||||||
| Oil Sands | 2,923 | 2,923 | 31,667 | 31,668 | ||||||||
| Conventional | — | — | 2,566 | 2,610 | ||||||||
| Offshore | — | — | 4,101 | 4,089 | ||||||||
| Canadian Refining | — | — | 2,914 | 2,901 | ||||||||
| U.S. Refining | — | — | 9,460 | 9,517 | ||||||||
| Corporate and Eliminations | — | — | 5,672 | 5,754 | ||||||||
| Consolidated | 2,923 | 2,923 | 56,380 | 56,539 |
E) Capital Expenditures (1)
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Capital Investment | ||
| Oil Sands | 763 | 647 |
| Conventional | 122 | 126 |
| Offshore | ||
| Atlantic | 227 | 158 |
| Asia Pacific | 14 | 1 |
| Total Upstream | 1,126 | 932 |
| Canadian Refining | 22 | 31 |
| U.S. Refining | 77 | 67 |
| Total Downstream | 99 | 98 |
| Corporate and Eliminations | 4 | 6 |
| 1,229 | 1,036 | |
| Acquisitions | ||
| Oil Sands | 92 | 2 |
| Conventional | — | 8 |
| 92 | 10 | |
| Total Capital Expenditures | 1,321 | 1,046 |
(1)Includes expenditures on PP&E, E&E assets and capitalized interest.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 11 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE |
|---|
In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These interim Consolidated Financial Statements were prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) (the “IFRS Accounting Standards”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting”. These interim Consolidated Financial Statements were prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2024, except for income taxes. Income taxes on earnings or loss in the interim period are accrued using the income tax rate that would be applicable to the expected annual earnings or loss.
Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements were condensed. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2024, which were prepared in accordance with IFRS Accounting Standards.
These interim Consolidated Financial Statements were approved by the Board of Directors effective May 7, 2025.
| 3. FINANCE COSTS, NET | | --- || For the three months ended March 31, | 2025 | 2024 | | --- | --- | --- | | Interest Expense – Short-Term Borrowings and Long-Term Debt | 79 | 76 | | Interest Expense – Lease Liabilities (Note 9) | 43 | 39 | | Unwinding of Discount on Decommissioning Liabilities (Note 11) | 58 | 57 | | Other | 6 | 6 | | Capitalized Interest | (17) | (8) | | Finance Costs | 169 | 170 | | Interest Income | (33) | (35) | | | 136 | 135 | | 4. FOREIGN EXCHANGE (GAIN) LOSS, NET | | --- || For the three months ended March 31, | 2025 | 2024 | | --- | --- | --- | | Unrealized Foreign Exchange (Gain) Loss on Translation of: | | | | U.S. Dollar Debt | (5) | 123 | | Other | 24 | 1 | | Unrealized Foreign Exchange (Gain) Loss | 19 | 124 | | Realized Foreign Exchange (Gain) Loss | (19) | (25) | | | — | 99 | | 5. INCOME TAXES | | --- || For the three months ended March 31, | 2025 | 2024 | | --- | --- | --- | | Current Tax | | | | Canada | 279 | 346 | | United States | — | 11 | | Asia Pacific | 45 | 44 | | Other International | 13 | 9 | | Total Current Tax Expense (Recovery) | 337 | 410 | | Deferred Tax Expense (Recovery) | (66) | (32) | | | 271 | 378 | | Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 12 | | --- | --- |
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 6. PER SHARE AMOUNTS |
|---|
A) Net Earnings (Loss) Per Common Share – Basic and Diluted
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Net Earnings (Loss) | 859 | 1,176 |
| Effect of Cumulative Dividends on Preferred Shares | (6) | (9) |
| Net Earnings (Loss) – Basic | 853 | 1,167 |
| Effect of Stock-Based Compensation | 1 | — |
| Net Earnings (Loss) – Diluted | 854 | 1,167 |
| Basic – Weighted Average Number of Shares (thousands) | 1,821,325 | 1,867,793 |
| Dilutive Effect of Warrants | 2,505 | 5,466 |
| Dilutive Effect of Stock-Based Compensation | 7,435 | 5,041 |
| Diluted – Weighted Average Number of Shares (thousands) | 1,831,265 | 1,878,300 |
| Net Earnings (Loss) Per Common Share – Basic ($) | 0.47 | 0.62 |
| Net Earnings (Loss) Per Common Share – Diluted (1) ($) | 0.47 | 0.62 |
(1)For the three months ended March 31, 2025, 13.4 million common shares (2024 – 22.2 million) related to the assumed exercise of stock-based compensation were excluded from the calculation of dilutive net earnings (loss) per share, as the effect was anti-dilutive.
B) Common Share Dividends
| 2025 | 2024 | |||
|---|---|---|---|---|
| For the three months ended March 31, | Per Share | Amount | Per Share | Amount |
| Base Dividends | 0.180 | 327 | 0.140 | 262 |
| Variable Dividends | — | — | — | — |
| Total Common Share Dividends Declared and Paid | 0.180 | 327 | 0.140 | 262 |
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.
On May 7, 2025, the Company’s Board of Directors declared a second quarter base dividend of $0.200 per common share, payable on June 30 2025, to common shareholders of record as at June 13, 2025.
C) Preferred Share Dividends
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Series 1 First Preferred Shares | 2 | 2 |
| Series 2 First Preferred Shares | — | — |
| Series 3 First Preferred Shares | — | 3 |
| Series 5 First Preferred Shares | 2 | 2 |
| Series 7 First Preferred Shares | 2 | 2 |
| Total Preferred Share Dividends Declared | 6 | 9 |
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly.
For the three months ended March 31, 2025, the Company paid preferred share dividends of $6 million (2024 – $9 million).
On May 7, 2025, the Company’s Board of Directors declared second quarter dividends of $4 million payable on June 30, 2025, to preferred shareholders of record as at June 13, 2025.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 13 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 7. EXPLORATION AND EVALUATION ASSETS, NET | | --- || | Total | | --- | --- | | As at December 31, 2024 | 484 | | Additions | 27 | | As at March 31, 2025 | 511 | | 8. PROPERTY, PLANT AND EQUIPMENT, NET | | --- || | Crude Oil and Natural Gas Properties | Processing, Transportation and Storage Assets | Refining Assets | Other Assets (1) | Total | | --- | --- | --- | --- | --- | --- | | COST | | | | | | | As at December 31, 2024 | 52,090 | 280 | 14,325 | 1,975 | 68,670 | | Acquisitions | 92 | — | — | — | 92 | | Additions | 1,099 | — | 100 | 3 | 1,202 | | Change in Decommissioning Liabilities | 9 | — | — | — | 9 | | Exchange Rate Movements and Other | (21) | (1) | (22) | 1 | (43) | | As at March 31, 2025 | 53,269 | 279 | 14,403 | 1,979 | 69,930 | | ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION | | | | | | | As at December 31, 2024 | 21,849 | 141 | 6,675 | 1,437 | 30,102 | | Depreciation, Depletion and Amortization | 1,031 | 3 | 176 | 21 | 1,231 | | Exchange Rate Movements and Other | (24) | — | (15) | (1) | (40) | | As at March 31, 2025 | 22,856 | 144 | 6,836 | 1,457 | 31,293 | | CARRYING VALUE | | | | | | | As at December 31, 2024 | 30,241 | 139 | 7,650 | 538 | 38,568 | | As at March 31, 2025 | 30,413 | 135 | 7,567 | 522 | 38,637 |
(1)Includes assets within the commercial fuels business, office furniture, fixtures, leasehold improvements, information technology and aircraft.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 14 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 9. LEASES |
|---|
A) Right-of-Use Assets, Net
| Real Estate | Transportation and Storage Assets (1) | Refining Assets | Other Assets (2) | Total | |
|---|---|---|---|---|---|
| COST | |||||
| As at December 31, 2024 | 592 | 2,392 | 178 | 125 | 3,287 |
| Additions | 4 | 16 | — | 2 | 22 |
| Exchange Rate Movements and Other | 1 | 53 | — | 3 | 57 |
| As at March 31, 2025 | 597 | 2,461 | 178 | 130 | 3,366 |
| ACCUMULATED DEPRECIATION | |||||
| As at December 31, 2024 | 193 | 999 | 94 | 51 | 1,337 |
| Depreciation | 10 | 61 | 3 | 9 | 83 |
| Exchange Rate Movements and Other | (1) | (1) | — | 1 | (1) |
| As at March 31, 2025 | 202 | 1,059 | 97 | 61 | 1,419 |
| CARRYING VALUE | |||||
| As at December 31, 2024 | 399 | 1,393 | 84 | 74 | 1,950 |
| As at March 31, 2025 | 395 | 1,402 | 81 | 69 | 1,947 |
(1)Includes a pipeline, storage tanks, railcars, vessels, barges, a natural gas processing plant and caverns.
(2)Includes assets in the commercial fuels business, fleet vehicles, camps and other equipment.
B) Lease Liabilities
| Total | |
|---|---|
| As at December 31, 2024 | 2,927 |
| Additions | 22 |
| Interest Expense (Note 3) | 43 |
| Lease Payments | (126) |
| Exchange Rate Movements and Other | 59 |
| As at March 31, 2025 | 2,925 |
| Less: Current Portion | 381 |
| Long-Term Portion | 2,544 |
| 10. DEBT AND CAPITAL STRUCTURE | |
| --- |
A) Short-Term Borrowings
| March 31, | December 31, | ||
|---|---|---|---|
| As at | Notes | 2025 | 2024 |
| Uncommitted Demand Facilities | i | — | — |
| WRB Uncommitted Demand Facilities | ii | 323 | 173 |
| Total Debt Principal | 323 | 173 |
i) Uncommitted Demand Facilities
As at March 31, 2025, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2024 – $1.7 billion) in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at March 31, 2025, there were outstanding letters of credit aggregating to $368 million (December 31, 2024 – $355 million) and no direct borrowings (December 31, 2024 – $nil).
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 15 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
ii) WRB Uncommitted Demand Facilities
WRB has uncommitted demand facilities of US$450 million (December 31, 2024 – US$450 million) that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at March 31, 2025, US$450 million was drawn on these facilities, of which Cenovus’s proportionate share was US$225 million (C$323 million). As at December 31, 2024, Cenovus's proportionate share of drawings was US$120 million (C$173 million).
B) Long-Term Debt
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Committed Credit Facility | — | — |
| U.S. Dollar Denominated Unsecured Notes (1) | 5,465 | 5,470 |
| Canadian Dollar Unsecured Notes | 2,000 | 2,000 |
| Total Debt Principal | 7,465 | 7,470 |
| Debt Premiums (Discounts), Net, and Transaction Costs | 59 | 64 |
| Long-Term Debt | 7,524 | 7,534 |
| Less: Current Portion | 192 | 192 |
| Long-Term Portion | 7,332 | 7,342 |
(1)Total U.S. dollar denominated unsecured notes as at March 31, 2025, was US$3.8 billion (December 31, 2024 — US$3.8 billion).
As at March 31, 2025 , the Company had in place a committed credit facility that consists of a $2.2 billion tranche maturing on June 26, 2027, and a $3.3 billion tranche maturing on June 26, 2028. As at March 31, 2025, no amount was drawn on the credit facility (December 31, 2024 – $nil).
The committed credit facility may include Canadian overnight repo rate average loans, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.
As at March 31, 2025, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. The Company is below this limit.
C) Capital Structure
Cenovus’s capital structure consists of shareholders’ equity and Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents, and short-term investments. Net Debt is used in managing the Company’s capital structure. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions, while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, steward working capital, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, Total Debt, Net Debt to adjusted earnings before interest, taxes and depreciation, depletion and amortization (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.
Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4.0 billion over the long-term at a West Texas Intermediate (“WTI”) price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices or the strengthening or weakening of the Canadian dollar relative to the U.S. dollar.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 16 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
Net Debt to Adjusted EBITDA
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Short-Term Borrowings | 323 | 173 |
| Current Portion of Long-Term Debt | 192 | 192 |
| Long-Term Portion of Long-Term Debt | 7,332 | 7,342 |
| Total Debt | 7,847 | 7,707 |
| Less: Cash and Cash Equivalents | (2,768) | (3,093) |
| Net Debt | 5,079 | 4,614 |
| Net Earnings (Loss) | 2,825 | 3,142 |
| Add (Deduct): | ||
| Finance Costs, Net | 515 | 514 |
| Income Tax Expense (Recovery) | 822 | 929 |
| Depreciation, Depletion and Amortization | 4,990 | 4,871 |
| Exploration and Evaluation Asset Write-downs | 37 | 37 |
| (Income) Loss From Equity-Accounted Affiliates | (50) | (66) |
| Unrealized (Gain) Loss on Risk Management | 4 | 12 |
| Foreign Exchange (Gain) Loss, Net | 363 | 462 |
| (Gain) Loss on Divestiture of Assets | (14) | (119) |
| Re-measurement of Contingent Payments | 2 | 30 |
| Other (Income) Loss, Net | 29 | (55) |
| Adjusted EBITDA (1) | 9,523 | 9,757 |
| Net Debt to Adjusted EBITDA (times) | 0.5 | 0.5 |
(1)Calculated on a trailing twelve-month basis.
Net Debt to Adjusted Funds Flow
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Net Debt | 5,079 | 4,614 |
| Cash From (Used in) Operating Activities | 8,625 | 9,235 |
| (Add) Deduct: | ||
| Settlement of Decommissioning Liabilities | (222) | (234) |
| Net Change in Non-Cash Working Capital | 713 | 1,305 |
| Adjusted Funds Flow (1) | 8,134 | 8,164 |
| Net Debt to Adjusted Funds Flow (times) | 0.6 | 0.6 |
(1)Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Net Debt | 5,079 | 4,614 |
| Shareholders’ Equity | 30,032 | 29,754 |
| Capitalization | 35,111 | 34,368 |
| Net Debt to Capitalization (percent) | 14 | 13 |
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 17 | |
| --- | --- |
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 11. DECOMMISSIONING LIABILITIES | | --- || | Total | | --- | --- | | As at December 31, 2024 | 4,534 | | Liabilities Incurred | 9 | | Liabilities Acquired | 43 | | Liabilities Settled | (36) | | Unwinding of Discount on Decommissioning Liabilities (Note 3) | 58 | | As at March 31, 2025 | 4,608 |
As at March 31, 2025, the undiscounted amount of estimated future cash flows required to settle the obligation was discounted using a credit-adjusted risk-free rate of 5.2 percent (December 31, 2024 – 5.2 percent) and assumes an inflation rate of two percent (December 31, 2024 – two percent).
| 12. OTHER LIABILITIES | | --- || | March 31, | December 31, | | --- | --- | --- | | As at | 2025 | 2024 | | Renewable Volume Obligation, Net (1) | 272 | 284 | | Pension and Other Post-Employment Benefit Plan | 270 | 269 | | Employee Long-Term Incentives | 67 | 96 | | Provisions for Onerous and Unfavourable Contracts | 64 | 66 | | Provision for West White Rose Expansion Project | 34 | 54 | | Other | 185 | 150 | | | 892 | 919 |
(1)The gross amounts of the renewable volume obligation and renewable identification numbers asset were $852 million and $580 million, respectively (December 31, 2024 – $652 million and $368 million, respectively).
| 13. SHARE CAPITAL AND WARRANTS |
|---|
A) Authorized
Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles.
B) Issued and Outstanding – Common Shares
| March 31, 2025 | December 31, 2024 | |||
|---|---|---|---|---|
| Number of<br><br>Common<br><br>Shares<br><br>(thousands) | Amount | Number of<br><br>Common<br><br>Shares<br><br>(thousands) | Amount | |
| Outstanding, Beginning of Year | 1,825,038 | 15,659 | 1,871,868 | 16,031 |
| Issued Under Stock Option Plans | 346 | 4 | 5,049 | 68 |
| Purchase of Common Shares Under NCIB | (2,950) | (25) | (55,861) | (479) |
| Issued Upon Exercise of Warrants | 224 | 2 | 3,982 | 39 |
| Outstanding, End of Period | 1,822,658 | 15,640 | 1,825,038 | 15,659 |
As at March 31, 2025, there were 45.1 million (December 31, 2024 – 48.8 million) common shares available for future issuance under the stock option plan.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 18 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
C) Normal Course Issuer Bid
On November 7, 2024, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 127.5 million common shares during the period from November 11, 2024, to November 10, 2025.
For the three months ended March 31, 2025, the Company purchased and cancelled 3.0 million common shares through the NCIB. The shares were purchased at a volume weighted average price of $20.68 per common share for a total of $61 million. Paid in surplus was reduced by $37 million, of which $36 million represents the excess of the purchase price of the common shares over their average carrying value and $1 million relates to share buyback tax.
From April 1, 2025, to May 5, 2025, the Company purchased an additional 10.9 million common shares for $178 million. As at May 5, 2025, the Company can further purchase up to 112.5 million common shares under the NCIB.
D) Treasury Shares
Cenovus has an employee benefit plan trust (the “Trust”). The Trust, through an independent trustee, acquires Cenovus’s common shares on the open market, which are held to satisfy the Company’s obligations under certain stock-based compensation plans.
| March 31, 2025 | December 31, 2024 | |||
|---|---|---|---|---|
| Number of<br><br>Common<br><br>Shares<br><br>(thousands) | Amount | Number of<br><br>Common<br><br>Shares<br><br>(thousands) | Amount | |
| Outstanding, Beginning of Year | 2,000 | 43 | — | — |
| Purchased Under Employee Benefit Plan | 2,800 | 58 | 2,000 | 43 |
| Distributed Under Employee Benefit Plan | (3,784) | (81) | — | — |
| Outstanding, End of Period | 1,016 | 20 | 2,000 | 43 |
Paid in surplus was reduced by $6 million, representing the difference between the long-term incentive obligation and the weighted average carrying value of the treasury shares on settlement.
E) Issued and Outstanding – Preferred Shares
| March 31, 2025 | December 31, 2024 | |||
|---|---|---|---|---|
| Number of Preferred Shares (thousands) | Amount | Number of<br><br>Preferred<br><br>Shares<br><br>(thousands) | Amount | |
| Outstanding, Beginning of Year | 26,000 | 356 | 36,000 | 519 |
| Preferred Shares Redeemed | (8,000) | (140) | (10,000) | (163) |
| Outstanding, End of Period | 18,000 | 216 | 26,000 | 356 |
On March 31, 2025, Cenovus exercised its right to redeem all 8.0 million of the Company’s series 5 preferred shares at a price of $25.00 per share, for a total of $200 million. Paid in surplus was reduced by $60 million, representing the excess of the purchase price of the series 5 preferred shares over their carrying value.
| As at March 31, 2025 | Dividend Reset Date | Dividend Rate (percent) | Number of Preferred Shares (thousands) |
|---|---|---|---|
| Series 1 First Preferred Shares | March 31, 2026 | 2.58 | 10,740 |
| Series 2 First Preferred Shares (1) | Quarterly | 4.57 | 1,260 |
| Series 7 First Preferred Shares | June 30, 2025 | 3.94 | 6,000 |
(1) The floating-rate dividend was 5.21 percent from December 31, 2024, to March 30, 2025.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 19 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
F) Issued and Outstanding – Warrants
| March 31, 2025 | December 31, 2024 | |||
|---|---|---|---|---|
| Number of<br><br>Warrants<br><br>(thousands) | Amount | Number of<br><br>Warrants<br><br>(thousands) | Amount | |
| Outstanding, Beginning of Year | 3,643 | 12 | 7,625 | 25 |
| Exercised | (224) | (1) | (3,982) | (13) |
| Outstanding, End of Period | 3,419 | 11 | 3,643 | 12 |
The exercise price of the warrants is $6.54 per share. The warrants expire on January 1, 2026.
| 14. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | | --- || | Pension and Other Post-Employment Benefits | Private Equity Investments | Foreign Currency Translation Adjustment | Total | | --- | --- | --- | --- | --- | | As at December 31, 2023 | 55 | 85 | 1,068 | 1,208 | | Other Comprehensive Income (Loss), Before Tax | 18 | — | 268 | 286 | | Income Tax (Expense) Recovery | (4) | — | — | (4) | | As at March 31, 2024 | 69 | 85 | 1,336 | 1,490 | | As at December 31, 2024 | 69 | 156 | 2,088 | 2,313 | | Other Comprehensive Income (Loss), Before Tax | 3 | (2) | (10) | (9) | | Income Tax (Expense) Recovery | (1) | — | — | (1) | | As at March 31, 2025 | 71 | 154 | 2,078 | 2,303 | | 15. STOCK-BASED COMPENSATION PLANS | | --- |
Cenovus has a number of stock-based compensation plans that include net settlement rights (“NSRs”), performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units. As at March 31, 2025, no Cenovus replacement stock options were outstanding.
The following tables summarize information related to the Company’s stock-based compensation plans:
| Units<br><br>Outstanding | Units<br><br>Exercisable | |
|---|---|---|
| As at March 31, 2025 | (thousands) | (thousands) |
| Stock Options With Associated Net Settlement Rights | 12,257 | 5,977 |
| Performance Share Units | 7,821 | — |
| Restricted Share Units | 10,407 | — |
| Deferred Share Units | 2,009 | 2,009 |
The weighted average exercise price of NSRs outstanding as at March 31, 2025, was $18.89.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 20 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| Units<br><br>Granted | Units<br><br>Vested and<br><br>Exercised/<br><br>Paid Out | |
|---|---|---|
| For the three months ended March 31, 2025 | (thousands) | (thousands) |
| Stock Options With Associated Net Settlement Rights | 4,361 | 337 |
| Cenovus Replacement Stock Options | — | 329 |
| Performance Share Units | 3,320 | 2,268 |
| Restricted Share Units | 4,276 | 1,927 |
| Deferred Share Units | 302 | 72 |
| Weighted Average Exercise Price | Units<br><br>Exercised | |
| --- | --- | --- |
| For the three months ended March 31, 2025 | ($/unit) | (thousands) |
| Stock Options With Associated Net Settlement Rights Exercised for Net Cash Payment | 9.48 | 9 |
| Stock Options With Associated Net Settlement Rights Exercised and Net Settled for Common Shares (1) | 9.48 | 328 |
| Cenovus Replacement Stock Options Exercised and Net Settled for Cash | 3.54 | 317 |
| Cenovus Replacement Stock Options Exercised and Net Settled for Common Shares (2) | 3.54 | 12 |
(1)NSRs were net settled for 328 thousand common shares.
(2)Cenovus replacement stock options were net settled for 9 thousand common shares.
The following table summarizes the stock-based compensation expense (recovery) recorded for all plans:
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Stock Options With Associated Net Settlement Rights | 3 | 4 |
| Cenovus Replacement Stock Options | (2) | 3 |
| Performance Share Units | 10 | 48 |
| Restricted Share Units | 14 | 35 |
| Deferred Share Units | 1 | 11 |
| Stock-Based Compensation Expense (Recovery) | 26 | 101 |
PSUs and RSUs granted under the Performance Share Unit Plan and Restricted Share Unit Plan for Local Employees in the Asia Pacific region may only be settled in cash.
| 16. RELATED PARTY TRANSACTIONS |
|---|
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company charges HMLP for construction and management services, and incurs costs for the use of HMLP’s pipeline systems, as well as transportation and storage services.
The following table summarizes revenues and associated expenses related to HMLP:
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Revenues from Construction and Management Services | 29 | 31 |
| Transportation Expenses | 68 | 69 |
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 21 | |
| --- | --- |
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 17. FINANCIAL INSTRUMENTS |
|---|
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, long-term debt, certain portions of other assets and certain portions of other liabilities. Risk management assets and liabilities arise from the use of derivative financial instruments.
A) Fair Value of Non-Derivative Financial Instruments
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of these instruments.
The fair values of restricted cash, certain portions of other assets and certain portions of other liabilities approximate their carrying amount due to the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at March 31, 2025, the carrying value of Cenovus’s long-term debt was $7.5 billion and the fair value was $7.0 billion (December 31, 2024, carrying value – $7.5 billion; fair value – $6.9 billion).
The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value in other assets. Fair value is determined based on recent market activity which may include equity transactions of the entity when available (Level 3).
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:
| Total | |
|---|---|
| As at December 31, 2024 | 219 |
| Changes in Fair Value | (2) |
| As at March 31, 2025 | 217 |
B) Fair Value of Risk Management Assets and Liabilities
Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other assets and other liabilities (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management.
The Company’s risk management assets and liabilities consist of condensate and refined product futures; crude oil and natural gas futures and swaps; and renewable power, power and foreign exchange contracts. The Company may also enter into forwards and options to manage commodity, foreign exchange and interest rate exposures.
Crude oil, natural gas, condensate, refined products and power contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity, extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data and foreign exchange forward curves (Level 2).
The fair value of renewable power contracts is calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques.
Summary of Risk Management Positions
| March 31, 2025 | December 31, 2024 | |||||
|---|---|---|---|---|---|---|
| Risk Management | Risk Management | |||||
| As at | Asset | Liability | Net | Asset | Liability | Net |
| Crude Oil, Condensate, Natural Gas, and Refined Products | 13 | — | 13 | 9 | 10 | (1) |
| Power Contracts | 7 | — | 7 | 6 | — | 6 |
| Renewable Power Contracts | — | 36 | (36) | 5 | — | 5 |
| Foreign Exchange Rate Contracts | — | — | — | — | 3 | (3) |
| 20 | 36 | (16) | 20 | 13 | 7 | |
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 22 | |||||
| --- | --- |
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Level 2 – Prices Sourced From Observable Data or Market Corroboration | 20 | 2 |
| Level 3 – Prices Sourced From Partially Unobservable Data | (36) | 5 |
| (16) | 7 |
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:
| Total | |
|---|---|
| As at December 31, 2024 | 7 |
| Change in Fair Value of Contracts in Place, Beginning of Year | (39) |
| Change in Fair Value of Contracts Entered Into During the Period | 24 |
| Fair Value of Contracts Realized During the Period | (8) |
| As at March 31, 2025 | (16) |
C) Earnings Impact of (Gains) Losses From Risk Management Positions
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Realized (Gain) Loss | (8) | 10 |
| Unrealized (Gain) Loss | 23 | 31 |
| (Gain) Loss on Risk Management | 15 | 41 |
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.
| 18. RISK MANAGEMENT |
|---|
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates and commodity power prices, as well as credit risk and liquidity risk.
As at March 31, 2025, the fair value of risk management positions was a net liability of $16 million. As at March 31, 2025, there were foreign exchange contracts with a notional value of US$135 million (December 31, 2024 – US$250 million). As at March 31, 2025, and December 31, 2024, there were no outstanding interest rate contracts or cross currency interest rate swap contracts.
Net Fair Value of Risk Management Positions
| As at March 31, 2025 | Notional Volumes (1) (2) | Terms | Weighted<br><br>Average<br><br>Price (2) | Fair Value Asset (Liability) |
|---|---|---|---|---|
| WTI Contracts Related to Blending (3) | ||||
| WTI Fixed – Sell | 2.5 MMbbls | April 2025 – December 2025 | US$70.27/bbl | (1) |
| WTI Fixed – Buy | 0.3 MMbbls | April 2025 – December 2025 | US$72.60/bbl | (1) |
| Power Contracts | 7 | |||
| Renewable Power Contracts | (36) | |||
| Other Financial Positions (4) | 15 | |||
| Total Fair Value | (16) |
(1) Million barrels (“MMbbls”).
(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month.
(3) Includes individual WTI contracts with varying terms, the longest of which is 9 months. WTI contracts related to blending are used to help manage price exposure to condensate used for blending.
(4) Includes risk management positions related to Western Canadian Select (“WCS”), heavy oil, light oil and condensate differentials, benchmark delivery location spreads, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts and the Company’s U.S. refining and marketing activities.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 23 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
A) Commodity Price and Foreign Exchange Rate Risk
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.
The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:
| As at March 31, 2025 | Sensitivity Range | Increase | Decrease |
|---|---|---|---|
| Crude Oil and Condensate Commodity Price | ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges | (1) | 1 |
| Crude Oil and Condensate Differential Price (1) | ± US$2.50/bbl Applied to Differential Hedges Tied to Production | 7 | (7) |
| WCS (Hardisty) Differential Price | ± US$2.50/bbl Applied to WCS Differential Hedges Tied to Production | 2 | (2) |
| Refined Products Commodity Price | ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges | (9) | 9 |
| Natural Gas Commodity Price | ± US$0.50/Mcf (2) Applied to Natural Gas Hedges Tied to Production | — | — |
| Natural Gas Basis Price | ± US$0.25/Mcf Applied to Natural Gas Basis Hedges | — | — |
| Power Commodity Price | ± C$10.00/MWh (3) Applied to Power Hedges | 44 | (44) |
| U.S. to Canadian Dollar Exchange Rate | ± $0.05 in the U.S. to Canadian Dollar Exchange Rate | 13 | (15) |
(1)Excluding WCS at Hardisty.
(2)One thousand cubic feet (“Mcf”).
(3)One thousand kilowatts of electricity per hour (“MWh”).
B) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks.
As at March 31, 2025, approximately 79 percent (December 31, 2024 – 79 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 97 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.5 percent as at March 31, 2025 (December 31, 2024 – 0.4 percent).
C) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.
As disclosed in Note 10, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at a WTI price of US$45.00 per barrel to manage the Company’s overall debt position.
Undiscounted cash outflows relating to financial liabilities are:
| As at March 31, 2025 | Less than 1 Year | Years 2 and 3 | Years 4 and 5 | Thereafter | Total |
|---|---|---|---|---|---|
| Accounts Payable and Accrued Liabilities (1) | 5,948 | — | — | — | 5,948 |
| Short-Term Borrowings | 323 | — | — | — | 323 |
| Lease Liabilities (2) | 513 | 808 | 628 | 2,551 | 4,500 |
| Long-Term Debt (2) | 521 | 3,145 | 717 | 7,236 | 11,619 |
(1)Includes current risk management liabilities.
(2)Principal and interest, including current portion, if applicable.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 24 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
| 19. SUPPLEMENTARY CASH FLOW INFORMATION |
|---|
A) Working Capital
| March 31, | December 31, | |
|---|---|---|
| As at | 2025 | 2024 |
| Total Current Assets | 10,103 | 10,434 |
| Total Current Liabilities | 6,910 | 7,362 |
| Working Capital | 3,193 | 3,072 |
B) Changes in Non-Cash Working Capital
| For the three months ended March 31, | 2025 | 2024 |
|---|---|---|
| Accounts Receivable and Accrued Revenues | (95) | (689) |
| Income Tax Receivable | (78) | 216 |
| Inventories | 160 | (241) |
| Accounts Payable and Accrued Liabilities | (541) | 316 |
| Income Tax Payable | (330) | 28 |
| Total Change in Non-Cash Working Capital | (884) | (370) |
| Net Change in Non-Cash Working Capital – Operating Activities | (861) | (269) |
| Net Change in Non-Cash Working Capital – Investing Activities | (23) | (101) |
| Total Change in Non-Cash Working Capital | (884) | (370) |
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 25 | |
| --- | --- |
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
C) Reconciliation of Liabilities
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
| Dividends Payable | Repurchase Agreements Payable | Short-Term Borrowings | Long-Term Debt | Lease Liabilities | |
|---|---|---|---|---|---|
| As at December 31, 2023 | 9 | — | 179 | 7,108 | 2,658 |
| Changes From Financing Cash Flows: | |||||
| Net Issuance (Repayment) of Short-Term Borrowings | — | — | (175) | — | — |
| Principal Repayment of Leases | — | — | — | — | (70) |
| Dividends Paid | (271) | — | — | — | — |
| Non-Cash Changes: | |||||
| Finance and Transaction Costs | — | — | — | (4) | — |
| Lease Additions | — | — | — | — | 4 |
| Base Dividends Declared on Common Shares | 262 | — | — | — | — |
| Dividends Declared on Preferred Shares | 9 | — | — | — | — |
| Exchange Rate Movements and Other | — | — | (4) | 123 | 7 |
| As at March 31, 2024 | 9 | — | — | 7,227 | 2,599 |
| As at December 31, 2024 | — | — | 173 | 7,534 | 2,927 |
| Acquisition | — | — | — | 12 | — |
| Changes From Financing Cash Flows: | |||||
| Net Issuance (Repayment) of Short-Term Borrowings | — | — | 150 | — | — |
| Proceeds on Repurchase Agreements | — | 300 | — | — | — |
| Repayment of Long-Term Debt | — | — | — | (12) | — |
| Principal Repayment of Leases | — | — | — | — | (83) |
| Dividends Paid | (333) | — | — | — | — |
| Non-Cash Changes: | |||||
| Finance and Transaction Costs | — | — | — | (5) | — |
| Lease Additions | — | — | — | — | 22 |
| Base Dividends Declared on Common Shares | 327 | — | — | — | — |
| Variable Dividends Declared on Common Shares | 6 | — | — | — | — |
| Exchange Rate Movements and Other | — | — | — | (5) | 59 |
| As at March 31, 2025 | — | 300 | 323 | 7,524 | 2,925 |
| 20. COMMITMENTS AND CONTINGENCIES | |||||
| --- |
A) Commitments
Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below:
| As at March 31, 2025 | Remainder of Year | 2 Years | 3 Years | 4 Years | 5 Years | Thereafter | Total |
|---|---|---|---|---|---|---|---|
| Transportation and Storage (1) (2) | 1,636 | 2,032 | 2,009 | 1,999 | 1,912 | 14,729 | 24,317 |
| Real Estate | 47 | 63 | 60 | 59 | 63 | 533 | 825 |
| Obligation to Fund HCML | 78 | 104 | 98 | 57 | 44 | 105 | 486 |
| Other Long-Term Commitments | 612 | 198 | 194 | 159 | 118 | 589 | 1,870 |
| Total Commitments | 2,373 | 2,397 | 2,361 | 2,274 | 2,137 | 15,956 | 27,498 |
(1)Includes transportation commitments that are subject to regulatory approval or were approved but are not yet in service of $833 million. Terms are up to 20 years on commencement.
(2)As at March 31, 2025, includes $1.8 billion related to transportation and storage commitments with HMLP.
There were outstanding letters of credit aggregating to $368 million (December 31, 2024 – $355 million) issued as security for financial and performance conditions under certain contracts.
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 26 |
|---|
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
All amounts in $ millions, unless otherwise indicated
For the period ended March 31, 2025
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its interim Consolidated Financial Statements.
Income Tax Matters
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.
| 21. PRIOR PERIOD REVISIONS |
|---|
In December 2024, it was identified that certain transactions in the U.S Refining segment were reported on a gross basis in revenues and purchased product rather than on a net basis. As a result, revenues and purchased product were overstated for the three months ended March 31, 2024. The prior period was revised to reflect the change. There was no impact on net earnings (loss), segment income (loss), cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Comprehensive Income (Loss) and segmented disclosures to the corresponding revised amounts:
| U.S. Refining Segment | Consolidated | |||||
|---|---|---|---|---|---|---|
| For the three months ended <br>March 31, 2024 | Previously Reported | Revisions | Revised Balance | Previously Reported | Revisions | Revised Balance |
| Revenues | 7,235 | (334) | 6,901 | 13,397 | (334) | 13,063 |
| Purchased Product | 6,132 | (334) | 5,798 | 6,133 | (334) | 5,799 |
| Transportation and Blending | — | — | — | 2,575 | — | 2,575 |
| Purchased Product, Transportation<br><br>and Blending | 6,132 | (334) | 5,798 | 8,708 | (334) | 8,374 |
| 1,103 | — | 1,103 | 4,689 | — | 4,689 | |
| Cenovus Energy Inc. – Q1 2025 Interim Consolidated Financial Statements | 27 | |||||
| --- | --- |
Document
Exhibit 99.4
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Jonathan M. McKenzie, President & Chief Executive Officer of Cenovus Energy Inc., certify the following:
1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended March 31, 2025.
2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework.
5.2 ICFR - material weakness relating to design: N/A
5.3 Limitation on scope of design: N/A
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2025 and ended on March 31, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 8, 2025
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
President & Chief Executive Officer
Document
Exhibit 99.5
FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
I, Karamjit S. Sandhar, Executive Vice-President & Chief Financial Officer of Cenovus Energy Inc., certify the following:
1.Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Cenovus Energy Inc. (the “issuer”) for the interim period ended March 31, 2025.
2.No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.
3.Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.
4.Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.
5.Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings
(a)designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that
(i)material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and
(ii)information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
(b)designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.
5.1 Control framework: The control framework the issuer’s other certifying officer(s) and I used to design the issuer’s ICFR is the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control – Integrated Framework.
5.2 ICFR - material weakness relating to design: N/A
5.3 Limitation on scope of design: N/A
Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2025 and ended on March 31, 2025 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.
Date: May 8, 2025
/s/ Karamjit S. Sandhar
Karamjit S. Sandhar
Executive Vice-President & Chief Financial Officer