Cenovus Energy Inc. Aktie

Good morning, and welcome, everyone, to Cenovus' Virtual Annual Meeting of Shareholders. I'm Kim Guttormson, Director of Communications.

I'd first like to acknowledge that in our many operating areas, we work on the traditional lands of multiple indigenous peoples. In Canada, this includes First Nations, Metis and Inuit. And in the United States, this includes tribal nations. We extend our most sincere thanks and respect to the members of these nations. Today, we're holding our annual meeting in a virtual format, which allows a broader base of shareholders to participate regardless of your location.

Before turning the meeting over to Alex Pourbaix, Chair of Cenovus' Board, I'll take a minute to explain how the meeting will work. If you are a registered shareholder or duly appointed proxy holder, your information screen displays instructions on how to participate in the meeting, including voting and submitting questions. The ability to vote or ask a question is available for registered shareholders and duly appointed proxy holders only. All other guests are in listen-only mode.

Polling is now open, and voting details are displayed on your information screen. If you've already voted, you don't need to take any further action unless you'd like to change your vote. We'll close the polls following the final voting matter. If you are a registered shareholder or a duly appointed proxy holder, you may submit questions at any time during the meeting. Select the Questions tab found at the left or bottom of the screen and type in your question. Please note that questions related to voting matters will be addressed during the formal portion of the meeting.

To ensure questions related to voting matters are addressed before we close the polls, we may need to return to earlier agenda items. We may also aggregate questions that are similar. Questions that aren't related to voting matters will either be addressed during the Q&A session, which follows the formal portion of the meeting and remarks from our CEO, or they will be posted to our website, cenovus.com, in the coming days, and these will include management's response.

I'll now ask Alex Pourbaix, Chair of the Board, to call the meeting to order. Mr. Pourbaix?

Thank you, Kim, and welcome, everyone, to Cenovus' Annual Meeting of Shareholders. Before we start the formal portion of the meeting, I'd like to take a moment to thank you, our shareholders. We appreciate your continued support and confidence in our strategy and execution. As you'll hear from our CEO, Jon McKenzie, we are positioned to further build on our momentum in 2026 and beyond, focusing on our strategic priorities and continuing to deliver value across the business. I would like to thank all of our directors for their continued commitment to our success.

Now on to the business of the day. In accordance with Cenovus' bylaws, I will chair the meeting. Colin Ritchie, Assistant Corporate Secretary, will act as Secretary, and Stephen Bandola from Computershare will act as scrutineer. The record date for determining shareholders who are entitled to receive notice of and vote at this meeting was fixed at March 10, 2026.

I've been advised by the Secretary that notice of this meeting was properly given and a quorum is present. Accordingly, I declare the meeting properly called and constituted for the transaction of business. The reading of the notice of meeting will be dispensed with, and I direct the Secretary to include with the minutes, a copy of the meeting materials, confirmation of mailing to shareholders and the report on attendance. I now call the meeting to order.

Jon McKenzie, President and Chief Executive Officer, is here today, along with members of Cenovus' executive team, including: Andrew Dahlin, Executive Vice President and Chief Operating Officer; Kam Sandhar, Executive Vice President and Chief Financial Officer; Jeff Lawson, Executive Vice President, Corporate Development and Chief Sustainability Officer; Susan Anderson, Senior Vice President, Legal and General Counsel; Candace Newman, Senior Vice President, People Services; Eric Zimpfer, Head of Downstream; and Geoff Murray, Executive Vice President, Commercial. They are all available to answer your questions following the formal portion of this meeting. Also with us today and available to answer questions are Ryan Lundeen and Ali Arnell, partners at our auditor, PwC. The rest of the Cenovus leadership team and our Board members are also joining the meeting but are in listen-only mode.

The business of today's meeting is described in the notice of meeting and management information circular dated March 10, 2026, which were delivered and filed in advance of this meeting. You can find a link to the circular and annual report by clicking on the Document icon found at the left or on the bottom of your screen, and they can also be found on Cenovus' website and on SEDAR+.

The business of today's meeting is to receive the audited financial statements for the year ended December 31, 2025, and to consider and vote on 3 items as set forth on Pages 12 to 14 of the circular. First, the appointment of our auditor; second, the election of directors; and third, the nonbinding advisory vote on the corporation's approach to executive compensation. For efficiency, we have prearranged for Andrew Dahlin and Kam Sandhar, both Cenovus shareholders, to move and second the formal business motions. We will now proceed with the formal business of the meeting.

The first item of business is to receive the consolidated financial statements and the auditor's report for the year ended December 31, 2025. The 2025 annual report containing these audited financial statements was delivered to shareholders in advance of the meeting, and a link can be found at the left or bottom of your screen, as well as on Cenovus' website and on SEDAR+.

We will now move on to the voting items. A reminder, the polls are still open for voting on the items of business. As mentioned earlier, voting will be conducted by online polling, and voting options will be visible on your screen if you are a registered shareholder or duly appointed proxy holder. If you have already voted, you don't need to take any further action unless you would like to change your vote.

Item 1 on the agenda is the appointment of our auditor as set forth on Page 12 of the circular. Could I have a motion?

Mr. Chair, my name is Andrew Dahlin, and I move for a vote on Item 1 to appoint our auditor.

Thank you, Mr. Dahlin. Is there a seconder for the motion?

Mr. Chair, my name is Kam Sandhar, and I second the motion.

Thank you, Mr. Sandhar. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

Okay. We will now move to Item 2 on the agenda, the election of each of the director nominees as set forth on Page 13 of the circular, being: Stephen Bradley; Keith Casey; Michael Crothers; James Girgulis; Jane Kinney; Eva Kwok; Melanie Little; Richard Marcogliese; Chana Martineau; Jon McKenzie; Claude Mongeau; myself, Alex Pourbaix; Frank Sixt; and Rhonda Zygocki. There having been no further nominations received in advance of the meeting in accordance with Cenovus' bylaw #1, I declare the nominations closed. Could I have a motion?

Mr. Chair, my name is Kam Sandhar, and I nominate each of the individuals you've listed, and I move that each nominee be elected a director of Cenovus.

Thank you, Mr. Sandhar. Is there a seconder for the motion?

Mr. Chair, my name is Andrew Dahlin, and I second the motion.

Thank you, Mr. Dahlin. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

We will now move on to Item 3, a nonbinding advisory resolution to approve the corporation's approach to executive compensation as set forth on Page 14 of the circular. Could I have a motion?

Mr. Chair, my name is Andrew Dahlin, and I move for a vote on Item 3, a nonbinding advisory resolution to approve the corporation's approach to executive compensation.

Thank you, Mr. Dahlin. Is there a seconder for the motion?

Mr. Chair, my name is Kam Sandhar, and I second the motion.

Thank you, Mr. Sandhar. Are there any questions on the motion?

There are no questions on the motion.

[Voting]

Online polling is now closed. In order for today's resolutions to be passed, the approval by a simple majority of the votes cast by shareholders who voted online or by proxy at this meeting must be received. I have received the scrutineer's report and confirm as follows: PwC is appointed as auditor of Cenovus, as approved by 99.67% of the votes cast by shareholders. Each director nominee is elected to the Board. The nonbinding [ advisory resolution ] to accept the approach to executive compensation was approved by 97.39% of the votes cast by shareholders.

I direct the Secretary to file the final scrutineer's report with the minutes of the meeting. Details of the voting results will be filed with securities regulators and included in the news release which will be issued later today.

The formal business of the meeting is now complete. May I have a motion to conclude the meeting?

Mr. Chair, my name is Kam Sandhar, and I move that this meeting conclude.

Thank you, Mr. Sandhar. I declare the formal business of this meeting is concluded. I now invite Mr. Jon McKenzie, Cenovus' President and Chief Executive Officer, to give his remarks, which will be followed by a question-and-answer session.

Thank you, Alex. On behalf of Cenovus, our employees and our shareholders, I'd like to thank you for your continued leadership, stewardship and as Chair of the Board. I'm looking forward to another year of close collaboration in 2026.

Now I'd like to first bring your attention to the advisory on the screen, which refers to some of the information I'm about to discuss. Additional information about forward-looking statements and financial information can be found in our first quarter news release, first quarter management's discussion and analysis and our 2025 annual report. These are all available on cenovus.com under Investors.

I will begin with safety, the cornerstone of everything we do. The safety of each of our employees and contractors is our top priority, supported by a safety culture that is deeply embedded across all our operating sites. Our strong performance in 2025 includes top-quartile process safety performance for the third consecutive year. We remain committed to continuous improvement to ensure our people go home safe every day.

In 2025, we executed a long list of priorities across the company. Operationally, our teams delivered exceptional performance, setting multiple Upstream production records across our assets and demonstrating top quartile downstream reliability. Our Upstream production of 834,000 BOE per day was the highest ever for Cenovus, up 3% from 2024, and that doesn't include the impact of acquiring MEG Energy and its Christina Lake asset. We exited the year producing over 970,000 BOE per day.

In the Downstream, our refineries ran reliably through the year with a combined utilization rate of 95% across the Canadian and U.S. segments while enhancing the competitiveness of their margins and unit costs. We also executed major milestones on our highly efficient growth projects, completing the Narrows Lake tieback to Christina Lake, a first of its kind extended steam reach pipeline, facilities work on the Foster Creek optimization project, which delivered production growth well ahead of schedule, and construction, installation and tie-ins of the West White Rose platform.

2025 also saw us complete two significant transactions. We closed the acquisition of MEG on November 13, adding 110,000 barrels a day of top-tier resource located next to our largest producing SAGD asset. Consolidating the Christina Lake area will generate a projected $400 million of annual operating and corporate synergies by 2028, with work already underway. We also sold our [indiscernible] and now have full operational, commercial and strategic control of our Downstream business, which is a critical component of our heavy oil value chain. Together, these transactions position the company for continued growth and value creation over the long term.

From a financial perspective, our balance sheet remains robust, and we continue to prioritize the flexibility that comes with a $4 billion net debt level, which represents an underlevered balance sheet. Following the MEG acquisition, our capital allocation framework was adjusted to balance deleveraging and shareholder returns while we maintain a long-term net debt target of $4 billion.

In 2025, we returned about $3.8 billion to shareholders through dividends, share repurchases and the redemption of preferred shares. Strong operational performance, meaningful progress capturing MEG synergies and a robust balance sheet positions us well to continue to deliver value from our portfolio of assets. With the completion of our 3-year investment cycle this past year, we have delivered incremental production increases while reducing the amount of growth capital we plan to spend year-over-year.

At Narrows Lake, we used extended steam reach to unlock some of the best resource in our portfolio. Production rates at Christina Lake continue to rise as we bring down our steam-oil ratio and allocate more steam to the newest pads at Narrows Lake. At Foster Creek, we delivered the optimization project ahead of schedule, increasing capacity of one of our largest and highest quality assets by approximately 30,000 barrels per day.

Drilling at West White Rose has now commenced, and we expect first oil in the third quarter of this year. This asset is expected to reach peak production of about 45,000 barrels a day net to Cenovus by 2028, and its high netback production and decreasing capital spend position it to generate considerable free cash flow. Looking forward, our Christina Lake North expansion project will drive production growth of about 40,000 barrels per day by the end of 2028 as we head 2 new steam generators and debottleneck the water and oil handling capacity. We plan to exit 2026 at a production rate of about 1 million BOE per day, a significant and exciting milestone for our company. It is a testament to all the talented people that work for us. With these key growth projects online, we will continue to grow to around 1.1 million BOE per day by 2028.

We remain financially disciplined and do not expect to change our capital plans in response to short-term volatility and commodity prices. Our opportunity-rich portfolio gives us optionality for investment in the long term, and you should expect us to continue to find and invest in high-return growth projects across our business going forward. When looking at investments, we test economics to meet our return thresholds at USD 45 WTI and expect to maintain our overall capital spending in and around the $5 billion mark in both 2026 and 2027.

As we enter 2026, our business has never been stronger. We remain focused on protecting and extending our competitive advantages: a low-cost, long-life resource base; a conservative capital structure; disciplined cycle-resistant investment and continued commitment to increasing returns to our shareholders.

With these foundations in place, we are well positioned to navigate the year ahead. We know the geopolitical unrest has put more attention than ever on energy security. We will continue to focus on competitiveness and advocate for regulatory and policy environment that allows us to produce the resources North America and the world need. I want to thank our shareholders, our Board and our employees and contractors for your ongoing support, and I'm looking forward to the exciting year ahead.

Thanks, Mr. McKenzie. We will now answer questions that were submitted online. Please click on the Questions tab found at the left or bottom of your screen to submit your question. We may group questions that are similar for a single response. All questions and our answers will be posted on Cenovus' website within 5 business days. If we run out of time today and don't get to your submitted question, it will be posted there as well.

We have the following question from Jessica Carradine with Investors for Paris Compliance, representing shareholder Solal Foundation. The question. We have withheld our vote for the reappointment of the auditor due to ongoing gaps in the portrayal of decommissioning liability in Cenovus' financials.

My question is for PwC. Auditing standards require the disclosure of critical audit matters which communicate highly material areas that involve significant estimation uncertainty. In the 2025 financial statements, Cenovus lists decommissioning costs as a key area for estimation uncertainty. In your audit of Cenovus, how did you determine that decommissioning liabilities did not meet the threshold to be included as a critical audit matter? And what procedures did you perform to assess the sensitivity of these liabilities to core assumptions such as asset lives or the discount rate?

Hello, it's Ryan Lundeen, Assurance Partner from PwC, and thank you for the question. I'd like to address both parts. First, how critical audit matters are determined under PCAOB standards, and second, our work over decommissioning liabilities in the Cenovus audit.

First, on the CAM determination framework. Under PCAOB auditing standards 3101, a critical audit matter is not simply any material or complex area of the financial statements. It is specifically defined as a matter that was communicated or required to be communicated to the Audit Committee, relates to accounts or disclosures that are material to the financial statements and involved especially challenging subjective or complex auditor judgment.

It is important to emphasize that the CAM threshold is about the nature of the auditor's judgment, not solely about the significance of management's estimate or the materiality of the account. Many financial statement areas are material and involve estimation uncertainty, but do not rise to the CAM threshold because the auditor's work, while rigorous, did not involve especially challenging subjective or complex judgment relative to other areas of the audit.

On the second part, on decommissioning liabilities specifically, we do not opine on individual balances. The fact that decommissioning liabilities were not identified as a CAM in our audit report does not mean they receive less audit attention than necessary. It means that in the specific facts and circumstances of the audit, our procedures over this balance did not involve the degree of especially challenging, subjective or complex auditor judgment that distinguishes a CAM from other significant audit areas.

On that note, we did perform our audit in accordance with standards of the Public Company Accounting Oversight Board. Our responsibility as set out in our auditor's report indicates that we provide an opinion on the consolidated financial statements taken as a whole in accordance with IFRS. We provided an unqualified opinion in relation to those statements based on the applicable accounting and auditing standards. If there had been material deviations from such standards, we would not have been able to issue an unqualified audit opinion. Thank you.

Thank you, Mr. Lundeen. We have a second question for -- from [indiscernible]. Given the scale of Cenovus' decommissioning liabilities and the number of judgments required to estimate them, what specific steps did the committee take to scrutinize the assumptions applied by management, such as the asset lives and the discount rate, and to satisfy itself that this area receives sufficient audit scrutiny, particularly in light of the absence of any critical audit matter relating to decommissioning liabilities?

It's Alex Pourbaix. The Chair of the Audit Committee is in listen-only mode, so I will respond to this question. And I would state that Cenovus provides disclosure relating to our decommissioning liabilities, including the undiscounted amount of estimated future cash flows to settle all our decommissioning liabilities. We exercise reasonable judgment to assess liabilities and estimate future values. All of our disclosures are made in accordance with IFRS accounting standards.

With respect to timing, it is important to note that oil and natural gas currently make up over 50% of total energy demand, and that demand continues to grow. For example, the International Energy Agency expects oil demand to remain above 100 million barrels per day by 2050, and upstream oil production will require about $540 billion in annual investments through 2050 to maintain global supply. And I think it is important to note that recent global events have only reinforced that oil and gas remain critical strategic commodities for continued economic development. This points to an incredible opportunity for Canada to deliver our oil and natural gas to a growing world for decades to come.

Thank you, Mr. Pourbaix. We have a question from Jeff Carlson. Using share buybacks as a way to create value for shareholders is a coin flip at best. Further, using company earnings to repurchase its own shares is not in keeping with a vision of long-term growth. Doesn't it make more sense to deploy this capital in ways that will actually grow the company or to return these earnings directly to shareholders who have risked their own money in the form of higher or special dividends? With this in mind, my question is, why has the Board adopted this policy of repurchasing its own shares?

It's Alex again. I will also take this question. And I would say that our framework very intentionally delivers a balance of shareholder returns and deleveraging, targeting to return approximately 50% of excess free funds flow to shareholders while net debt is above $6 billion, with the remainder allocated to deleveraging. As we have said before, our capital allocation framework is not formulaic, but guidelines, and shouldn't be viewed as something we manage quarter-to-quarter, but over longer time frames.

To the extent that oil prices remain elevated, you could see us having more bias towards deleveraging to bring the debt down faster. Paying debt down faster allows us to protect our equity holders if we do see weaker commodity prices in the future. While returns on buybacks aren't as attractive at high prices, we continue to see value in repurchasing our shares, and we'll continue to do so.

Our track record has been strong. We have repurchased 337 million shares for an average price of $23.25 a share, an attractive price in relation to our view of intrinsic value.

Thank you, Mr. Pourbaix. There are no further questions.

Great. So on behalf of your Board of Directors and leadership team, thank you for attending our Annual Meeting of Shareholders.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's First Quarter 2026 Results Conference Call. [Operator Instructions]

As a reminder, this call is being recorded.

I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2026 First Quarter Results Conference Call. On the call this morning are CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. Then we'll open the line for Jon, Kam and other members of the Cenovous management team to take your questions.

Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information non-GAAP measures and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus' annual MD&A and our most recent AIF and Form 40-F.

And as a reminder, all figures we referenced on the call today will be in Canadian dollars, unless otherwise indicated. For the question-and-answer portion of the call, please keep to one question with a maximum of one follow-up. You're welcome to rejoin the queue for any other follow-up questions you may have. We also ask that you hold off on any detailed modeling questions. You can follow up on these directly with our Investor Relations team after the call.

I will now turn the call over to Jon. Jon, please go ahead.

Great. Thank you, Patrick, and good morning, everyone. As always, I'm going to start with our top priority, which is safety. At our Toledo Refinery, we recently celebrated 12 consecutive months and over 3.3 million man hours without a recordable injury. This milestone was delivered during a period which included a major turnaround on the east side of the plant, work that carries additional risk given the elevated activity and nonroutine work.

And the business delivered consistent execution, bringing that asset back online safely and 11 days ahead of schedule. The performance reflects the commitment and dedication of the Toledo team supported by the strength of our safety systems, which focus on leadership engagement, a stop work culture and recognizing strong safety behaviors. So congratulations to the Toledo refinery, they continue to reinforce the belief core to Cenovus. Strong operational performance starts with doing the work safely every day.

So now turning to our results. Our priorities this quarter remain unchanged. We've stayed focused on executing our business plan, delivering exceptional operating performance and advancing our growth projects. The focus on execution translated into strong first quarter results with upstream production exceeding 972,000 BOE per day, supported by record oil sands volumes in our first full quarter following the MEG acquisition. While geopolitical events late in the quarter resulted in increased price volatility and heightened uncertainty, our approach to operating our business remains the same. Our results reflect the strength of our business model. We are a reliable supplier of crude oil, natural gas and refined products to both North American and global markets.

Now starting with oil sands, the Christina Lake production averaged 359,000 barrels per day in the first quarter, supported by strong well performance at Narrows Lake. Narrows Lake is now producing over 65,000 barrels a day from the first 4 well pads with a steam oil ratio below 2%. Individual well performance has been exceptionally strong and exceeds our internal expectations. Our best wells at Narrows Lake are now producing over 5,000 barrels a day. Bringing on a project of this complexity and scale to 65,000 barrels a day in just over 9 months is a testament to the quality of the asset and the capability of our technical project and operating people.

Production from Narrows Lake will continue to ramp up as we bring on additional well pads and we expect to reach 80,000 barrels a day later this summer. Now integration work at Christina Lake North is also progressing well. We've completed a delineation and seismic program in the quarter and initiated the redevelopment program ahead of schedule. The first of the 42 redevelopment wells was spud in March and began producing in April. Initial production results are exceeding our internal forecasts. And as we execute our redevelopment program, we will see increased production from Christina Lake North throughout the remainder of 2026.

At the same time, installation of the first new steam generators progressing ahead of schedule with startup expected before the end of the year. And with the acceleration of the redevelopment well program we will exceed the $150 million synergy target we set for ourselves in 2026. Not to be outdone at Foster Creek, we set another quarterly production record of 223,000 barrels per day, with peak rates exceeding 230,000 barrels a day in March. These production rates were driven by the optimization project, which was delivered ahead of schedule and strong operating performance from our new well pads. We plan to start up an additional 4 well pads in 2026.

The turnaround of Foster Creek phase began in April has progressed well to date with limited production impact. We continue to optimize our turnaround activity across our Oil Sands portfolio which will result in more efficient and lower impact turnarounds. At Sunrise, production in the first quarter was just over 59,000 barrels per day. During the quarter, we successfully started up the first of the 4 new well pads on the East side development area of Sunrise. These pads are some of the largest Cenovus ever drilled targeting high-quality rich pay of up to 50 meters thick. Now early indications from the first pad have met and exceeded expectations. We've seen recent daily rates to reach as high as 68,000 barrels per day, and with another 3 pads to come on in this area, we expect to continue to grow production from Sunrise all the way through to 2028.

The Lloydminster Thermals delivered another strong quarter, averaging 102,000 barrels per day supported by the continued outperformance of the redevelopment well program. Recent redevelopment wells have surpassed our expectations in some of our longer laterals, nearly doubling our initial forecast. Of note, now this performance excludes any contribution from Vaughan, which we sold in December and with limited initial volumes coming from Rush Lake which continues to ramp up following the 2025 outage. At our Asia Pacific assets, production was over 57,000 BOE per day in the quarter, and production from the region continues to impress, delivering consistent and robust free cash flow to Cenovus. In the Atlantic, production was over 18,000 barrels a day in the quarter, with strong performance from Terra Nova and the base White Rose field. Of note, we continue to benefit from the high netbacks and Brent plus pricing in that region. At West White Rose, we have now completed all the elements of construction and commissioning and have commenced drilling from the offshore platform, marking another important milestone for the project.

I just couldn't be more proud of what this team has been able to deliver through an extreme challenging winter and challenging weather conditions, which really extended into the early spring. With drilling operations underway. We now expect first oil from the project later in Q3. In the Downstream, first quarter results were once again very strong. The Canadian refining business delivered throughput of 115,000 barrels a day in the quarter, or utilization rate of about 107%. During the quarter, we entered into agreements to sell our Canadian commercial fuels business, which includes cardlock and travel center locations, for expected cash proceeds of $275 million.

Now this transaction is expected to close in the second half of 2026, pending approval from the Competition Bureau and other customary closing conditions. In U.S. refining business, crude throughput averaged 343,000 barrels a day or approximately 94% utilization. Our PADD II refineries continue to deliver strong operational availability, allowing us to optimize margins as the opportunities arise. Adjusted market capture was 114% for the quarter, reflecting a market environment that continued to favor our configuration, including our ability to process heavy crude and our low gasoline to distillate yield ratio.

So now I'll turn it over to Kam to walk through some of our financial results.

Thanks, Jon, and good morning, everyone. In the first quarter, we generated approximately $4.4 billion of operating margin and $3.4 billion of adjusted funds flow. Operating margin in the upstream was over $3.7 billion, exceeding the prior quarter due to the higher production in the oil sands, rising benchmark oil prices in late February and March. Our first quarter results included over $1.5 billion of taxes and royalties, which rose alongside commodity prices. Oil sands nonfuel operating costs were $8.92 a barrel in the first quarter about $0.50 per barrel higher than the prior quarter due to planned maintenance and workover activities as well as higher GHG compliance costs. Downstream operating margin was $734 million, which was -- which included $504 million of inventory holding gains with results in the quarter benefiting from competitive and reliable operations and improved product pricing.

In U.S. refining, operating costs were $11.74 a barrel or $0.20 per barrel lower than the previous quarter, reflecting lower planned maintenance offset in part by modestly lower throughput and higher energy and electricity costs. Adjusted market capture, as Jon mentioned, was 114% with economic conditions continuing to favor the configuration of our refineries, widening heavy crude differentials, strong diesel and jet fuel margins and the relative strength of secondary products versus gasoline were all tailwinds in our results.

Looking forward, capture rates are expected to normalize through the spring and summer. However, we are seeing significantly higher volatility in product prices in the current environment and how these prices settle relative to each other over the coming months may impact our capture rates. Capital investment in the first quarter was approximately $1.2 billion, supporting sustaining activity across the business, along with investment in growth and optimization projects at Christina Lake North, Sunrise, Foster Creek and West White Rose. Our capital guidance for 2026 remains unchanged at $5 billion to $5.3 billion.

Turning to net debt. At the end of the quarter, our balance was approximately $8.1 billion, a modest decrease from the prior quarter with higher adjusted funds flow, partially offset by a $1.1 billion increase in noncash working capital. This increase in working capital is typical of periods where commodity prices rise to the extent we saw through the latter part of the quarter. As current commodity prices -- at current commodity prices, we would expect the pace of deleveraging to accelerate significantly in the coming quarters. Shareholder returns in the first quarter were $1 billion, including $356 million in common share purchases $379 million through dividends and $300 million through the redemption of our Series 1 and 2 preferred shares. These were the last outstanding series of preferred shares of the original $900 million which we have redeemed over the past 2 years, resulting in a lower cost and a simplified capital structure going forward.

Consistent with our commitment to grow shareholder returns, our Board of Directors has approved a 10% increase to the annual base dividend to $0.88 per share. This increase reflects the growth of our business and the strength of our operations, which both fund the dividend and our sustaining capital requirements at a $45 WTI oil price.

I'll now turn the call back to Jon for some closing remarks.

Great. Thanks, Kam. Now as we close the book on the first quarter, it's worth reiterating that volatility and geopolitical uncertainty are not new to our industry. We've seen many cycles over the decades. It's why we constructed our capital structure, financial framework and operating model to perform through a wide range of market conditions. While higher benchmark prices underscore the operating leverage and the cash flow generating capability of our business, they do not change our strategy.

Our focus remains on executing the business plan that we laid out in December. Our company responded accordingly this quarter, delivering consistently strong operational performance across both upstream and downstream. We increased our production rates, ran our refineries with high availability and utilization, completed the West White Rose project and accelerated the integration of Christina Lake North. With our unique high-quality long reserve life assets, coupled with our disciplined capital allocation framework, and dedicated and highly competent people, our business performance continues to press our competitive advantages.

Now before we open the line for questions, I want to talk about an opportunity that we as Canadians have, if we choose to seize it. The events of the last few weeks have clearly shown in the world that energy security is national security and energy security is economic security. The reality is the world needs affordable, abundant, reliable energy from all sources, regardless of how we label them. The world will require hydrocarbons to form a material component of the energy supply mix for decades to come. And there are no examples of first world nations that don't also have access to affordable, abundant, reliable energy. It is essential and irreplaceable for a high-quality standard of living. In Canada, we are blessed with some of the highest quality, longest life resources in the world, including the Canadian oil sands.

These resources not only supply Canada with affordable, reliable, abundant energy we use and take for granted every day in our modern lives, but they also fund our social benefit network, schools, hospitals, roads, pensions through the payment of taxes and royalties and the creation of high-paying jobs. And yet the national dialogue on further development of the oil sands has been myopically focused on the climate agenda and climate policy, which have ignored a multitude of benefits that responsible oil sands development is brought to this country. Of the top 10 global producing oil nations, Canada is recognized as the most responsible producer across a broad range of metrics.

The result of this myopic dialogue, however, is that we have created a set of national policies and regulations that make resource development and investment in Canada uncompetitive for the rest of the world. Only one greenfield oil sands project has been approved and built since 2013. And Capital has left candidates to plan more competitive jurisdictions and Canada has ceded high-paying jobs, taxes and royalties to countries like Russia, Iran, Iraq in the United States. Our uncompetitive national climate policies and regulations have not reduced global demand for oil by 1 barrel. It just means that the oil, the world demands and the associated benefits are not coming from or to Canada. It does the country no service to negligibly reduce the impact of climate change over the next century if we materially erode our social benefit network over the next 15 years.

And yet, we have an opportunity to course correct. If we recognize that we are in a global competition for investment and we choose to compete, we have the opportunity to become the energy superpower that our Prime Minister has advocated for, but continuing to add incremental costs and protracted expensive regulatory processes to the energy industry drives investment in Canada. For example, the industrial carbon tax is unique to Canada. No other major oil producing in the nation in the world has one.

The result is this tax does not incent decarbonization of the Canadian industry, but instead incents industry to invest outside of Canada. This is our time. We should be an energy superpower and we need to take the right decisions to unlock investment and growth to the benefit of our economy and all Canadians.

And with that, I'll open it up to your questions.

[Operator Instructions]. Our first question comes from Dennis Fong with CIBC World Markets.

Congrats on a great quarter as well as the higher synergy capture.

Nothing is going on in the market this morning.

My first question is related to a lot of the geotechnical work that you alluded to in your prepared remarks, especially on the Christina Lake North or MEG legacy assets. I was just curious, as you start to see some of the results of the redevelopment wells roll in, how does that maybe change the way you're either thinking about the development across the asset or even maybe looking at the facility expansion project or the optimization of that expansion project as you go forward?

Yes. As I mentioned, Dennis, I'll let Andrew fill in some of the blanks that I'm going to miss. But we really took the opportunity over this winter to really start to develop our own model for the Christina Lake North asset based on the geotechnical work that we had done. So we drilled about 40 delineation drill -- or wells, shot 3D seismic and 4D seismic across the asset. And it's really confirmed, I think, what we knew before in that this is a Tier 1 expandable resource that's got a reserve life that's measured in decades, not in years.

So as we kind of go forward and think about development to that, the first step for us is to go after some of these redevelopment wells because this is oil that really comes back to the plant and doesn't consume any teams. So it really drives down the SOR and allows us to optimize the facilities as they are in place today. So what you'll see from us through the rest of this year as we finish that program is the well today, production today is 110,000 barrels a day, and that's going to grow through the rest of the year. You'll see kind of month-over-month improvements as we bring on more and more development wells. The other thing that I mentioned is we put in our base case additional steam capacity, a fifth and a sixth OTSG. The fifth is ahead of schedule. That's going to add additional steam capacity.

We'll bring that on before the end of the year, and you'll see the results of that come through in 2027. But long story short is we're well ahead of what we put in our base case in terms of the FID case for MEG. And it really, to your point, gets us thinking about what is the further expansion beyond the $150 million that we've put into the public domain today. Andrew, I don't know if you've got anything else you want to add to this.

Yes, maybe add a couple of things, Dennis. Yes, obviously, just to add a couple of sort of factoids on the redevelopment program. We target drilling 40 wells this year, 5 are drilled, 3 are on stream. And I think as Jon mentioned in his opening comments, those 3 -- first 3 wells are delivering above expectation. I think as we look broader and further out, as a function of that delineation program, we executed here in Q1, we've identified something like 250 redev opportunities. So we've got a rich portfolio for years ahead of us there. And then on the facility optimization, just to add one more detail there. We actually got 3 waves of facility projects that are all in on the go at the moment. First one is indeed the fifth OTSG coming on later this year.

Second one is an expansion of the water and oil treating facility. We call that the facility expansion project. But what we're also looking at is actually looking at an opportunity to connect the 2 facilities, CLN to the CL facility. And that's really where the next big wave of synergies comes. And yes, frankly, probably a great opportunity at the Investor Day here in Q1 2027 to provide you a good update on that. And I'd say with some confidence we're going to deliver this year's synergy target of $150 million. In fact, we're going to exceed that. I'm equally very confident that we're going to deliver and exceed the $400 million per year synergy target for 2028.

Yes. Dennis, this has just been a great acquisition for us. For us to be able to get such a huge Tier 1 resource that sits right next to what we do and it's right in the wheelhouse of what we do and is going to provide decades of returns to investors. It's just been a terrific acquisition, and we're really happy with what we got in that acquisition.

Definitely. I really appreciate that color from both of you in terms of the opportunity set going forward. Staying in the -- for my second question and staying the upstream, I wanted to focus in on Sunrise. Again, from your prepared comments, it sounds like you're getting close to that 70,000-plus barrel a day level at that asset and you don't even have all of these kind of new well pad or well pads online. Can you talk towards where maybe the next phase of maybe bottleneck situations happen to be at the Sunrise asset? Is it more facility driven? How do we think about a, we'll call it, exceeding the opportunity that you've highlighted in the 2028 time frame? And what does that kind of involver look like on a go-forward basis?

Yes. Dennis, oe of the things that we haven't been sitting on our hands at Sunrise and you haven't necessarily seen the production growth until this quarter. But we've always taken the opportunity to debottleneck the plant in preparation for where we're going with this. So we've done a lot of work on the steam systems, a lot of work on the cooling systems, a lot of work on water handling as well as cooling in that plant.

And one of the things that may be somewhat invisible to you in the last quarter, we took the opportunity to take 1 of the 2 trains down to do some overhead steam work, and we ran 1 train at 51,000 to 55,000 barrels a day. So there's lots of capacity inside this plant to continue to ramp up production as we go forward. And I think you're kind of quite right to note that with even just the first few wells from the first of the V pads coming on, we're kind of 68,000 barrels a day. So we think there's lots of opportunity before we hit the next constraint inside this plant. And it's something that we're going to take a hard look at going forward is how do we go beyond 75,000 barrels a day at Sunrise because it's an immense resource. And a lot of good work has already happened in terms of debottlenecking those facilities in preparation for going higher.

Next question is from Menno Hulshof with TD Cowen.

I'll start with a question on market capture, if that's okay. You mentioned -- I believe you mentioned potential normalization of the 114% that you achieved in Q1 in the coming months and quarters. And I know there's a lot of moving parts here, but what do you think market capture normalizes to? And more specifically, can we expect a higher floor on that measure going forward relative to what you were talking about in late 2025?

Well, I think we continue to push you towards 70% metal, but I'll let Eric speak to this in a little bit more detail.

Yes, it's a great question. I would say, certainly, a very good quarter and very proud of what the team delivered. I would say it's certainly built on the back of strong operations and strong commercial optimization, and we expect that to continue, absolutely no change in that performance. I think when I look at the market environment in the first quarter, there were a number of things that I think very much favored or supported, I think, our configuration.

And so you look at the heavy diff widening that plays certainly into our portfolio and how we're built to process heavy crude. I think the strength of diesel as well as Jet, again, I think, reinforced our configuration and gave us an opportunity there for a higher market capture. And I would also point to the relative pricing of secondary products relative to gasoline. And so with those secondary products pricing strongly relative to gasoline, it gives us a higher market capture potential. So you put all those things together in the first quarter and you come up with a pretty strong number that we're proud of. As I look forward into the second quarter, and as Jon talked about it normalizing to 70%, there's a couple of factors I'd maybe call your attention to.

One on the feedstock side, I would say when you look at some of the pricing around domestic light sweet crudes relative to TI, so crudes that we do run that is becoming increasingly expensive and a widening relative to that TI marker. And so that impacts the market capture available to us to the negative I would also point to, as I mentioned, benefiting us in the first quarter, as the gasoline crack strengthens and it widens against that secondary product pricing, that also impacts the market capture available to us. So while our performance, we expect to stay the same, expect to have really good reliability, really good operations and really good commercial optimization.

The market environment as it evolves into the second and third quarter. And it's frankly seasonal, you see it every year. These factors show us that our market capture potential will be lower as we get into 2Q and 3Q. And again, that's back into that kind of 70% range that we've talked about previously.

That was very helpful. Maybe the follow-up question is on -- because it's getting a lot of airtime, the Christina Lake North development program, you mentioned, I believe, another 250 locations. And so my question is, is 40 wells per year a reasonable cadence? Or would you consider accelerating that a little bit in 2027 and 2028. I'm just asking that because I'm assuming that would be close to the top of your opportunity set in terms of full cycle returns.

No, I'm going to let Andrew answer this more fully, and you're absolutely right that the opportunity set continues to grow and the 250 locations that we had are not all equal. But you also have to remember to Menno, we've got 2 well pads that we're starting up this year as well. And so the pacing and staging of your redevelopment really is limited by the internal constraints that you have inside your plant and your oil and water handling systems.

But as we go forward, what you should expect from us at Christina Lake North, as we talked about, is steadily increasing production, steadily decreasing SOR. And then with the additional more steam, you're going to see a material movement in the production. But the pacing and staging of redevelopments and redrills, to your point, is not yet optimized, and that's something that we'll lay out when we get into Investor Day in January.

I don't have a lot to add actually, Jon. It's really not -- it's Andrew speaking. It's really an optimization of a fully integrated system between the subsurface and the facilities. And obviously, we're going to -- we lean towards the readers because they come on with such -- with instantaneous oil and such low SORs.

Next question is from Alexa Petrick from Goldman Sachs.

Our first one is just around capital allocation priorities. I mean as we think about the elevated commodity price environment and incremental cash flow generation, any updated thoughts on how you're balancing pay down and capital returns?

Good morning, Alexa, it's Kam. I think at the highest level, I would say not a lot has changed. Our framework, I would say, we've kind of had intact now for the last few years. I think, first, what I would start with is we've set our capital program this year. We've got our plan with our growth projects continue to progress. We've got embedded growth in our business going into the fourth quarter of this year into next year.

So that $5 billion to $5.3 billion of capital spending, you shouldn't expect any change. That is -- even though we are seeing higher prices than what we budgeted for at the beginning of the year. I think our plan as it relates to organic capital is unchanged. I think beyond that, obviously, you saw we also increased our dividend. And again, that's kind of normal course, I would say, too, that, that dividend needs to be sustained and fully funded in a lower price world. And that's really anchored to the growth that you're seeing in the portfolio, not just this year, but even as we think about where we're going to be in 2027 and 2028.

And then beyond that, really, it comes down to what is our kind of driver between deleveraging and share repurchases. And I think what we've outlined before is that we've got a guideline in place where as the debt moves from what was around $8 billion down to $6 billion, we're going to kind of be 50-50 and they will move to a higher proportion of buybacks as we get the debt down further.

But one of the things I would say is, clearly, this price environment we're in today, it is not what we expected when we started the year. I think we are really viewing it as something that's more short term in nature. So with that in mind, I think we're probably taking a bit of an opportunity to probably have a bit of a bias towards more debt reduction versus buybacks, not to say that we don't see a return on the buyback. I think we continue to see a return, and you'll see us stay in market. But when you think about proportions of our free cash flow, I think nobody should be surprised to see us have a little bit higher proportion to deleveraging in the short term.

Okay. That's very helpful. And then our follow-up is really just around West White Rose. I mean any color there around what the gating items are for first oil and timing around the cash flow inflection?

Sure. Andrew, why don't you take that one and maybe just kind of draw a path between where we are today and first oil.

No, sure. Absolutely. Yes. So West White Rose, as Jon talked in his opening comments, project's completed. We've got the operating authority from the regulator, and we -- and drilling has commenced. So over the next -- the first well there kind of comes in 3 phases. Phase 1 is obviously drilling the well. So this is roughly 6,000 meter long well, it's a horizontal well. We'll do that. Then we go into the completion phase and then the tie-in phase. So drilling completion and tie in, that's what we're saying we should be complete have completed by late Q3 of this year and then, hence, get the first production on stream. Having done that, we immediately go to the second well. And then we just continue through a repeat of that program through roughly 30 to 35 wells, which will take us through the next 4 years. So we'll see first production here late Q3 this year and then a steady ramp-up of production from West White Rose from current 0 up to a plateau of 85,000 barrels a day by late 2028, noting that's the gross volume.

Yes. It's a pretty exciting day for us. This has been a long time coming. And going through the commissioning process and the work that was done on SIT really confirmed that the construction was first rate, high quality, and we really got this to a point now where we're in operations. And so the project is now behind us, really happy with how it's functioning technically. Everything is kind of all systems go as we kind of drill the first of 7 wells in the first well package. So a very exciting day for us.

Actually, Jon, can I just add one thing. I think it's an exciting day for many people. For us as an organization for our partners, but also for the province of Newfoundland. This is a world-class project that's come on stream that's going to benefit the companies but also in Newfoundland for decades to come.

Our next question is from Greg Pardy from RBC Capital Markets.

Thanks for the detailed rundown. Jon, I couldn't help, but think a little bit about your comments on the regulatory framework and carbon taxes and so forth. And I'm trying to get at the root of that a little bit in terms of -- has there been any change perhaps in your thinking maybe over the last year or so. As it relates to regulatory reform, decarbonization, export market diversification and so forth? Like how are you and perhaps -- well, you can only speak for yourself, I you realized. But how -- are you thinking about that differently now than you might have a year ago? Has anything changed that way?

No, Greg, I think we're -- we've been entirely consistent through time. What we have to do, and I think this was part of where the MOU was going is we have to have a view where pathways production and pipelines all come together. And the reality is that with comprehensive policy reform that allows for our significant investment in this base and the production piece is lacking.

And so we need a set of policies that are consistent with investment. We need a set of policies that recognize that we, as Canadians, compete for capital, and we have to compete in a different way. We have not grown oil sands on a greenfield basis for over 10 years. And if we are going to fill 1 million-barrel a day pipeline to the West Coast, it's got to come with growth, and that growth has to come capital and that capital has to be competitively advanced vis-a-vis, where else it can go?

Okay. Okay. All right. I think that's clear. And then, Jon, in the past, even back at the refinery tour in Ohio back in the fall. I mean, part of the strategic role that your U.S. downstream plays is just the potential for congestion in Western Canada. Now there have been -- there's debottlenecking underway. There's various initiatives on the mainline and so on. But what's the in-house view at Cenovus in terms of what maybe the egress picture is looking like out of Western Canada is the concern around congestion maybe as much as it was before?

Yes. No, it's -- I'm going to let Jeff answer the back part of your question, but you're absolutely right. Our refineries provide us with the most economic egress out of this province versus any other opportunities we have -- what is kind of interesting right now is we have a number of opportunities to a number of different locations by a number of different midstreamers that potentially could offer additionally aggress to producers going forward. .

But Jeff, maybe you can talk a little bit about how you're seeing the environment for egress and midstream participation in ex-Alberta egress.

For sure, Jon. And Greg, I think Jon hit the high level on it really well, which is through some pretty hard work over the past couple of years by Cenovus and by industry and a number of midstream partners we are seeing a nice steady flow of creative egress alternatives come to market.

I would say, we've seen what's come to pass already, so only speak of things that are being worked on or looking to the future. You can quickly name at least 3 different projects, bringing north of 1 million barrels a day of egress to diverse locations, all potentially in service by the end of this decade. And that's a big change from 2024 right when Trans Mountain came on, and there was maybe a large feeling that this might be the last I think industry has proven creative and responsive to need. And as we said last quarter, don't be surprised to see Cenovus continue to support these initiatives.

Next question is from Travis Wood from NBC National Bank.

Question is kind of back to what Menno was talking about in terms of market capture. But rather than the market capture, would you guys be able to share some thoughts around how you're able to capture some of the physical flow disconnects and global pricing, whether that's shifting how you're moving the crude itself or maybe shifting and optimizing the refined product sales into other markets and on the refined product side. I'm kind of thinking more jet fuel or diesel opportunities that you see kind of as an ad hoc basis through the marketing and trading team as well.

Yes. So Travis, we're kind of doing this in 2 places. I mean one of the places that we have opportunity is on the crude side. and particularly on the East Coast of Canada, where we're seeing the physical and financial markets disconnect. I'll let Jeff talk a little bit about that, and then Eric can kind of fill you in on how we're thinking about the product market and our ability to capture premiums there?

Great. So Travis, just in terms of crude side, we all watch and have seen benchmarks do what they do and move around. But when you get into the physical market, there's a lot of things that are less seen. I would say off the East Coast, we've managed to find some attractive pricing both dated Brent versus Brent, when you get into the more physical nature of things dated Brent sets that price. And you can look for lots of headlines on it, but those prices have been anywhere from $20 to $40 plus greater than Brent. So pretty significant. In addition, as you look to grade and location differentials across all of like crude, we've seen opportunity to sell at increased differentials of things would normally be $1 a premium moving to $6, $7 and $8 premium . So we continue to extract that. And then we have a number of assets on the pipeline side that allow us to move crude around and there's opportunities to move between grades to gather incremental value. It really has shown up really significantly in the physical market. which is less observable than the benchmark. So we just continue to optimize in that range. And I think Eric will go on the refined product side.

Yes. Yes. And maybe just a little more on the feedstock side, building on Jeff's point. I think you've been able to see some really good optimization as we look at standing up the network. So whether that's understanding how do we really find the optimization opportunities from the upgrader, how do we actually optimize across our entire network with Superior and Toledo and down into Lima number of opportunities we see and have been able to capture. I think I would also point to being able to optimize and bus through some constraints inside the refinery to maximize our heavy crude and actually maximize the high 10 portion of the heavy crude, which becomes quite advantage for us.

So a lot of good work even on the feedstock side. optimizing within the network. I think turning to the product side, continuing to find ways, again, as a network to really optimize across the portfolio. I'd point to, as I've spoken before around the marine facility at Toledo and using that to find new means of egress continue to work to figure out how do we monetize our octane length and find different outlets for octane products as opposed to just finished products. I think it's been a huge opportunity, really optimizing within our jet and diesel make and making sure the right molecules are going to the right places to get the most advantaged products into the market.

And so our jet make is something that I think was really strong as we looked ahead, we optimized the kit in the first quarter, and as I spoke to some of the market capture performance, that spoke to seeing the opportunity in the market and then within the physical refinery being able to do that. So I think a lot of different moving pieces that all add up to strong performance in the quarter.

Okay. No, that makes sense. And I know, Jon, you've kind of been continuing to talk about 70% market capture. But if the team continues to optimize both organic feedstock for the refiners optimize global sales from the upstream side and then capture much more robust product pricing downstream. Is there a scenario where you could -- you think you could continue to outperform that 70% given the initiatives the team seems to be working on?

There's always a scenario where you capture more than 70%, and there's always a scenario where you capture less. And to the point you're making, Travis, we recognize that this is somewhat of a clumsy marker in terms of trying to gauge performance. And what we've committed to do is come to you at our Investor Day in January and provide a lot more fidelity into how this works. But I don't want to front run that -- and I don't want to get out over my skis in terms of promising something well above 70%.

But suffice it to say, we're really pleased. We're really happy really proud of the work that Eric and the downstream have done to achieve the kind of market capture rates that we've got, and we look forward for more to come. We're obviously not finished but we owe you a better explanation going forward as to how you can gauge and forecast a refining business and that's to come.

Okay. We'll wait for January and keep asking you on the quarterly call. So I appreciate the color.

I'd be disappointed if you didn't, Travis.

Next question is from Manav Gupta from UBS.

A quick question. Your weighted average tax spread for the first quarter net of RINs was almost down $5 versus the last quarter. I know it's been only probably half a quarter, but can you give us some idea where this number is trending quarter-to-date? I would assume it's materially higher, but if you could give us some idea where that number is trending quarter-to-date for you guys.

Yes, this is Eric. I don't have the specific number, but I can certainly speak to a few things. I think as we saw in the first quarter, January and February were pretty lean. That's expected that is pretty typical in PADD II particularly, where you just have some really tough margin environment. We saw the strength start to return in March and operated into that environment where there's a supply disruption and working to place our products into that market. We've continued to see that strength into the second quarter here. There's a couple of things I think about. Obviously, we've got quite a bit going on in the world. But I think we look at the supply-demand balance really being pretty tight. I think you've seen a number of folks move inventory into the market. So inventories at relatively low positions.

There's been seasonal maintenance going on as well as some unplanned maintenance throughout the pad. And so that makes a tight supply-demand balance even tighter and that really starts to strengthen the cracks. And so we've seen some really, really strong cracks and continue to put our good operations to work to make sure we're putting our products into that market. But the supply-demand balance that we see, I think, continues to show some strong cracks here in the second quarter.

Perfect. And my quick follow-up here is international crude prices are high. International gas prices are super high. Can you talk a little bit about how your international gas assets could be kicking some tailwind maybe for a couple of quarters from what's going on? If you could talk about your international gas asset exposure over there.

Yes. And remember, Manav, that our international gas assets are really on a fixed price basis. So those are low volatility cash flows that we get out of Asia, China and Indonesia. So they don't necessarily see the exposure to the international gas price, but what tends to happen when LNG prices go up is the demand for our gas goes up as well. It's the first gas into Guangdong when LNG prices elevate the way that they have. Now where we do see some benefit is on the associated liquids, those trade at a Brent plus basis. And we do capture additional margin on that. But 1 thing I say about our Asian gas business, and we love that business because of its low volatility and certainty that everybody kind of loves it when the international prices of gas are low and then they always wonder why we're not getting a bigger margin when international gas prices are high, but it's been a fantastic business for us. but we don't necessarily participate in LNG prices as they go up and down.

[Operator Instructions] Next question is from Patrick O'Rourke from ATB Cormark Capital Markets.

Congratulations on another strong operational performance here, especially in the upstream. Hopefully, this isn't redundant because you've covered a lot of ground so far. But just taking a look at the downstream here and heavy throughput in the U.S. segment was up in the quarter. Still, if you were to look at nameplate a little bit of potential upside to that. Was the driver of that, as you spoke to network optimization? Or was this being driven by the heavy crude differential there? And what sort of impact does this have on your market capture going forward?

So I'm going to let Eric answer this question, but there's a couple of things that are bubbling beneath the surf. As Eric mentioned, the cracks were relatively low in January and February, and we obviously optimize our throughput based on commercial considerations. And then on the asphalt side, asphalt prices haven't necessarily kept pace with feedstock and so we've adjusted there.

So when you kind of look at that utilization rate, you've also got to think through all the commercial considerations that go in and around that. It's not entirely a mechanical reliability story. But Eric, maybe you can provide some color.

Yes, I think you hit it really well. Yes. Look, we're built and configured to run the heavy crude, and that's what we do. I think, as Jon alluded to, though, when we looked at the market environment and then certainly as the market started to strengthen, the asphalt prices did not follow the crude prices. And so there are some choices we needed to make around how do we position the kit economically in that environment. And so I think in terms of overall reliability, really, really strong quarter. But looking at market factors and understanding again some of that secondary pricing I talked to earlier, how is that pricing in relative to the price of crude? And then how does that show how you optimize your network.

That said, I will highlight a number of things we've been able to do to unlock heavy crude capacity. A lot of that comes down to reliability of our coking units. A lot of really good work to get after the reliability there, get cycle times down, get throughput up and that really does enable the ability to process more heavy crude, essentially the same total throughput, which is a big advantage for us, again, optimizing within just constraints in the refinery. And just having a mindset to how do we continue to safely and reliably push our constraints to unlock incremental value.

And I think really seeing some of the the talent of the team come through and the ability to unlock those constraints and continue to push the business forward, I think is pretty exciting.

Okay. Great. And this may be a bit more of a broader philosophical question, but I really appreciate the advocacy for the industry that are to start the call. I'm wondering, you've gone through a substantial growth phase here. Growth is in a sense, tailing off a little bit. What would the sort of specific market conditions and regulatory parameters be that enormous opportunity set within the portfolio where we would see Cenovus start to think about upticking the growth profile again here where it makes sense?

Yes. And thanks for the question, Patrick. And you're quite right. We have seen some modest growth in the industry, and you've seen some growth of Cenovus over the past number of years. But the way I would describe that growth is a lot of it comes from acquisition and mergers, and a lot of it comes from brownfield and debottlenecking projects. I think the issue that we have to wrestle with is if we do want material growth in the provinces has suggested that it's looking to actually double production, we have to have a competitive market that allows for greenfield development and greenfield development comes at a higher cost and a higher breakeven than the growth that you've seen to date.

So things like what we've done at Narrows Lake or what we've done at Foster Creek, I would just describe those as optimizations versus fundamental greenfield growth. So without providing for a competitive set of policies that attract capital into this basin and allow us to meet those hurdle rates. I think we're at a point where we have to be pretty thoughtful about a set of policy environments that really do allow us to grow and fill a pipeline that's desirous of moving another 1 million barrels a day to the West Coast.

There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thank you, operator. Obviously, this concludes our conference call. And I'd like to thank everybody for joining. We certainly appreciate your interest in the company and wish you all a great day. Thank you.

This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great day.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's Fourth Quarter and Full Year 2025 Results Conference Call.

[Operator Instructions] As a reminder, this call is being recorded.

I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2025 Year-End and Fourth Quarter Results Conference Call. On the call this morning, our CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. Then we'll open the line for Jon, Kam, and other members of the Cenovus management team to take your questions.

Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available in Cenovus' annual MD&A and our most recent AIF and Form 40-F. And as a reminder, all figures we reference on the call today will be in Canadian dollars, unless otherwise noted. You can view our results at cenovus.com.

For the question-and-answer portion of the call, please keep to one question with a maximum of one follow-up. You're welcome to rejoin the queue for any other follow-up questions you may have. We also ask that you hold off on any detailed modeling questions. You can follow up on these directly with our Investor Relations team after the call.

I will now turn the call over to Jon. Jon, please go ahead.

Great. And thank you, Patrick, and good morning, everyone. I want to begin by recognizing our safety performance. Safety remains the cornerstone of everything we do at this company and every decision we make. At our Sunrise Oil Sands asset, our teams have now gone through 2 full calendar years and more than 1.8 million hours worked without a reportable incident. Now this is particularly notable because 2025 represented the highest activity level at Sunrise in the past 6 years with close to 950,000 hours worked as they completed 2 turnarounds and advanced the asset's growth program. This outcome reflects our deep commitment to safety even during periods of elevated activity. Personal safety for each of our employees and contractors remains a critical priority, which must underpin everything we do. We are working to build on our strong performance and continuously improve to ensure that our people come home safely each and every day.

So now to our results. 2025 was a very important year for Cenovus in which we executed a long list of priorities across the company. Our performance in 2025 is a testament to the great people and assets we have at Cenovus. When I look at all the things that we accomplished this year, I couldn't be more impressed by the way our people met the challenges we faced. We had a very ambitious agenda, and we collectively delivered against it. Operationally, our teams delivered exceptional performance, including setting multiple upstream production records across our assets and executing consecutive quarters of top quartile downstream reliability and profitability. Our upstream production of 834,000 BOE per day in 2025 was the highest ever for Cenovus and up 3% from 2024, excluding the impact of the MEG Energy acquisition. We also reduced total upstream nonfuel operating costs by approximately 4% from the year before.

In the Downstream, our refineries ran well through the year with a combined utilization rate of 95% across the Canadian and U.S. segments. This included the impact of a major 59-day turnaround at Toledo, which was completed 11 days ahead of schedule. Now at the same time, we lowered costs, delivering a reduction in operating costs of around $4 per barrel in the Canadian Refining segment and $2 per barrel in our U.S. operated refineries. We recognize there's more work to do as we continue to drive down costs and leverage our commercial capabilities to enhance our market capture.

We also achieved major milestones across our growth projects in 2025. This included completing the Narrows Lake tieback to Christina Lake, a first of its kind extended steam reach pipeline. Completing the facilities work on the Foster Creek optimization project, which delivered production growth well ahead of schedule and completing the construction and installation of the tie-ins on the West White Rose platform. These projects reflect an enormous amount of effort, determination, and ingenuity from all parts of our organization that I couldn't be -- and I couldn't be more proud of what we've delivered.

Now 2025 also saw us complete 2 significant transactions. Starting with MEG Energy. We have long recognized the quality of the resource and the synergy opportunity available if we consolidated the Christina Lake area. When MEG became available, we responded accordingly. The acquisition was successfully closed on November 13, adding over 100,000 barrels a day of top-tier resource located directly within our largest producing SAGD asset. The addition of MEG's assets and people have strengthened our industry-leading heavy oil portfolio and solidified our position as the preeminent heavy oil producer, not just in the Western Canadian Sedimentary Basin but globally.

We also sold our interest in the WRB refining joint venture at the end of the third quarter. As a result, we now have full operational, commercial, and strategic control of our Downstream business, which remains critical -- which remains a critical component to our heavy oil value chain. Together, these transactions position the company for continued material value growth over the long term.

So now turning to our fourth quarter results. Upstream production in the fourth quarter was 918,000 BOE per day, headlined by oil sands production of 727,000 BOE per day, both records for the company. Including the full benefit of the MEG acquisition, which closed in mid-November, we exited the year with production over 970,000 BOE per day in December, including nearly 786,000 BOE per day from the oil sands. We are encouraged by the recent performance and expect our operating momentum to continue into 2026 and beyond.

At Christina Lake, production averaged 309,000 barrels a day in the fourth quarter. That includes roughly 6 weeks of production from the newly acquired Christina Lake North asset, which achieved its highest ever production rates of over 110,000 barrels a day in the quarter. The combined Christina Lake is the largest and highest quality thermal asset in the industry with a reserve life measured in decades. The integrations of systems and people is largely complete, and we have delivered a majority of the expected corporate synergies already. Work is now progressing at pace to capture operational synergies.

We have begun a delineation and seismic program at the Christina Lake North asset, which will allow us to optimize our go-forward development plans for this resource. Our technical groups have begun leveraging our scale and operating practices to deliver near-term production and cost savings. We have also begun drilling a 42-well redevelopment program, which will support additional production volumes in 2026 and 2027. We are very comfortable in our ability to deliver the $150 million of annual synergies in 2026 and '27, and over $400 million of annual synergies by the end of 2028. We are delineating additional synergy opportunities as we fully integrate our future development plans for the broader Christina Lake region.

Now at Foster Creek, we achieved a production record of 220,000 barrels per day in the quarter, reflecting the impact of the Foster Creek optimization project. Incremental steam capacity of approximately 80,000 barrels a day was brought online in mid-2025. And in the fourth quarter, the water treatment and deoiling facilities were commissioned and put into service. With these milestones behind us and production largely ramped up, we have successfully delivered around 30,000 barrels a day of growth at Foster Creek well ahead of schedule.

Looking forward, new well pads associated with the optimization project will be brought online at Foster Creek this year, which will support increased production levels or support the increased production levels we have seen. We also continue to progress our enhanced sulfur recovery project that will reduce operating costs by about $0.50 to $0.75 per barrel when it comes online midyear.

At Sunrise, following the turnarounds executed in Q2 and Q3, production rose to over 60,000 barrels a day in the fourth quarter. The first of the new well pads from the East development area, incorporating Cenovus well pad design for the first time at Sunrise is currently steaming and expected to start up in early 2026. We will bring on a total of 3 well pads in this high-quality reservoir in 2026 and at least one more in 2027. This development will deliver the next phase of growth as we progress our plans to increase production to over 70,000 barrels a day by 2028. Now with the work we completed earlier this year, we have also extended the turnaround cycle from 4 to 5 years at Sunrise. That means there is no major cycle ending turnarounds at Sunrise until 2030, providing an extended runway while we grow volumes and optimize the asset.

The Lloydminster thermals had an exceptional fourth quarter, partly as a result of the highly successful redevelopment well program that significantly exceeded our expectations. In tandem with strong base well optimization, production averaged over 107,000 barrels per day in the quarter, more than 10,000 barrels higher than the previous quarter. This includes the impact of the sale of Vawn at the beginning of December. And building off the success we had in 2025, we'll be deploying an even larger redevelopment program in Lloydminster in 2026.

Now turning to the Atlantic. At West White Rose, we're currently conducting systems integration testing, and we're in the final phase of commissioning. Our teams have done a fantastic job of safely progressing the scope in spite of particularly challenging weather in the North Atlantic. We've seen an abnormally severe winter storm season with waves as high as 17 meters and winds up to 170 kilometers per hour. Through this, our people have continued to make steady progress. We have completed the welding and coating of the platform legs and the main power generators are fully commissioned. We also opened the living quarters on the top side prior to year-end, transitioning staff from using a flotel vessel to fully manning the platform. Now we've guided you to expect first oil in the second quarter. With the weather disruptions we've seen, that timeline will be tight but our people are determined and do incredible work as we push this forward at pace.

Also in the offshore, in conjunction with our partners in Asia, we successfully extended the gas sales agreements in China for both Liwan 34-2 and Liwan 29-1 subsequent to the quarter. The extensions will enable sales through the end of the field's production periods in 2034 and '40, respectively. This increases sales volumes within our 5-year plan and add nearly $2 billion of incremental free cash flow to these assets over the life of the fields.

Now moving to the Downstream. Fourth quarter results underpin the profitability and competitiveness of our assets in a relatively weak crack environment. In the quarter, the Canadian Refining business ran at its highest rates of production through the year with crude throughput of 113,000 barrels per day or utilization rate of about 105%. in U.S. Refining, our results in the fourth quarter reflect not only our operated -- sorry, reflect only our operated assets as our interest in the WRB refining was divested effective September 30. Our U.S. refining business delivered crude throughput of 353,000 barrels per day or approximately 97% utilization.

While the market crack spreads in Chicago area deteriorated significantly in early December, which is typical for this time of year, we're able to capture a larger share of the margin available. Excluding the receipt of onetime pipeline settlement, our adjusted market capture was around 95% in the quarter. This reflects both seasonal product mix impacts related to our configuration as well as our ability to capitalize on commercial opportunities we saw in the market during the quarter.

Now I'm going to pause for a minute, and I will turn this over to Kam to walk through our financial results.

Thanks, Jon. Good morning, everyone. In the fourth quarter, we generated approximately $2.8 billion of operating margin and $2.7 billion of adjusted funds flow. Operating margin in the Upstream was over $2.6 billion, in line with the prior quarter with record production in the oil sands more than offsetting declining benchmark oil prices. Oil sands nonfuel operating costs decreased to $8.39 a barrel in the fourth quarter, over $1.25 lower than the prior quarter due to higher production volumes and reduced maintenance activity.

As Jon mentioned, our Downstream business continued to demonstrate strong performance in the quarter. Downstream operating margin was $149 million despite deteriorating regional crack spreads in the U.S. towards the end of the year. This included $138 million of inventory holding losses and $15 million of turnaround expenses, partially offset by a onetime pipeline settlement receipt. Excluding these impacts, downstream operating margin would have been approximately $235 million in the quarter.

In the U.S. Refining, operating costs, excluding turnaround expenses, were $11.57 a barrel, reflecting higher fuel and electricity prices, planned maintenance activity and modestly lower throughput quarter-over-quarter. The fourth quarter environment was particularly favorable to our configuration with heavy crude differentials widening, diesel and jet fuel advantage relative to gasoline and lower benchmark crude prices benefiting asphalt and other product margins. Our marketing teams were able to capitalize on market opportunities in the quarter, while at our Lima and Toledo refineries, we continue to leverage and enhance the interconnectivity of the sites. On a sustained basis, we continue to guide to adjusted market capture of around 70% at a $14 WCS heavy oil differential with opportunities to improve this over time.

Capital investment in the fourth quarter was nearly $1.4 billion, resulting in full year capital spending of $4.9 billion. This spend supported sustaining activity across the business, along with investment in growth and optimization, including capital directed to our 3 of our major capital projects at Narrows Lake, Foster Creek and West White Rose. As we look forward, growth spend in 2026 -- in the 2026 plan is approximately $300 million lower at the midpoint year-over-year. This growth spend includes commencing the drilling at West White Rose, advancing the Christina North expansion project, which will support growth at Christina Lake to around 400,000 barrels a day.

Net debt was approximately $8.3 billion at the end of the fourth quarter, an increase of approximately $3 billion due to the MEG transaction, partly offset by the receipt of $1.9 billion of cash proceeds from the sale of WRB. Shareholder returns in the fourth quarter were $1.1 billion, including $714 million through share buybacks and $380 million through dividends. After closing the MEG transaction, we've adjusted our framework to balance deleveraging and shareholder returns while we move towards our long-term net debt target of $4 billion. When net debt reaches $6 billion, we will aim to increase shareholder returns to around 75% of excess free funds flow.

Also in the fourth quarter, we recognized a current tax recovery of $189 million, primarily driven by the integration of MEG's business with Cenovus. Full year 2025 current taxes were approximately $780 million, well below our original guidance of $1.2 billion to $1.3 billion. Our cash tax guidance for 2026 remains unchanged at $1 billion to $1.3 billion at around a USD 60 WTI price. With the strong operational performance, meaningful progress towards capturing MEG synergies and a robust balance sheet, we are well positioned to continue to deliver value from our opportunity-rich portfolio.

I'll now turn it back to Jon with some closing remarks.

Great. And thank you, Kam. 2025 was a great year for this company by any measure and a testament to the dedication and determination of the people that we have in this organization, including those who most recently joined us from MEG. Our disciplined execution and focus on operational excellence enabled us to deliver significant milestones across the major projects this year while setting numerous production records at all our oil sands assets.

In our Downstream business, we've continued to demonstrate the potential of the assets as evidenced by consecutive quarters of top-tier reliability and meaningful cash flow contribution. Completing the strategic acquisition of MEG has materially extended our industry-leading low-cost, long-life resource base. Through the integration of our highly complementary assets and the focus on the ingenuity of our combined teams, we expect to create significant value from this business for years and decades to come. Anchored by our strong financial framework and balance sheet, and the many opportunities ahead of us, Cenovus is more resilient, competitive and durable than ever before.

And with that, we're happy to answer any questions you might have.

[Operator Instructions] Our first question will come from the line of Dennis Fong from CIBC World Markets.

First and foremost, congrats on a really strong quarter and year. My first one here focuses really on the MEG assets that you've now taken over. I was hoping to find out what some of the next steps happen to be in terms of obviously turning the asset over to your teams? And then how are you looking at applying, we'll call it, Cenovus' best practices and technical understanding on the asset to really drive stronger performance and realize the synergies that you outlined or more with the initial presentation.

Sure. So maybe I'll take a crack at it, and then I'll turn it over to Andrew Dahlin to give you some of the details on the production side. But I think we've had this asset now for, I guess, it's about 3 months now. And I'd say that particularly during the first 6 weeks since we acquired this, we moved really, really quickly on getting after all the corporate synergies that we had outlined in our investment case. So everything from the HR synergies through the commercial synergies, the finance synergies, getting the amalgamation done to realize some of the tax synergies. That was all done before year-end. And so we kind of look at that run rate of [ $150 million ], and we're very, very comfortable that the [ $120 million ] that is sort of the corporate component of that is very realizable and has largely been captured now.

So as we kind of move into 2026, we're really focused on the operations proper. We have started a lot of work on delineating the reservoir in advance of doing our redevelopment program, which will kick off next month and really looking at the well pad development and seeing where we can insert ourselves to impose some of our operating practices and well design on that. And Andrew will give you a bit more detail. But we haven't lost sight, Dennis, of the bigger picture and the view of how do we bring more synergy forward and how do we go beyond the $400 million that we had articulated in the business case. And we're comfortable there's a lot more there, and that's what we're working on now.

But Andrew, maybe you can talk a little bit about some of the things you're doing in the field to get additional production synergy out of those operations. That's right.

Yes, it's Andrew Dahlin speaking. Yes, maybe just focusing on production itself. So the first thing we're going after here in the first half of this year is the start of the redevelopment campaign. So the plan is to drill 40 redevelopment wells that ultimately get after heated bitumen zone that sits below our current production wells. We will get production from our first redevs here in Q2 of this year. And I think as Jon has spoken to, that would benefit and see a production uplift both here in 2026 and into 2027. So that's the kind of the first production lever we're pulling. Second one would be our development methodology. So those of you that came to our teach-in, you'll know that our focus or our sort of way of developing it is the field is with wider well spacing and longer wells. So we are moving to implement that already here latter part of 2026. We'll be steaming the first pad in 2027 and seeing a production ramp-up and actually much lower development costs starting in '26 into '27.

And then the team is working really hard on facility debottlenecking and expansion. So there's a debottlenecking program, actually 3 MOCs taking place right as we speak to be able to push more volume through the plant. And then, of course, we have a facility expansion project that will see the facility expanded and production taken to an excess of 150,000 barrels a day by 2027, 2028. So that was kind of the immediate production focus. And then on top of that, of course, if I look further out, we have things like boundary land, so the boundary land that existed between ourselves and MEG. As Jon alluded to, we're delineating that opportunity and then putting that into an optimized long-term development plan for the asset. So I'll stop there.

If I were to sum it up, Dennis, I'd say there's really no surprises in what we put out as our investment case on this. And I think we'll be bringing forward additional upside as we go through the coming quarters and months.

Fantastic. No, I really appreciate that -- the depth of that context there, both Jon and Andrew. Shifting my focus towards Lloyd for my second question. In your slide deck, you showcased development, both from the thermal as well as the, we'll call it, conventional assets towards over 145,000 barrels a day over the next couple of years. But I did draw a little bit of notice to the use of solvent enhanced oil recovery techniques. Can you elaborate a little bit more on that opportunity and what that could mean for the field?

Yes. So we've got a solvent project going on at what we call Spruce Lake North, which we think is an ideal reservoir for the application of solvent. And I think you know that we've been kind of leaders in this and kind of developing that technology. So it's not a, I'd say, a step change from our strategy but it is something that we think is an opportunity for us, and this is kind of an ideal place to do this.

I think, Andrew, maybe you can talk a little bit about the development of that and when we can expect to see that project come online.

Yes. No, happy to. So indeed, Spruce Lake project, we've taken FID on the project. Its spend is in the order of $250 million. We'll spend that here in 2026 and through into 2027 when the project will come on stream, I know. Essentially, what we do is we inject condensate along with the steam but less steam. And what it does is it lowers our SOR, it drives higher production and it drives higher ultimate recovery. So we see an immediate benefit to Spruce Lake. And frankly, we see the future application of this in the rest of our oil sands assets. and potentially also in some of our lower quality reservoirs. So we very much have a view of how could we deploy this technology into the next 2 to 3 decades. So that's where we are on that.

Our next question will come from the line of Menno Hoshoff from TD Cowen.

I'll start with maybe just on the Downstream side of things. One big thing that jumped out for a lot of people in the quarter was the big uptick on a quarter-on-quarter basis for U.S. market capture. Yes, just a big increase. And you did touch on this to some degree in your opening remarks, but can you just elaborate on what drove that because nobody was even close to that in their models, I don't think. And maybe your expectation for market capture through the middle of the year, especially given limited planned turnaround activity.

Well, I'll tell you what I'm going to turn it over to Eric to give you a view on that. Eric rarely smiles but he is smiling this morning. So I think we're really pleased and happy with the work that he and his team have done. But Eric, why don't you talk a little bit about how you got the market capture you did?

Yes. Thanks, Jon, and thanks, Menno, for the question. Yes, really pleased with the performance. I would say it's a combination of a number of things. I think certainly, fundamentally, just having the reliability in place that gives you the ability to capture the market when it presents itself. And so what we saw in the fourth quarter was some market opportunities where there were some supply disruptions in the region and our reliability allowed us to capture that. I think you put on top of that some of the real commercial optimization work that we've been doing between finding the synergies between Lima and Toledo, using dock access to find new markets for our products, just really helped underpin the improvement that we've been driving, and you got to see that in the fourth quarter.

The other nuance to market capture that I would highlight is there is seasonality to it. So what happens in the fourth quarter when you see the gasoline cracks start to fall off as you expect in PADD 2, there is some benefit to our portfolio where we have some GDD flexibility. It also helps relative to some of the other secondary products that we make, so asphalt and some of those products are able to kind of price better relative to the crack, which shows a higher market capture. What I would say going forward is we'll continue to guide to that 70%, but we do see seasonality in it but I would continue to steer towards that 70% at the $14 dip that we've talked about.

So we are starting to see a bit of an impact from the PADD 2 egress initiatives, that you've talked about in the past?

Yes, absolutely. We've seen some real good improvements around our ability to utilize the Toledo dock. We set an annual record in the volumes we've been able to move. And that just really helps us find new markets and be able to really get after some better opportunities for us, and we'll continue to explore all sorts of options to continue to take advantage of that.

Okay. That's helpful. And I'm going to assume that's part of the first question, cutting off if it's not. But just on West White Rose, really good to see that the Q2 timeline is still intact. But can you just give us an update on the status of drilling? And what should we be modeling for an exit rate for 2026 if everything goes according to plan?

Yes. No, you're quite right, Menno, we're still guiding to Q2. I did mention in my notes that it's tight. So we had hoped to be drilling by this time. We are in the final stages right now of commissioning, and that will make the time frame, again, tight for the end of Q2.

But Andrew, maybe you can talk a little bit about exactly where you are and how you're seeing production through the end of the year.

Menno, it's Andrew speaking. Yes, indeed, maybe I'll just sort of make sure that we all sort of level on where we are in terms of status of the project. So major construction is complete. The platform is commissioned and inhabitable. All the subsurface work connecting the platform to the SeaRose is completed. And as Jon talked about, we're in the final throes of commissioning and sit testing. So that's where we are today, and then we move into drilling.

I think in terms of how do I look at it from a production and the CapEx for the year, we absolutely to guidance, both for production. Our production guidance was 20,000 to 25,000 barrels a day and actually don't have CapEx handy but we're also within that CapEx guidance. And so what you'll naturally see is as the first and the second well come on stream, you'll see a -- sorry, I'll start again. You'll have a base production from SeaRose and from Terra Nova, and that will continue through the year. I tell you that we're seeing good uptime and availability on production from both of those facilities here in Q1. And then obviously, in the second half of the year, you'll get a production ramp-up as each new well comes on.

So the final push is on, Menno, and we've increased the number of people on the platform, and we look to be drilling very, very shortly.

Our next question will come from the line of Neil Mehta from Goldman Sachs.

And Jon, you addressed this in a couple of different ways, but maybe you can dig a little deeper, which is you're getting to be a 1 million barrel a day producer, and you've got a lot of growth here coming in the next couple of years. I think there's a lot more questions about egress coming out of Canada and apportionment is a factor and you have a little bit less WRB as a hedge. And so just maybe you can address this concern head on. Is Cenovus a lot more exposed to potential volatility in WCS? Or do you feel confident about your ability to navigate that potential risk?

Yes. No, it's something we obviously think about Menno or Menno -- Neil. Since I came to this company, the 2 things that we obviously highlighted were egress and having a strong balance sheet. And when you kind of think about this company growing from a standing start to 1 million barrels a day over 20 years, those 2 things have really been front and center for us.

So Geoff Murray , who's our EVP of Commercial, he deals with this every day. But Geoff, maybe talk about some of the egress options that we have and where we sit as a company in terms of our balances.

No, it sounds great, Jon. Neil, great question. If we wind the clock way back when to 2018, we sold 80% of what we made in Alberta. Where we stand now is maybe 40% of the crude oil we make is sold in Alberta and exposed to that diff. So we've moved a very long way, as you point also the growth on that front. So that's a really big shift over the past 7, 8 years. Probably more importantly is looking forward in the near term. We've been saying for a while, Trans Mountain is here. It's working. It's performing as expected, and you will see that through the stability of the Alberta diff as compared to global points, and that's proven to be true.

We've also said we're not going to rest on our laurels. And we and the industry at large haven't. I think we've disclosed entering into opportunities for 150,000 barrels a day of export over the next 2 years under contract. And even more importantly than that, I would say Cenovus has been pressing hard across the industry for what's next, although the diff is in the right place and stable, we know that we need to take action to continue that. And I think you can probably scour the market and find a number of publicly discussed projects, and we're really quite supportive of all of them, both in philosophy but also through contracting mechanisms, and we'll continue to do that.

Yes. I'd say just adding to that, Neil, I would say that we probably see more proposed projects today than I've seen in the last 10 years. and more projects that are doable in a shorter time frame than we've had in a long period of time. So as Geoff mentioned, heavy oil egress is a really important part of our strategy, and we are actively evaluating and looking at all of those options that are available to us. And you shouldn't be surprised if we take action on some of those.

And the follow-up is around return of capital versus growth. We're probably in a firmer commodity price environment, Jon, than you and I would have thought a couple of months ago. Certainly, geopolitics is part of that. But if we are -- if we do go into a period of time where we're above, let's say, a mid-cycle price that you outlined, does that dollar go back to deleveraging/return of capital? Or could you accelerate the growth lever? How do you think about that?

We really don't think about the commodity price of the day, Neil. We are kind of more value orientated in terms of how we allocate capital over the long term. And I think we've been pretty clear that in the short term, until we get down to $6 billion of net debt, 50% of the free cash flow is going to be used for deleveraging, and then we'll return 50% to the shareholders in the form of buybacks.

But Kam, maybe you have some more thoughts on that.

Yes, Neil, I would just add, I think when you look at our philosophy around just capital allocation, the growth projects we've got in the portfolio, and I mentioned this in my remarks, our growth spend actually has come down year-over-year when you look at the projects we've got. We've obviously finished or close to being done things like Narrows, the Foster optimization, West White Rose. We obviously added the FEP expansion. But when you look at the portfolio as a whole, our growth spend is down year-over-year. So -- and one of the things we do try to do is we try to ensure that capital spend doesn't really change with commodity prices to Jon's point, in that we can fully fund that growth plan with our dividend and probably in a low $50 world. And so don't expect us to make any sort of knee-jerk reactions to capital spending if commodity prices flex down $5 to $10. And similarly, you're not going to see us move it in the other direction if oil prices go up.

When you look at the priorities we have today in terms of our excess free cash flow, I don't think anything has changed. Neil, we -- obviously, our philosophy has been that we're going to continue to be balanced on deleveraging and share repurchases with our excess cash, and that's something we'll continue to do. I think I would say that obviously, the share price has continued to perform very well but we're nowhere near a price level that I would suggest is a level where we would move away from things like buybacks. We've made a lot of improvements to the business, both on costs, on growth and free cash flow improvements. And our business continues to get more and more resilient. And I think that affords us the opportunity to continue to buy back stock.

Our next question will come from the line of Travis Wood from NBCCM.

I wanted to -- Menno kind of stole my question there but I wanted to dig into that a little bit more because I think it's quite interesting in terms of the rate of change. So could you talk about some of those anomalies that you saw through Q4 in order to capture that adjusted 95%? And does the marketing and trading team have that ability to capture those go forward? And I guess, in the same breath, how much does other refinery downtime have to do with that market capture? So if we see in the future, Whiting go down again, can we ramp up that market capture in those one-off quarters with other refineries going into turnaround?

Yes. Again, great question, Travis. I appreciate the question. Yes, I think maybe just working backwards, I think certainly, with the reliability improvements we've been able to deliver in our portfolio, it positions us to be able to capture market opportunities when they present itself. And so any time there's a disruption in the market, that reliability lets you take advantage of it. And that's what we saw in the fourth quarter. And so you saw some strength in the crack really into early December before it started to fall off as you would expect it to in the winter season. And so I fully expect that is something we will continue to stay laser-focused on that when the market presents opportunities for us, we want to be able to take advantage of that. So that is absolutely core to what we want to be able to do.

In terms of the market, I think every refinery and every downstream has its own unique configuration. And I think when the market fundamentals favor that configuration, you see the opportunity to have a higher market capture. So for us, where we have a high -- heavy differential -- sorry, where we have a higher heavy crude consumption where we see that heavy diff, that favors our portfolio. Where you see the gas crack come off, we have some diesel -- some distillate length, some diesel and jet length, we're able to take advantage of that by optimizing our cut points inside the refinery and really maximizing that distillate production. Superior has significant asphalt production, right? When you see the asphalt market have some strength and carry that forward, that favors that portfolio.

And so that really is that seasonality I spoke to earlier that depending on what the market is favoring and how it's priced in, that can favor or that can work against you. And what we saw in the fourth quarter was really the opportunity, both from the market opportunities with some of the disruptions as well as our configuration fitting better into what the crack available was for us.

Okay. That's fantastic color. Switching gears for my second, just in terms of Liwan contracting on the gas sales, does that include any kind of contracted pricing as well? Is there any material change to the pricing as we look out through '26 and beyond?

Yes. No, that's a good question, Travis. So what we've done on 34- it's taken the last couple of years to really work on delineating those reservoirs. And what we're finding is those reservoirs are getting bigger than what we had originally booked for reserves, not smaller. And that's given us the opportunity to increase the gas sales right to the end of life of the PSCs. And that's a big deal for us. And so the gas contracts themselves are roughly the same as what they are today, although slightly higher as well. So we're very pleased with the pricing, very pleased with the volumes. And as I mentioned in my notes, it gives us about $2 billion of incremental free cash flow over the life of those fields. So it's a very significant piece of work and something that the team there has been working on for the last couple of years. So it's good to see it come to fruition at year-end.

Our next question will come from the line of Chris Hebert from RBC Capital Markets.

Jon, it's Greg. So I think we may have got our wires crossed on our end.

Apologize. You came up because Chris Hebert [ we're wondering ] really well.

I did indeed. And yes, so listen, a couple of things. I want to come back to Neil's question. So you finished the 3-year plan, the 3-year growth plan and so forth. Is there another growth plan, albeit perhaps more modest than the offering right now? And then kind of related to that, I wanted to go back to what Kam was talking about in terms of not really throttling your spending too much. But like how generally should we -- I hate to ask it this way but how should we think about sort of your capital spend maybe over the next 2, 3 years? And that obviously ties into the degree of balance sheet deleveraging, other things being equal.

Yes. So what I would say, Greg, is one of the things we don't want to get into is big major projects again. So West White Rose is the last of the big major projects. But we have fairly low sustaining capital in and around sort of the 3.6, 3.7 level. And so we have plenty of capital available to us at growth projects that chin the bar at $45. But the growth that you're going to see from us over the next couple of years outside of the work that we've already delineated at the Mega asset is really around brownfield development, debottlenecking and those kind of things. So we mentioned the [indiscernible] SAGD project that we've got going on at Spruce Lake, which is kind of another example of something that kind of adds 5,000 to 10,000 barrels a day, but isn't -- probably doesn't chin the bar in terms of major project status. But you're going to continue to see those kind of things.

So where we have opportunities to add production for $45 or sort of add production that has a return of and return on capital of $45, and we can kind of do in $10,000, $15,000, $20,000 a flowing barrel range, you're going to continue to see those things come out of us. And so I would kind of -- if I were you, I would kind of model us being close to that $5 billion that we've talked about in the past as kind of being the ceiling for our capital spending and then incorporate from that kind of 3% to 5% growth.

Okay. Okay. That's helpful. And then that [ $5 billion ], let's just assume another $350 million, like I like the fact you guys are capitalizing your turnarounds, gives good transparency. So another -- I'm splitting hairs here, Jon, but that would include turnarounds or wouldn't include turnarounds?

That will include turnarounds.

Okay. Okay. Terrific. And Travis's question was good. I mean, kind of interested in -- like I love your Asian business. I mean it doesn't get a whole lot of airtime. But what does that business look like over 2, 3, 4, 5 years? How much time are you spending there? Do you want to grow it? Do you want to harvest it? Are you going to sell it?

I don't think -- the way I think about that business, Greg, you're quite right. It's a really good business, and it spits out a lot of free cash flow. I think it's averaged about $1 billion a year for the last 5 years that we've owned it on a free cash flow basis. And what we really like about it is it's fixed price gas plus we get the value of the liquids on a Brent basis. Your operating costs are about $1 an M. The fiscal take is relatively modest, and there's really not much of a requirement for sustaining capital. So the way we kind of think about it is not harvesting the asset but definitely sweating the asset and staying true to the Block 29/26, where we think we have a competitive advantage.

But we kind of look at it under those terms. We evaluate the opportunities within the block. We work well with the partner there that we have in CNOOC, and we're really grateful for that relationship. And it's just an asset that we just continue to take free cash flow from and invest appropriately in.

Our next question comes from the line of Manav Gupta from UBS.

I just wanted to quickly focus a little bit on egress. We know Enbridge has announced MLO 1 on their call, they are very close to announcing MLO 2 could happen before year-end. And then they also threw out the prospect of an MLO 3. And then there are a bunch of projects that ET and Enbridge are looking where they could even reverse the Bakken pipeline, get more Canadian crude onto DAPL. So I'm just trying to understand, as all these Egress projects are taking shape place, does this give Cenovus a little more confidence that we are not going back to the days where WTI, WCS could be $25 or so. Those days are behind the Alberta oil sands. Can you talk a little bit about that?

Manav, it's Geoff Murray. It sounds like between my last comment and this one you scoured the world and found a number of the pipelines. There's -- there are more out there as well under development. And I'd point to a few other developments and other companies that are working away on things in the same sort of time frame. The projects you referenced, I think, are all intended to be in service late '27, '28, '29. There's projects that push '29, '30, '31 as well. And I think, as Jon pointed out, there's a number of these opportunities out there. Very few of them look like the big challenging mega projects we saw of a decade ago, and there was a certain level of probability around those things. These things are smaller. They're more easily permitted. There is less development to be done.

And I would say we're well connected with all of them, broadly supportive of egress. The key will be industry and Cenovus being prepared to stand by and stand behind and take long-term contracts around these assets. And as Jon pointed out, don't be surprised to see us do that. That is a way of saying we have impact and influence to drive the outcome you referenced, which is to continue to bring egress to market to keep the differential in Alberta where we see it now. And it does feel fairly comforting that, that is something we can take action to drive for at least the next 5 to 10 years.

Yes. I think, Manav, we don't take any of this for granted. So we would never be of the view that we're never going back to where we are. But our challenge as a company is to make sure that we take advantage of these opportunities as they arise. We're kind of in a world right now where we're opportunity-rich in terms of egress. And so we're looking at everything. But we also understand that egress is something that's very important to this company on a long-term basis. But with everything that's out there today, it's very positive for this company and this industry. And as I said before, you should look for us to lead this and take advantage of it.

[Operator Instructions] And there are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. Thank you, operator. So this concludes our conference call. I'd just like to thank everybody for joining us. We definitely appreciate your interest in the company. So thank you very much, and have a great day.

This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great day.

Good morning, everyone. Thank you for standing by, and welcome to the Cenovus Energy's Third Quarter 2025 Results Conference Call. [Operator Instructions] As a reminder this call is being recorded. I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Thank you, operator. Good morning, everyone, and welcome to Cenovus' 2025 Third Quarter Results Conference Call. On the call this morning are CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. Then we'll open the line for John, Kam and other members of Cenovus' management team to take your questions.

Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. Additional information is available on Cenovus' annual MD&A and our most recent AIF and Form 40-F.

And as a reminder, all figures we referenced on the call today will be in Canadian dollars, unless otherwise indicated. You can view our results at cenovus.com. For the question-and-answer portion of the call, please keep the one question with a maximum of one follow-up.

You're welcome to rejoin the queue for any other follow-up questions you may have. We also ask that you hold off on any detailed modeling questions, you can follow up on these directly with our Investor Relations team after the call.

I will now turn the call over to Jon. Jon, please go ahead.

Great. And thank you, Patrick, and good morning to everybody. To begin the call, I'd like to recognize some of our employees for safely achieving a number of critical accomplishments and milestones over the quarter. Coming into this year, we set some very ambitious goals for the company in 2025 and our execution has been near flawless.

What make these achievements even more satisfying is that we have remained focused on the safety of our people, the communities in which we operate in the environment. Now for example, at the West White Rose project, we completed some intricate and critical work in the third quarter that included installing the top sides on the gravity-based structure, making subsea connections at 120 meters below the ocean surface and completing a turnaround of the SeaRose FPSO.

These operations require thousands of offshore hours and were completed in one of the most hostile operating environments, the North Atlantic and I'm incredibly proud of our people and their continued commitment to our core values as we meet our goals and milestones.

Now before I get to the results, I'd also like to take a moment to speak about the MEG acquisition. As many of you are aware, MEG shareholder vote, which was scheduled to take place yesterday has been postponed to next Thursday, November 6. The delay is to give time for MEG to respond to a regulatory inquiry related to MEG's consideration of the amended terms of the transaction-related matters.

The inquiries associated with a complaint raised by a former employee of MEG, who holds approximately 4,000 shares. We do not expect this inquiry to have any impact on the transaction. There continues to be very strong support for the transaction for MEG shareholders with 86% of the shares voted in favor of the transaction. We expect the vote to proceed as planned next week.

Cenovus remains resolute in our commitment to this transaction. When completed, this acquisition combined with the organic growth we are already delivering across our business is transformational to this company. Subject to shareholder and court approval, we anticipate closing this transaction in November and welcoming the MEG team and moving quickly to capture the identified synergies and beyond.

Now turning to the quarter. We've spoken about 2025 as being an inflection point for our company, where the investments we've made in our people, our assets and in the growth of our business start to come through. The third quarter results are a proof point of more to come. We achieved the highest ever upstream production of 833,000 BOE per day, highlighted by the best ever performance of our oil sands assets which contributed 643,000 barrels per day.

At Christina Lake, production was 252,000 barrels a day in the third quarter, supported by the ramp-up of volumes from Narrows Lake. In the quarter, we brought on 3 well pads at Narrows Lake, which are continuing to ramp up as expected. We expect Christina Lake to sustain or exceed its current production rates in the coming quarters.

At Foster Creek, we achieved a production record of 215,000 barrels per day in the quarter. As part of the Foster Creek optimization project, we brought on 4 new steam generators online in July and they've already supporting consistently higher production from the asset, well ahead of schedule.

Commissioning of the water treatment and deoiling facilities is underway and approaching completion. New pads will be brought online in the first quarter of 2026. We have effectively brought forward a portion of the growth from this optimization project that was really not expected until 2026. We expect to build on the high level of production in the coming quarters as we fully utilize the steam capacity and complete the project.

At Sunrise, we executed a turnaround in September and production was 52,000 barrels a day in the quarter, with turnarounds at both sides of the plant completed in the year and followed by an efficient ramp-up, we expect Sunrise to exit the year around 60,000 barrels a day. The first of the new well pads from the East development area at Sunrise is planned for start-up in early 2026.

Development of the high-quality reservoir in this region will deliver the next phase of growth from the asset over the next 2 years. The Lloydminster Thermals produced 96,000 barrels per day in the quarter, the assets have performed very well despite 18,000 barrels of production from Rush Lake facilities remaining shut in as strong performance from the other assets in the region offset some of the lost volumes.

At Rush Lake, we have confirmed the integrity of the asset and are working towards a phased restart of production prior to the end of the year, subject to approval by the regulator. We expect to safely ramp up production through 2026.

At West White Rose, I'm pleased to say the commissioning is nearly complete and there has been an extraordinary achievement by everybody involved, and we will be drilling from the platform prior to year-end and seeing first oil in the second quarter of next year.

Now moving to the Downstream. We had an excellent third quarter. The Canadian refining business continues to run well with crude throughput of 105,000 barrels a day and utilization rate of about 98%. In U.S. refining, we delivered record production with crude throughput of 605,000 barrels per day and utilization rate of 99%.

Our assets ran as expected during the quarter with high rates of utilization and availability. And this in conjunction with seasonally higher -- or seasonally stronger crack spreads generated positive refunds flow for the business. Cost control in the downstream has been a focus area for the business, and we continue to see unit cost trend downward towards competitive benchmarks and with the sale of WRB, which closed at the end of the quarter, our downstream business is now fully owned, operated and within our control.

Now I'll turn it over to Kam to walk through some of the financial results.

Thanks, Jon, and good morning, everyone. In the third quarter, we generated $3 billion of operating margin and approximately $2.5 billion of adjusted funds flow. Operating margin in the Upstream was approximately $2.6 billion, an increase of around $450 million from the second quarter, driven by our strong operating performance and higher realized pricing in the oil sands.

Oil sands non-fuel operating costs of $9.65 per barrel decreased quarter-over-quarter due to lower turnaround activities and higher production volumes. We continue to make progress on reducing operating costs across the upstream business and expect to see further reductions as we bring on the West White Rose project, realize a full benefit the Foster Creek optimization project and continue to see steady ramp-up at Sunrise.

Our downstream business demonstrated strong performance in the quarter with operating margin of $364 million. This included $88 million of inventory holding losses and $38 million of turnaround expenses partially offset by a $67 million benefit related to the receipt of the small refinery exemption at Superior.

In the U.S. refining per unit operating costs, excluding turnaround expenses were $9.67 a barrel, a decrease of $0.85 a barrel from the second quarter and over $3 a barrel relative to the same quarter last year. The reduction in OpEx was largely driven by performance from our operated assets which delivered operating cost of approximately $9.90 per barrel in the third quarter.

Adjusted market capture for the U.S. refining business was 65% in the quarter, this was supported by a capture rate of 69% from our operated assets, which benefited from the small refinery exemption at Superior and increased refined product exports from the dock at Toledo. The sale of our 50% interest in WRB refining closed at the end of the third quarter.

In addition to the cash proceeds of $1.8 billion received on October 1, the transaction eliminated Cenovus' share of drawn credit facilities associated with the joint venture of $313 million, resulting in a total value received at $2.1 billion based on preliminary closing adjustments. Results from our U.S. refining business will only include our operating assets beginning in the fourth quarter, and we have updated our 2025 guidance to reflect the sale of Wood River and Borger.

Capital investment of $1.2 billion was driven by a consistent level of sustaining activity across the business in addition to the continued advancement of our key growth projects. With the West White Rose project now substantially complete, we continue to expect our growth capital to come down significantly in 2026.

At the end of the third quarter, our net debt was approximately $5.3 billion prior to the receipt of the $1.8 billion of cash proceeds from the sale of WRB. We returned $1.3 billion to shareholders in the quarter through dividends and share buybacks. We took the opportunity to allocate more capital to share repurchases in the third quarter following the announced sale of WRB.

This included the purchase of about 40 million shares at an average price of $22.75 per share. The total value of the share repurchase in the quarter was $918 million which is approximately $175 million higher than our excess free funds flow in the quarter. Subsequent to the quarter and through October 27, the company purchased another $409 million worth of shares or about 17 million shares.

And as Jon noted, following the approval by MEG shareholders, we expect the acquisition of MEG Energy to close in November. Total consideration for the transaction is expected to be a split of 50% cash and 50% Cenovus shares. This equates to a maximum of approximately $3.8 billion in cash and the issuance of $160 million Cenovus shares on a fully pro rata basis.

Pro forma, our balance sheet remains strong with less than 1x net debt to cash flow. And going forward, we'll continue to be opportunistic with our share buybacks while living within the guidelines of our financial framework. As we head into 2026, our major projects are nearing completion and our growth capital is coming down.

Combined with the strength in our balance sheet, the business is positioned well to support our near-term growth plans and remain resilient even at the bottom of the cycle commodity price.

I'll now turn the call back to Jon for some closing remarks.

Great. Thank you, Kam. As I mentioned earlier, we set some ambitious goals for ourselves and the company for this year, and I couldn't be more proud of the way our people have taken up the challenge. We've largely completed our growth projects and are seeing the benefits of higher production with more to come over the future quarters.

Our downstream business has been relentless in driving performance across the portfolio of assets and the sale of WRB gives us full operational, commercial and strategic control of our downstream business while monetizing our non-operated business at an attractive price. Our business is blessed with a deep inventory of development opportunities at low supply costs below $45 WTI and underpinned by a fortress balance sheet.

We are focused on aligning our strategy, business plans and priorities and look forward to building on a quarter-over-quarter growth and value for the foreseeable future. And with that, I'm happy to answer your questions.

[Operator Instructions] Our first question comes from the line of Menno Hulshof from TD Cowen.

Just a question on portfolio streamlining. If we assume that the MEG deal closes towards the middle of November, like you've talked about, how should we be thinking about asset sales potential in the context of what would be a more levered balance sheet? I know you get this question a lot, but any updated thoughts there would be helpful.

One of the things that we are always very cognizant of Menno is the amount of leverage we keep on our balance sheet, and we've always run with an underlevered balance sheet, which allows us to do transactions like this very comfortably.

So there is no burning platform to need to delever after doing this transaction. We're very comfortable with the level of debt that we're going to be taking on to get this deal done and through time, we'll get back to the $4 billion of net debt, but there is no urgency to do asset sales or something like that in an effort to get there.

And that being said, we always look at the portfolio. We always should think about how we want to position ourselves and if opportunities arise. We're always live to those, but certainly, there's nothing that would say that we need to do something tomorrow. We would never do a transaction like this if we felt it was going to corrupt the balance sheet and put our equity holders in harm's way.

Great. And then maybe moving on to the downstream, we're sort of moving into November now, sort of 1/3 of the way through the quarter. How would you frame the setup for U.S. Downstream for Q4. And then maybe on a related note, how much should we expect market capture to be impacted with the Wood River border assets no longer in the mix? I'm guessing it's no more than, call it, 1 to 2 percentage points, but any thoughts there would help.

Well, in Q3, our market capture was actually higher in our operated assets than they were in the non-operated assets. But I've got Eric Zimpfer with us this morning. So maybe I'll turn that question over to him to see how he's thinking about Q4 and market capture.

Yes. Thanks, Jon, and thanks for the question, Menno. Yes, I'd say I certainly think the third quarter is a testament to the work that the team has done, and I think has been something that has really been a focus area for the year. And really proud of the results of what we're seeing in the third quarter.

As we look at the fourth quarter, I think there's a couple of things I think about in terms of the underlying performance, continue to be encouraged by the trajectory. So reliability improvements that we've made have really give us a foundation.

I think the cost focus that we've had throughout the year and the results that we're seeing with the lower cost base is something that, again, we continue to focus on and will continue to be something that we emphasize going forward.

Yes, any time you get into the fourth quarter, you expect margins to start to come off, cracks start to weaken. We're already seeing some of that. There's some strength right now. But I think having a strong business and strong underlying performance gives us the ability to kind of weather through some of the market challenges that you inevitably expect in fourth quarter and then also in the first quarter as well with the PADD II region specifically.

In terms of the market capture, I'd just maybe emphasize. Reemphasize what Jon shared, that has been a continued area of focus for us. A number of things that we've worked to really help strengthen our market capture. The U.S. operated portfolio really outperformed the collective portfolio in terms of what we saw in market capture.

So continue to be encouraged, but it's something we are continuing to focus on and try to figure and look for opportunities to grow that market capture even more through our synergy opportunities as well as accessing some markets where we can have some higher netbacks and better product placement.

One moment for our next question. Our next question comes from the line of Patrick O'Rourke from ATB Capital Markets.

Maybe just to sort of continue on the downstream theme there from Menno. Just wondering, now with the fully operated portfolio with the integration in the kits, sort of what the flexibility is going forward in terms of the product slate. It's a little bit lower on, call it, diesel distillate yield and maybe some of your Canadian peers, is there an ability to raise those things, capture premium products?

And then you've spoken to pushing product in the more premium markets, Eastern Canada, et cetera. What progress you've made on that so far.

Yes. Thanks, Patrick. It's a great question. In terms of the portfolio, I think one of the things I'm really excited about is with the opportunities of the U.S. portfolio, I think, particularly around the synergies each refinery has its unique configuration that allows us to maximize the value. But one of the things we've really started to lean into is how do we optimize across the entire portfolio? And how do we get the best product yield across portfolio and not just asset by asset, but really thinking about it at a portfolio level. I think that gives us a tremendous opportunity.

And I can think particularly in the Ohio Valley area, where we're able to optimize, whether it's our premium production, premium gasoline production whether it's balancing our distillate feedstocks and maximize their distillate production truly an area where we're continuing to explore and we see -- we certainly see some potential benefits and also the opportunities to do some investments in the future to look at how do we continue to make the best products from our kit.

In terms of kind of the second part of your question on accessing the markets, continues to be an area of focus. PADD II is, we think, a really good region for us, but the opportunity to place products outside of PADD II and find more advantaged markets is really important to our strategy.

I would point to -- we've made significant progress in how we're managing the Toledo marine facility. And that has given us the ability to put products into a number of different regions outside of PADD II whether it's in the Canadian markets, whether it's into Upstate New York or whether it's into other regions on the Great Lakes.

But tons of opportunities there. We're really excited about the opportunity to further explore that. And see great upside there.

Okay. Great. And then just in terms of free cash flow allocation priorities, I know with the initial MEG transaction, you came out with sort of a formula in terms of allocation of balance sheet versus shareholder returns, 50% than 75% finally 100%. Today's updated deck just really speaks to the 100. And I know you said it wouldn't necessarily be formulaic on a month-by-month, quarter-by-quarter basis.

But maybe if you could comment sort of on the game plan in terms of allocation today between delevering and share buybacks.

Sure. Kam, you've done a lot of work on this. Why don't you take this one?

Yes. So Patrick, I would kind of separate sort of from the MEG transaction what we're doing today. Obviously, we spent the last year to -- even longer than that, getting the balance sheet to where we are today, which is at that $4 billion target. So putting MEG aside for a second, I would say the plan would be to return 100% of our excess free cash flow because we are at our long-term debt level.

And we'll be -- we continue to see that as a really good opportunity today, and we'll continue to utilize our free cash flow to return that cash back to shareholders. And I'd say for now, given where the share price is, and we continue to see it as an attractive place to deploy capital, you should expect that excess free cash flow to go towards share repurchases.

Obviously, as we get to the point where MEG does close, which we still expect here in November, we will adjust that framework to be a bit more balanced with deleveraging and shareholder returns. So the plan would be as we bring the debt back down to around that $6 billion, we'll be kind of around 50-50.

But as you pointed out, it's not going to be so prescriptive in formulaic. We'll be thoughtful about how much we put on the balance sheet and how much we repurchase shares. And some of that will depend on commodity prices and free cash flow. But think of those as guidelines versus formulas going forward. But I think overall, the goal would be to get back down to the $4 billion, that is still our ultimate target.

We have an approach where we want to make sure we get the balance sheet back to that $4 billion. Obviously, our cash flow base, our growth we've got plus the plan with the MEG assets, we'll put the company in a really good position from a leverage point of view. But we view our balance sheet as being something that's going to stay pristine, and it allows us flexibility and opportunity like we've been able to pursue on the MEG transaction.

Our next question comes from the line of Alexa Petrick from Goldman Sachs.

I wanted to ask maybe switching gears. As we think about West White Rose, you've made a lot of progress there. What are some of the gating items and then any early thoughts on what that production path could look like for 1H 2026 versus 2H?

Yes. We haven't given guidance for 2026, '27 and '28 yet. But what we have said publicly about West White Rose is that we are largely through commissioning that project now and we'll be drilling well prior to year-end with first production expected in early second quarter 2026. That still remains the direction of travel.

But Andrew, maybe you could just provide a little bit more detail on where we are and what that path may look like.

Yes. No. Thank you, Alexa. Yes, maybe to go a little bit back in time and just catch up too. So obviously, in July, we placed the top sides on top of the CGS. We deep -- as Jon said, we're deep into the commissioning and start-up activities, and that actually included the -- all the subsea so we connected the West White Rose platform to the Sea Rose in terms of all the pipeline work, et cetera.

We'll be drilling by year-end and then indeed, first production in Q2 of 2026. In terms of production ramp-up, it's not -- we're going to drill roughly 5 wells per year. It's roughly a straight line from 2026 through to 2028. And what we've said is in 2028, gross volume should be around 80,000 barrels a day, which net Cenovus share is roughly 45,000 barrels a day, Alexa.

Okay. That's helpful. And then I recognize it's still a bit early, but you've talked about significant amount of growth CapEx coming off next year. Any early thoughts on what that magnitude could look like? And what are some maybe other offsetting considerations we should be keeping in mind?

Yes. So where we've really guided the market, and we'll formalize this when we come out with our budget in December. But if you look at spending the last couple of years, we've been around CAD 5 billion, which would include somewhere around [ 1.5, 1.7 ] worth of growth capital. And what we've been guiding to is 2026 will look different with all of these growth projects kind of rolling off the agenda.

So what you should be thinking about is on an unaffected basis, not including MEG, we would be around $4.2 billion. Take out WRB from that kind of brings you to around $4 billion And that's kind of where we think the budget pre-MEG is going to sit. And then we've also suggested that in 2026 when you add in MEG assets, we would probably be adding about another $800 million for sustaining and growth capital on the MEG assets in 2026.

So maybe I've really just already given you the budget for 2026 capital. But that's kind of what we've been saying, and I think it's very consistent with where we've been taking the market over the last few months and years.

[Operator Instructions] Our next question comes from the line of Manav Gupta from UBS.

I am so sorry about this for UBS IT issues. I wanted to ask you, there are a number of organic growth projects, which you are pursuing, which could deliver over 100,000 barrels of organic volume growth on top of MEG and so can you update us what's the progress over there? How are those projects progressing?

Yes. I'm not sure where the 400,000 barrels came from Manav.

No. 100,000. 100,000.

Sorry, I think you said 4, you kind of worried me I thought maybe our messaging had been confused.

No. 100,000, sir.

Yes. What we've been guiding the market to is about 150,000 barrels of growth. And it really comes from heavy oil, conventional and offshore so right across our portfolio. So on the East Coast, as Andrew mentioned, we look to ramp up the West White Rose project, about 45,000 to 50,000 barrels a day by 2028.

That growth starts in '26 and progresses linearly through '26, '27 and into '28. And that's kind of the biggest piece of the growth profile. What we're seeing in Narrows Lake with the tieback to Christina Lake, is the 20,000 to 30,000 barrels a day starting to materialize there, and you'll see Christina Lake in that 250 to 260 range.

We talked about adding 80,000 barrels a day of steam capacity at Foster Creek, which would add about 30,000 barrels a day to that asset. Today, we're already seeing about [ 20 ] of that with the early steam that we brought on. in Q3. But you should see that continue to ramp up in 2026 as we bring on well pads as well finished, the water handling and deoiling sections of that growth.

In Sunrise we're just getting into what we call the V PADD, and these are in the Eastern region of Sunrise. These are some of the most prolific PADDS that we've got in our inventory, and we expect to see production grow from 55,000 barrels a day to close to 75% over the next couple of years at Sunrise.

And then the other growth comes from our conventional and cold heavy businesses. But what you'll see from us as we progress through time and get through '26, '27 and in '28 is production will increase into that kind of 950,000 barrel a day range.

Very helpful. My quick follow-up here is, during the quarter, the buyback was very strong. The buyback went up materially did the net debt? I'm just trying to understand, was this just a timing issue where the PSX deal had been announced and those cash proceeds are probably coming in somewhere in the fourth quarter. That's why the buyback and the net debt went up at the same time, if you could clarify on that.

Sure, Manav, it's Kam. So I think one thing just to keep in mind is our reported net debt at the end of September was $5.25 billion. That did not give consideration to the $1.8 billion that we brought in for the sale of Wood River and Borger. So after -- shortly after quarter end, we dropped back down to $4 billion but what I would say is we announced the sale back in early September.

We very intentionally obviously knew the timing of closing and when we get the cash. So we actually accelerated some of our buyback program through September and in October. So I think what I would tell you is I think we're going to continue to steward towards that $4 billion going forward. Obviously, MEG transaction when that closes, we'll change that.

But I think to the extent that we can, we'll continue to use 100% of excess free cash flow to buy back shares. But the debt -- the goal is to kind of hold the debt in and around that $4 billion. But obviously, the reported debt number at the end of September did not have or did not reflect the proceeds we received from the sale.

That's exactly what I thought. So it was just a timing issue. The buybacks are in 3Q and the proceeds coming in a little later.

Our next question comes from the line of Patrick O'Rourke from ATB Capital Markets.

Welcome back, Patrick.

Just wanted to kind of build on the comments there with respect to narrows. In the public data, we're seeing that sort of in the 15,000 to 16,000 in September, so getting close to the low end of that range. a bit of differentiation on well performance. We're only working with September here. You guys have the hindsight of more recent data.

I would assume, through -- close to through the month of October. Just wondering how well performance is trending relative to type curve and any time frame around when you get to the bottom of that 20,000 range.

Yes. So I'm going to turn this over to Andrew to give some detail, but we started steaming 2 well PADDS back in July and brought on about 18 wells on the X5 and 6 PADDS. We're currently steaming the third PADD, and we brought on, I think, 6 of 8 of those well pairs. And these are ramping up as expected. But Andrew, you're all over this every day. So why don't you add some good color.

Patrick, we were totally on top of this, and we're seeing exactly what we expected from those wells and that they are strong without giving too many numbers. I can tell you here that production in October is now up into the 20-something thousand barrels a day, 22,000, 23,000 barrels a day.

Indeed, we're producing from 3 PADDS pads, we're ensuring that we've got great conforms across all of those PADDS. And then here in early Q1 of next year, we'll bring the fourth pad on. So no, we're very comfortable and very confident in the performance we're seeing at Narrows Lake and ultimately in the delivery of that growth of the Christina Lake asset.

There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thank you, operator. And I think we're grateful and surprised. There were no questions about MEG but be that as it may, this concludes our conference call, and thank you for joining us. As always, we really appreciate the interest in the company. And thank you to all, and have a great day.

This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great day.

Good morning, everyone. Thank you for standing by, and welcome to Cenovus Energy's conference call regarding the acquisition of MEG Energy.

[Operator Instructions]

As a reminder, this call is being recorded. I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Thank you, operator. Good morning, everyone, and thank you for joining us to discuss the details of the proposed acquisition of MEG Energy announced earlier this morning. On the call today are Cenovus' CEO, Jon McKenzie; and CFO, Kam Sandhar. In a moment, I will turn the call over to Jon and Kam to share their thoughts on the transaction. Then we'll open the line for your questions.

Along with the press release issued this morning, we posted a slide presentation with additional details of the transaction. This can be found on the Investor Relations section of our website at cenovus.com.

Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion. And as a reminder, all figures we referenced on the call today will be in Canadian dollars, unless otherwise indicated.

For the question-and-answer portion of the call, please keep the 1 question with a maximum of 1 follow-up. I will now turn the call over to Jon. Jon, please go ahead.

Great. Thank you very much, Patrick, and good morning, everybody. I'm pleased to announce that Cenovus has entered into a definitive agreement to acquire MEG Energy in a cash and stock transaction valued at approximately $7.9 billion or $27.25 per MEG share. This is a very significant transaction for Cenovus. In acquiring MEG, we bring together 2 leading SAGD producers, strengthening our long-life portfolio of low-cost oil sands assets that serve as a foundation for this company and capitalize on this company's competitive advantage, heavy oil development.

MEG's 100,000 -- or 110,000 barrel a day Christina Lake asset is one of the highest quality properties in the oil sands and is directly adjacent to our own Christina Lake and Narrows Lake assets.

The fit is exceptional, and it plays right into what we do best, which is optimizing value from SAGD operations over all time frames. These assets will be producing for decades to come, significantly deepening our portfolio within the best oil sands resource in the basin. Combining these assets represents a unique opportunity to capture annual run rate synergies that grow from $150 million a year in 2026, '27 to over $400 million per year in 2028 and beyond. We know these assets well, and we have very high confidence in our ability to achieve the synergies that we've identified with the potential for even more to come as we look at our long-term development options. The transaction is expected to be immediately accretive to adjusted funds flow per share and free funds flow per share.

And importantly, through the transaction, we will maintain a strong balance sheet and remain committed to investment-grade credit ratings while continuing to return cash to shareholders. Now I want to spend a few minutes walking you through the tangible synergies that we see that unlocks the value of this transaction. The first part is made up of corporate and commercial synergies. This includes G&A optimization, IT and procurement savings, new commercial opportunities and reduced financing costs. We see these corporate and commercial synergies providing about $120 million of savings achievable in 2026.

Now there are over $280 million of annual development synergies and operating synergies that are unique to Cenovus. We will capture about $30 million per year of that in the near term, net of some additional capital required to deliver the full synergy value, but we expect to realize the full $280 million beginning in 2028. These development synergies are and where the industrial -- sorry, these development synergies are where the industrial logic for the transaction truly comes into focus.

Now for those of you that had a chance to listen to oil sands presentation during the Stampede Week, we highlighted 5 key elements that make up our optimized approach to SAGD development, which are geological characterization, optimal development sequencing, front-end well design, operating strategy and finally, late life management.

Utilizing this development approach, our technical teams have identified a robust set of opportunities that are both tangible and actionable. These synergies I will discuss today are very integrated into this strategy, but we're not done as we expect more synergies over time, particularly in optimal development sequencing. Now with that in mind, we have a plan to take production at MEG's Christina Lake to over 150,000 barrels a day by the end of 2028 and reduce the steam oil ratio down below 2, utilizing this optimized development approach. To do that and deliver the full $280 million of annual development and operating synergies, we will spend about $400 million of net incremental capital between 2026 and 2028 above MEG's current plan.

With the incremental scale our business provides and through application of our optimized integrated approach to SAGD development, we can increase production and structurally drive down development costs, improve the steam oil ratio and implement near-term opportunities to drive free cash flow higher in the future. So as an example, you can see on Slide 17 -- or Slide 7 in the presentation we posted today, one of the first opportunities we see is to apply Cenovus' pad and well design standards to all future development on the acquired asset. This means increasing well spacing from 50 to 100 meters while recovering the same resource, drilling fewer wells and longer laterals and minimizing surface infrastructure.

We also plan to deploy our highly successful redevelopment well program, which increases production without the need for additional steam injection. These wells reenter already heated reservoirs and target bypassed oil, delivering production at about 1/5 the cost of additional -- traditional SAGD well pairs. Redevelopment wells are among the most capital-efficient opportunities in our portfolio. We currently drill about 100 of them annually across our oil sands assets. At MEG's Christina Lake asset, we've identified more than 250 potential redevelopment well locations so far, only a small number of Cenovus-style redevelopment wells that have been drilled to date, highlighting the significant untapped opportunity.

Together, the changes I've just described expect to drive future finding and development costs down to about $2 per barrel, resulting in lower sustaining capital required over the long term. Another opportunity we've identified is the potential to increase the steam capacity at MEG's Christina Lake plant by over 30,000 barrels per day above and beyond the additions, which are currently underway as part of the MEG facility expansion project. This will translate into about 15,000 barrels a day of new production beginning in 2028. To do this, we plan to rerate the existing steam generators and bring steam quality up to approximately 85%.

This is the same way we run our generators at Foster Creek and Christina Lake today and applies our proprietary monitoring and operating practices to improve performance. In addition, we have a steam generator available that we can put into service at MEG's Christina plant over the coming years. Including the cost of some minor debottlenecks to accommodate the additional steam, we expect to add this new capacity for incremental capital investment of less than $150 million.

Another opportunity that comes with MEG's Christina Lake asset is the ability to access resource, which was previously inaccessible or was located a long distance away from our existing processing facilities. For example, MEG has -- or sorry, Cenovus has top-tier resource in areas like Hardy, Winefred Lake and Leismer, which are located on the other side of MEG's lands from our Christina Lake asset. Accessing these resources would have required long-distance pipeline and likely wouldn't have come into play for many decades.

With the addition of MEG's infrastructure, these resources can now be advanced and tied into the acquired processing facility much sooner and at a lower cost, accelerating low SOR resource and driving incremental value. We can also now access resource sitting within the competitive draining offsets between our lands and MEG's. Development is restricted within 100 meters on either side of the lease boundary. And with that lifted, additional resource is available to develop and more optimal pad orientation is possible going forward. All of these development synergies I've described are unique to Cenovus and will enable us to create real value for both Cenovus and MEG shareholders over the long term.

I'd like to take a moment to recognize the MEG team for the innovative work they've done at Christina Lake. MEG is one of the top SAGD operators in the industry, and we are very excited to leverage the best practices of both companies to continue to drive value. We can see several areas where MEG has advanced new and innovative approaches, and we'll be evaluating to see what we can implement across both Christina Lake assets as well as extending to the rest of our SAGD portfolio. At Cenovus, we remain committed to pushing the boundaries of SAGD innovation, and this combination brings together 2 of the best-performing producers in the space. Together, we are poised to accelerate technical advancement and set new benchmarks for performance in heavy oil development.

So now I'll turn it over to Kam to walk through the financial aspects of this transaction and our capital allocation priorities.

Thanks, Jon, and good morning, everyone. Before I get into the financial aspects of this transaction, I'm going to start by grounding us with our financial framework. We've always believed in positioning the company to manage a business that has a strong balance sheet, is resilient at bottom of the cycle commodity prices and has the ability to grow and enhance shareholder returns, including the base dividend. This transaction has been structured in a manner that continues to manage those priorities. We structured this transaction to minimize dilution to our existing shareholders, maintain a strong balance sheet and our mid-BBB investment-grade credit ratings while continuing to deliver a balance of shareholder returns and debt reduction.

The total transaction is valued at approximately $7.9 billion. The total consideration will be split with 75% cash and approximately 25% in Cenovus shares. This equates to $5.2 billion of cash and approximately 84.3 million shares. Cenovus will fund the cash component of the transaction with a fully committed financing made up of a $2.7 billion term loan and an acquisition facility. The financing will not change our current liquidity position, which stays strong with over $8 billion in undrawn committed credit facilities and cash on hand today. Upon closing, we expect our net debt to be approximately $10.8 billion with pro forma net debt to adjusted funds flow of less than 1x at current strip, representing a strong balance sheet.

This financing structure will allow us to maintain our mid-BBB credit ratings with a commitment to reduce net debt down to our target levels over time. As part of the transaction, we have updated our financial framework to balance deleveraging with shareholder returns as we move back towards our long-term net debt target of $4 billion, which remains unchanged. We plan to return 50% of our excess free funds flow to shareholders while we remain above $6 billion of net debt with the remaining 50% being put towards debt reduction. Once net debt falls below $6 billion, we'll increase target returns to around 75% of excess free funds flow. And when we ultimately reach $4 billion in net debt, we'll increase returns to shareholders to approximately 100% of excess free funds flow.

Keep in mind, these are guidelines and that we will not be formulaic about our returns in any given quarter. We're committed to returning cash to shareholders, but just as important is reducing our net debt down to our target. This allows us to be opportunistic over time and ensures we can sustain low commodity prices without compromising our dividend and our capital program. Cenovus will also actively look for opportunities to accelerate deleveraging and shareholder returns. This transaction is supportive of our long-term strategy of increasing our dividend ratably and consistently over time.

With the synergies Jon discussed, we expect to generate the long-life nature of this asset and the development runway of inventory we have is economic below $45 WTI, and we expect this acquisition will enhance and elongate our ability to increase our dividend over time. We continue to prioritize resilience at the bottom of the cycle, maintaining our current commitment to fully fund the sustaining capital and our base dividend at a WTI price of $45 a barrel. We will review the dividend in April and subject to Board approval, expect to continue to deliver on our commitment of double-digit growth in dividend per share over time.

I will now turn the call back to Jon for some closing remarks.

Great. And thank you, Kam. In summary, this transaction represents a rare combination of strategic fit, highly complementary assets and the ability to create significant value over both the short and the long term. We are building a contiguous platform of top-tier resource and infrastructure with decades of development ahead. The synergies have been -- that we have identified are unique to Cenovus and result from the proximity of our assets and our differentiated operating strategy. The transaction will bring our oil sands production to over 720,000 barrels a day with plans to grow to over 850,000 barrels a day by 2028. It enhances our cash flow and free funds flow profile while allowing us to maintain our strong financial position.

And with that, we're happy to answer your questions.

[Operator Instructions] Our first question comes from the line of Menno Hulshof from TD Cowen.

Maybe I'll just start and congratulations on the announcement. But the -- maybe the first question is on the $4 billion net debt target. With the big ramp-up in production and free cash beginning next year, did you consider raising it with this announcement? And if not, why does $4 billion still feel like the right target?

Thanks, Menno. I'll let Kam answer that, and maybe I'll chime in with some additional thoughts.

Yes, Menno, as you know, we are obviously in the midst of a fairly robust capital program, and we are -- we have a fair amount of growth over the next few years. I think one of the things we've always talked about is we really like the position we put ourselves in with the balance sheet that we have today. And to be honest, the reason we've been able to do this transaction is all the great work we've done on the deleveraging over the last couple of years.

So what I would say is that we always evaluate and look at our debt levels in relation to the cash flow that's generated at bottom of the cycle. It's something we'll always look at from time to time. But I would say, given where we are today, obviously, we are adding a fairly significant asset into the portfolio with MEG's assets and the free cash flow it's going to generate at the bottom of the cycle. But I think today, we're really comfortable with continuing to target an underlevered balance sheet and like the fact that it provides us optionality and opportunity, whether that's doing transactions, buying back our stock or even deploying capital into the business.

Yes. Menno, I'd maybe just add a little bit to that. One of the principles that we have embraced at Cenovus and this goes back a number of different -- or a number of years is that these commodity companies, in particular, this industry needs to run underlevered balance sheets. We can't be in a position where our business plan requires us to be in the debt capital markets or the equity markets.

So when we got to $4 billion, as you know, that was predicated on 1x EBITDA at the bottom of the cycle. With the asset base we've got today, it's significantly more than that. But as a principle, we're quite happy having underlevered balance sheet, which not only reduces the risk to the company and the equity holders, but also allows us to take advantage of opportunities in the market or in our shares as they present themselves.

Got it. And then in terms of the outlook, and this is just more a point of clarification. Does any of this -- to the extent that this is successful, does any of this impact anything within your plan to ramp production from 800,000 to 950,000 BOE/d? And then I guess there's a third question, is there a break fee?

So I'll answer the first one, and then I'll turn it to Kam for the second. So nothing changes in the base plan. This is all incremental to the base plan. Now one of the things we will do at our Investor Day in March is we'll give you a fully baked picture of kind of a combined Narrows Lake, MEG Christina Lake and Cenovus Christina Lake. And at that time, we expect to see more synergies and have more opportunities. The way you should be modeling today is this acquisition is incremental to our plan to get to 950,000 BOE/d.

Yes. Menno, on your third question, as it relates to break fee, I would say it's quite typical for transactions like this to have customary arrangements and break fees as part of this. And this transaction is no different from that perspective. And some of that detail will come out in due course.

Okay. So you're not prepared to provide that number today?

No, not today.

Our next question comes from the line of Neil Mehta from Goldman Sachs.

Congrats on this transaction. I was wondering if you could spend a little bit more time on the steam generator capacity as that does seem to be a material part of the long-term volume uplift and kind of unpack the engineering behind it and simplify the upside associated with that for the investment community.

Sure. So as you know, Neil, MEG is undertaking a facility expansion project today, and they're adding about 20,000 barrels a day of steam capacity through that exercise. What we know is that they also have additional unused oil treating capacity inside that facility. And so through a combination of doing 2 things, we're going to increase that steam capacity by about -- call it, 30,000 to 34,000 barrels a day of incremental steam.

One is re-rating the existing steam generators to produce steam quality up to about 85%, and that's what we do, as I mentioned, at Foster Creek and Christina Lake. That gets you about -- I think the number is 19,000 barrels a day of -- or 15,000 barrels a day of incremental steam. And then we're also adding a sixth generator, one that we actually have in inventory that's going to fit into their plant that adds kind of another 19,000 barrels a day. So between those 2, you're adding 33,000 barrels a day of incremental steam capacity with an SOR of about 2, that gets you your 15,000 barrels a day of production.

Yes. And then the follow-up is just around noncore asset sales. When you guys executed Husky, there were a lot of assets that you put ultimately into the market. I'm thinking in this context, Surmont, for example, where does that fit into the portfolio? And is there an opportunity to accelerate the deleveraging from the $11 billion number through asset monetization?

Yes. I mean one of the things that we always do as a company is continuously evaluate our portfolio. And we've talked quite openly in the past about some of the assets and the fit within our portfolio. I think with this transaction, it probably heightens our thinking around getting back to shareholder returns of 100% as well as managing risk of debt. So one of the things that I think you should keep in the back of your mind is that nobody should be surprised if we do find a way to reduce debt more quickly and get back to 100% shareholder returns a lot sooner than just organically deleveraging.

At this time, we have no questions in the queue. So we will wait a minute to give you the chance to connect with us if you do have a question. [Operator Instructions]

Thank you. There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thank you, operator. That concludes our conference call for today. So I'd like to thank everybody for joining us today and wish you all a great day.

This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great day.

Good morning, everyone. Thank you for standing by, and welcome to the Cenovus Energy Second Quarter 2025 Results Conference Call. [Operator Instructions] As a reminder, this call is being recorded. I would now like to turn the meeting over to Mr. Patrick Read, Vice President, Investor Relations and Internal Audit. Please go ahead, Mr. Read.

Thank you, Operator. Good morning, everyone, and welcome to Cenovus' 2025 Second Quarter Results Conference Call. On the call this morning our CEO, Jon McKenzie; and CFO, Kam Sandhar, will take you through our results. We'll then open the line for Jon, Kam and other members of the Cenovus management team to take your questions.

Before getting started, I'll refer you to our advisories located at the end of today's news release. These describe the forward-looking information, non-GAAP measures and oil and gas terms referred to today. They also outline the risk factors and assumptions relevant to this discussion.

Additional information is available in Cenovus' annual MD&A and our most recent AIF and Form 40-F. And as a reminder, all figures we referenced on the call today will be in Canadian dollars, unless otherwise indicated. You can view our results at cenovus.com. [Operator Instructions] I will now turn the call over to Jon. Jon, please go ahead.

Great. Thank you, Patrick, and good morning, everyone. As always, I'll start with our top priority, health and safety. This quarter posed some unique challenges, and I couldn't be more proud of the way our people responded. In late May, the Caribou Lake wildfire forced the evacuation of over 2,000 workers from our Foster Creek and Christina Lake operations. The fire came within a couple of kilometers of Christina Lake. And as a result, the facility underwent an orderly shutdown as per our protocol.

After a brief outage and thanks to the tireless and determined work of our people, we safely ramped production back up to 250,000 barrels a day and return to normal operations over the course of the week. Now this effort included draining and restarting over 50 kilometers of steam pipelines, bringing 26 boilers back online, returning the cogen facility back to service and remobilizing all 2,000 people back to site. It was an incredible effort, all safely done and without damage to our assets.

It's a privilege to witness how our people step up when it matters most, and I'd like to thank our staff for their resilience and continued commitment and dedication. Now turning to the quarter. This was a terrific quarter for the company. A lot of important work got done and many important milestones were achieved.

We underwent a heavy maintenance period completing large turnarounds in both the upstream and the downstream, which came in ahead of schedule and under budget. We achieved some very significant milestones on our major projects, bringing us closer to delivering on our production growth targets and completing our 3-year cycle of higher capital investment.

And through all that activity, we delivered exceptional operating performance across the company. Together, these achievements set the stage for the second half of the year and beyond and they were accomplished, thanks again to the hard work and determination of our people.

Now I want to speak to some of the details. Beginning with the Upstream Production in the quarter was 766,000 BOE per day as we completed turnarounds at Foster Creek and Sunrise and managed the production impacts from the wildfire activity at Christina Lake and the steam release at Rush Lake.

The turnarounds of Foster Creek and Sunrise both went very well. We completed the work and restored production well ahead of schedule, minimizing volumes lost over the quarter. At Christina Lake, production came back strongly following the brief wildfire-related shut-in. Production was 218,000 barrels a day in the quarter and has averaged over 250,000 barrels a day in July and we achieved an important milestone with the Narrows Lake tieback to Christina Lake.

Narrows Lake produced first oil earlier this month in July. This is a huge accomplishment and a testament to the technical and operations team who made this first-of-a-kind tieback possible. We'll ramp up the first pads at Narrow Lake over the remainder of the year and this means a lower steam-oil ratio and sustained higher production rates as we maximize the value from this asset.

Now second quarter was also a very busy quarter at the West White Rose Project. During the quarter, both the concrete gravity structure and the topsides were transported out to the Offshore field location. In June, the CGS was placed on the seabed and in mid-July, the topsides were lifted and set a top of the CGS well ahead of schedule. Now this feed of engineering include the world's first-ever direct ship-to-ship transfer of a topside to the Pioneering Spirit crane vessel.

With both the CGS and the topsides work complete and set in place, hookup and commissioning activities have now begun. This will include the connection to the SeaRose FPSO, which began producing oil earlier in the year following the successful completion of the asset life extension.

During the quarter, it reliably produced over 7,000 barrels per day. We plan to commence drilling from the West White Rose platform before the end of the year and achieved first oil in the second quarter of 2026. At Foster Creek, we tied in four new steam generators during the turnaround and turned them over to operations in July.

These steam generators will collectively add about 80,000 barrels per day of new steam capacity as part of the optimization project. We will complete work on the de-oiling and water treatment facilities later this year, and we're on track to bring on first oil from the project in early 2026. Now during the quarter, we also responded to a casing failure and injector well at Rush Lake, which resulted in a steam release to surface. The release was a localized incident impacting one well at Rush Lake 2 asset.

In response to the release, both Rush Lake 1 and Rush Lake 2 facilities were shut in. Prior to the shut in the facilities had been producing about 18,000 barrels a day. The well has been brought under control and will work together with the regulator to complete a full investigation and put together a plan to safely restart production. As a result and not a caution, we have removed Rush Lake volumes from our production guidance for the remainder of this year.

The production impact has been partially offset by strong performance from the other Lloyd thermal assets driven by new development wells and optimization work. Overall, it's been a very active and productive period for Upstream business, and we continue to deliver on our growth plans. In the Downstream, we had strong results in the second quarter. Excluding inventory holding losses and expense turnaround costs, the Downstream business generated about $220 million in operating margin.

The Canadian refining had another exceptional quarter. Crude throughput reached a new quarterly high of 112,000 barrels per day with a utilization rate of 104%. The reliability improvements made to the upgrader during last year's turnaround have enabled us to test capacity -- test the capacity of the facility with crude rates reaching as high as 87,000 barrels a day versus an operable capacity of 7,500 barrels per day.

The Lloydminster Refinery also performed exceptionally well, with rates reaching 33,000 barrels per day and record asphalt production in the quarter as we took advantage of strong seasonal demand. In U.S. refining, we delivered crude throughput of 553,000 barrels per day while also executing a major turnaround at the Toledo Refinery. And our execution at the Toledo Refinery is exemplary. We took down 8 major refinery units on the east side of the plant and similar to Lima last year, took a targeted approach to address the issues that we expect to improve reliability going forward. The turnaround was completed 11 days ahead of schedule and costs came in at the low end of the guidance range.

Now importantly, this marks the end of a heavy maintenance period across our downstream business where we have expensed nearly $900 million in turnaround costs over the last 6 quarters. With our full network up and running and our major maintenance bond, as we have a clear runway to demonstrate the capability of the refining network through the rest of the year and into the second half of 2026. So I'm now going to turn it over to Kam to walk us through our financial results.

Thanks, Jon, and good morning, everyone. In the second quarter, we generated $2.1 billion of operating margin and approximately $1.5 billion of adjusted funds flow. Operating margin in the Upstream was approximately $2.1 billion. Relative to last quarter, benchmark oil prices were lower and the Canadian dollar strengthened. This was partially offset by the WCS Differential narrowing by more than $2 a barrel in the quarter. Oil sands non-fuel operating costs of $10.73 per barrel increased quarter-over-quarter due to turnaround activities and lower volumes in the second quarter.

We expect operating costs to come down in the second half of the year and into next year as we return for maintenance and begin to bring on additional volumes from our growth projects. In the Downstream, we generated operating an operating margin shortfall of $71 million. Excluding $50 million of inventory holding losses and $239 million of turnaround expenses, operating margin in the Downstream was about $220 million in the quarter.

In the Canadian Refining business, operating costs of $10.63 per barrel decreased by about $0.20 a barrel from the first quarter, coming in below our full year guidance range for the second consecutive quarter. In the U.S. refining business, per unit operating costs of $10.52 per barrel decreased by about $1.60 per barrel from the first quarter and over $1 a barrel relative to the same quarter last year.

We continue to make progress in driving down costs in our operated refineries as we increase reliability and structurally remove costs across our network. Capital investment of $1.2 billion included sustaining activity across the business as well as growth and optimization capital in the oil sands, where we advanced our key projects and in the Atlantic region with the progression of the West White Rose project. At the end of the second quarter, our net debt was approximately $4.9 billion, a reduction of about $150 million from $5.1 billion at the end of the first quarter.

In addition to reducing our debt, we returned $819 million to shareholders through dividends, share buybacks and the redemption of $150 million of preferred shares. We purchased approximately $300 million worth of shares through our NCIB in the quarter or about 17 million shares at an average price of about $17.50 per share. Noncash working capital decreased by $923 million in the quarter, a significant contributor to our ability to continue to return cash to shareholders while further reducing our debt. We will continue to steward net debt towards our $4 billion target while remaining active with our NCIB.

With the value we see in our shares today and with our growth projects on track to start up in the coming quarters. We continue to see a significant opportunity to increase our returns to shareholders going forward through share repurchases. To this end, the company purchased another $129 million worth of shares subsequent to the end of the quarter through July 28, there are about 6.6 million shares.

With that, I'll now turn the call back to Jon for some closing remarks.

Great. And thank you, Kam. So as I touched on before, we had a terrific quarter and have successfully delivered on a number of key initiatives. We completed the turnarounds of Foster Creek, Sunrise and Toledo, well ahead of schedule and under budget. We achieved first oil at Narrows Lake and are now bringing on new production from some of the best quality resource in the basin. We have begun hookup and commissioning of the West White Rose project ahead of schedule after successfully completing critical work to make the concrete gravity structure with the topsides in July.

And we've tied in 4 new steam generators at Foster Creek that brings us one step closer to completing the optimization project and adding over 30,000 barrels a day of production at Foster Creek. Our growth projects are approaching completion. Our major maintenance activities for the year are largely behind us, and we are focused on driving value from our operations. This is a pivotal moment for the company as we execute on our plan to deliver higher production and lower capital into 2026 and increased free funds flow.

We have a clear view on the work in front of us and remain focused on creating long-term value for our shareholders. And with that, we're happy to answer any of your questions.

[Operator Instructions] Our first question will come from the line of Menno Hulshof from TD Cowen.

I'll start with a question on U.S. downstream. And with the understanding that you don't disclose utilization by refinery, and you did touch on this to some degree in your opening remarks, but can we just get a rundown on the status of your PADD 2 operated refineries. And given that the little bit of downstream turn around own activity that was planned for Q3 looks to have been pushed to Q4. How would you frame the bookends for Q3 utilization in market capture?

Yes. So the way I would frame it is, we've always talked about being competitive in the downstream, and we've defined that as kind of a Q1, Q2 cutoff point and we measure it using Solomon. So what we're driving towards is kind of that 98% availability right across the refining network that we have in the U.S. Today, all those refineries are kind of wide open. We're out of turnaround at Toledo. Everything is operating as we would expect it to, and we expect to see that through the third quarter.

I think we have some scheduled maintenance is relatively small at Toledo, and we think that's probably the confusion with additional turnaround work, but as in any refinery, you have regular scheduled maintenance that you undertake during the course of time. But if I kind of look out from now, the only big turnaround we have happens in 2026 at Lima and that looks like that's going to be in the back half of the year, Q3, Q4, and then 2027 at Toledo.

So we are through this major maintenance cycle that we've been in over the last 6 quarters, and we're really looking forward to seeing what we can do over the next 12 months and then more broadly with much less maintenance going forward through '26, '27.

And then maybe just flipping over to Rush Lake. It's good to hear that you've already developed a plan to restart the well. And I'm not going to ask for background the root cause because I know there's in ongoing investigation. But given that it's -- it looks to have been a casing failure on an injection well, can we assume there's minimal risk to Rush Lake design capacity and operating protocols. And are there any read-throughs at all for your other Lloyd projects?

Yes. I think out of an abundance of caution and conservatism, we've removed Rush Lake production for the rest of this year. So you're quite right. We're just finishing our root cause analysis and the investigation right now. We're confident that this is a casing failure on one well. And as I said in my call notes, we've got control of the site we're moving to sort of the recovery phase of this, where we'll work with the regulator and convince ourselves that we've got a good safe start-up plan for this.

But both two things need to come together, and we need to finish the investigation, but suffice it to say we're in the recovery portion of this incident.

Our next question will come from the line of Dennis Fong from CIBC.

I guess, first off, congrats on a really strong quarter. My first question here is just around next steps for some of these up-and-coming projects are ones that you're working on next. I know you've highlighted Sunrise, Lloyd thermal and Conventional Lloyd heavy oil, including multi-labs as kind of potential next projects. Can you discuss around sizing of CapEx and how you would think about the cadence of growth as well as cadence of spending over the next few years as you kind of look towards these projects? As well as kind of how do you maybe rightsize them given obviously the volatile commodity price environment we're sitting in?

Yes. So as we've kind of signaled to the market, we're really coming to the end of an investment cycle that we've had in this business that started in '23 and really concludes this year. So we've been pretty clear that 2026 capital will be much reduced from where we were in '23, '24 and '25 and we've kind of use kind of a low $4 billion as a good marker for you to build into your models. One of the things that we think about as it relates to some of the shorter cycle assets that we've got. And I guess, in particular, as it relates to Lloydminster, we just feel like we've got some real tremendous structural advantages there and that we own a huge block of land.

It's full of oil. We own all the infrastructure. We've got all the pipelines and then we have a lot of the royalty rights there as well. So as with any investment, we kind of rightsize it and we make sure that it returns capital and return on capital at $45. And then we kind of think about what's the right pacing and staging to use in terms of how big that investment needs to be. So we think about all kinds of things, like can we do this efficiently, and we have the drilling location sized and set up and ready to go and that pacing and staging.

So I think -- when you think about 2026, it might be somewhere around the $150 million to $200 million range that we would put into that cold heavy oil business Lloyd that kind of supports growth in the kind of 10% range as we move towards 40,000 barrels a day. But like any investment, it's got to make money at $45.

Great. Thanks, Jon. Really appreciate that color. My second question here and maybe a bit of a follow-on to Menno's first question, and frankly, not to belabor a focus on the U.S. Downstream now that you've completed major maintenance on Toledo and obviously, Lima last year, can you talk towards what maybe your team saw or changed during those turnarounds that provide view in the teams with incremental confidence around kind of this runway for stronger operations going forward?

Yes. So we've now had a chance to get inside every asset except for Superior, which we rebuilt and restarted in 2023, '24, but in Superior for -- sorry, in Toledo, we had a chance to take the east side of the plant down the big units and the big money making units that we had a chance to get into for the first time were the isocracker, the crude unit, the reformer.

I got inside the sulfur systems, the back tower, small cokers. The hydrogen plants and the flare. So those are pretty significant assets. And when we got inside them, we didn't find a significant amount of fund work, which is always a good thing. But the improvements that you make on that and getting everything clean dusted and gives you a much better confidence that you can continue to run those kind of assets. The reliability rates that we're looking for. So we were pleasantly surprised in the turnaround by what we didn't find and we look forward to a good clean run in Toledo.

Our next question will come from the line of Greg Pardy from RBC Capital Markets.

Jon, maybe just to switch into Asia for a minute. Liwan, Indonesia, as I sort of think about those assets. Liwan is not oil price driven. It's a good field, reduces your breakeven, but just curious how you sort of think about those two assets and how they fit in the portfolio long term.

The way I think of both of them, Greg, is we have real competency inside our footprint, both in Asia and Indonesia. In Indonesia, we're a non-operated party with 40%. In the South China Sea, we operate the deepwater. But I think as you pointed out, these assets throw out a significant amount of free cash flow. So it's fixed price gas plus we get liquids. We produce that gas where we get about a $12 realization for, we produce the gas for about $1 -- it's got very minimal capital requirements, sustaining capital requirements and the fiscal terms are actually quite good in terms of royalties and taxes.

So our strategic bent on those has really been to operate well and harvest cash from them. And I think, as you know, they kind of generate about $1 billion of free cash flow every year. And our goal there is really to try and extend the contractual terms around the gas sales and get as much free cash flow as we can out of those assets going forward. So it's kind of a harvest strategy today with an idea that we've got some contractual optimization to do it through time.

And just a quick one for Kam. I mean the working capital tailwind was huge in the quarter. Should we expect much of that to reverse in 3Q, 4Q? You think?

Greg, it's Kam. Well, I would say, number one, I think working capital is something we're always going to be focused on, making sure we minimize it to the best we can. I think the tailwinds you saw in the second quarter, a big chunk of it was driven by just the price movement we saw in the quarter. So there's probably about a $400 million or $500 million impact on working capital release we had as it relates to commodity price changes on our inventory balances.

And then the second piece I would say is there were some tax refunds that we were expecting that we were able to bring in the door through the second quarter that amounted to a couple of hundred million dollars. So I think the goal for us is to try to minimize any builds in working capital. I think, obviously, timing of production to sales, those types of things will always move around quarter-to-quarter.

But I think the goal is to try to maintain and minimize and keep working capital as low as possible. So I wouldn't expect -- you're going to continue to see fluctuations because of commodity prices, but I think we're going to try to minimize that as much as we can. And I think, obviously, this quarter, that release really helped us not just deleverage, but also continue on a fairly robust shareholder return program through the quarter.

Next question will come from the line of Neil Mehta from Goldman Sachs.

You've been always very transparent about your perspective around M&A and have a long history of doing really good M&A, including the Husky deal. And then certainly, that's been a lot of the investor focus and attention around certain assets. And just your perspective on whatever you can say, whatever comments you would make about M&A strategy and how do you think about a potential bolt-on deal?

I don't think anything has changed in the way that we look at M&A. We have a portfolio that we quite like. We don't see any holes inside that portfolio. And as it relates to capital allocation, inorganic and organic opportunities need to compete. So nothing has really changed over the course of our tenure in terms of the way we look at M&A. And Neil, if you're thinking about a particular M&A piece, we're obviously not going to comment on that.

And we'll look -- we'll just keep our eyes open, then why don't we turn over to the operations here and talk about West White Rose, the concrete gravity structure was -- is a big deal, getting that on. And just talk about now you're moving into hookup and commissioning. So what are the gating items? And remind us again what that translates to from a free cash flow perspective.

Yes. So the last couple of years, starting with your free cash flow question, we've been investing about $800-plus million a year into that project. And that's all going to kind of flip over and generate about $800 million of free cash flow using kind of a $60 WTI, $63 Brent pricing when we reach full production in '27 -- or sorry, '28, '29 time frame. So it's a huge change in terms of cash flow generation versus cash flow consumption that we're really excited about. You're absolutely right. It's a huge step for us to get this CGS on the seabed floor, and this was done with precision. It was done really, really well. And as I mentioned in my call notes well ahead of schedule.

And I'm always amazed at our technical people in this company, whether it's in oil sands or whether it's in the Offshore or even in the projects group, what they're able to do. And getting the topsides made it up with the gravity-based structure as seamlessly as we did and with the precision that's involved was a real feat for this company and a real credit to those people.

So the kind of -- if you're kind of looking at critical path now, the piece of commissioning that's on the critical path is getting the topsides welded to the gravity-based structure. It's a huge effort, and that will get underway in short order. And we anticipate the entire commissioning and hookup schedule to be about 3 months. And then prior to the end of the year, we will start drilling our first well at the West White Rose project with first oil expected in early Q2 2026.

Our next question will come from the line of Patrick O'Rourke from ATB Capital Markets.

Just looking here, you're able to improve the outlook for the operating costs in the Canadian downstream unit with this update to guidance here. Wondering what the key drivers are here is that utilization? Is it reliability enhancement and margin capture? Or how much of that really came down to lower than anticipated gas prices in the Western Canadian Sedimentary Basin.

Yes. It's all of the above, Patrick. Any time you're trying to take costs out of our refining business and get unit cost down. Obviously, you're looking at the denominator as well as the numerator of the equation and getting good production on the top line is a big help. And when we ran those the upgrader and the refinery at the levels we did, you're going to see a consequence on your unit cost on the output of that equation.

One of the things I'd tell you is I think Eric and his team, and I couldn't be more proud of these guys, not just in Lloydminster, but also in our operated refineries in PADD 2 have been grinding out costs over the last number of quarters. And there, they're kind of getting after this in a very tactical and in a very meaningful way. And what we've seen over the quarters is a continued reduction in not just the absolute spend. But as you get that better reliability and you're not spending as much on maintenance and you're getting the volumes that come through, it shows up in the numerator and the denominator of that equation.

This is really blocking and tackling and this is getting under the covers of the business operating in a very deliberate and tactical way. And we think we've got more to come. So we're on a journey as it relates to unit costs and -- these guys have been on it, and they continue to stay on it, driving that kind of performance. As it relates to energy and in particular, in Lloydminster, there's no doubt we benefit from reduced gas costs and reduced electricity prices. But the same principles apply. You're still trying to minimize the amount of gas you use and minimize the amount of electricity is and use it as well as possible. So -- all I'd say is this is really blocking and tackling 101, and Eric and his team have been all over this for some time, and we're seeing the results now.

And then I was going to ask about West White Rose, but I hope it was pretty comprehensive there. So I'm just going to switch back to the U.S. downstream and maybe as it relates to my last question. How low do you think you could get the operating costs there, what's -- if you could quantify the opportunity on a per unit basis. And then what's really -- when you think about the driver of incremental margin there between market capture, lower cost product slate optimization, what's really going to be the biggest driver of margin as we roll into the next 12 months where you don't have the same level of major turnaround activity that you've had through this quarter?

So there's always 3 drivers of margin in a refinery. One is you got to get the crude slate right, and I think we do a pretty good job of that. Differentials have been very tight as Differentials or if Differentials widen, we would capture more of that in our Downstream and that's kind of a one-to-one relationship and the upgrader. And at Toledo and Superior in particular, we do have a pretty high diet of heavy oil. So as the Differentials widen, you'll see margin capture in those 3 assets, in particular, those 4, if you include the Lloyd refinery increase. We have a lot of work we're doing on the product side.

So product placement is another area where you can drive additional value and additional margin capture. And we've opened up the dock at Toledo. We think that's a very strategic asset. We continue to increase our terminal positions, not just in PADD 2, but we opened an asphalt refinery in PADD 4 recently. That was part of our disclosure in the prior call. And we work that piece of it every day, so the commercial piece of the business works on it.

As it relates to unit costs, we've been pretty clear that we're not competitive on unit cost, and we need to get our unit costs down through time. We're going to do this in a smart way. We're not going to jeopardize reliability or safety to get there. But the trajectory that you've kind of seen that business on, I would expect it to continue through time. But we think there's probably another $2 per barrel that we can get out of our U.S. refining assets through time.

But that's going to be -- a journey is going to be something that we're going to be very deliberate about. And as I said before, we're not going to compromise reliability and safety, which are always kind of job one and running their refineries.

Our next question will come from the line of Manav Gupta from UBS.

I just wanted to understand this a little bit. You were down for about a week because of the fire and then you probably took a week to ramp back up. And so just trying to understand the opportunity barrel that was lost. So if these fires would not have happened at all? What would be a good number in terms of the volume that would be higher for the quarter versus when because of these fires?

Yes. So on Christina, I think that's the asset you're talking about. We were down for about 4 days. And then we ramped up to full production over the coming weeks. So about 11 days in total to go from a standing start to 250,000 barrels a day. And then adding up the barrels that we lost, it's about 2 million barrels. So if that were the number that you were going to use as the kind of LPO or lost profit opportunity, I think that would be a good number to put in your model.

That's exactly what I was looking for. And my second question to you was you generally have a very informed view on the differential, especially on the heavy side. So multiple things going on here, OPEC raising some volumes, then Chevron getting to drill back, but then very high U.S. utilization and desire for heavy barrels. So like what's your outlook for the heavy light differential into the year-end?

Well, Geoff Murray gets paid to provide insights on these kind of questions. Maybe I'll turn it over to him.

Sure thing, Jon. Manav, there's sort of two parts to that. There'd be what is the differential in Alberta and what is the differential in the U.S. Gulf Coast. And I think you were referencing a lot of global things that impact that U.S. Gulf Coast Differential. We've seen that be quite narrow compared to history, sort of a minus 2, minus 3 to WTI, and that's been obviously appropriate for where things have been.

Looking forward, I think the question you need to ask yourself and answer is if there is increased OPEC plus production, when does that come? And how much is it? Because much of that volume would be medium sour, which tends to have an impact on the dip in the Gulf. I wouldn't see that going anywhere further past what is more a normal long-run average of maybe $2 wider, minus, minus 3, minus 4, minus 5. That tends to percolate back into Alberta.

And then I would say on Alberta, it's the same thing I probably said the last couple of quarters, TMX is here and TMX is working and TMX is doing what it's supposed to do, which is to maintain the Alberta differential quite tight to the Gulf Coast. And I think we would see that persist definitely through the fourth quarter.

At this time, we have no questions in the queue. [Operator Instructions] Our next question will come from the line of [ Emma Graney ] from The Globe and Mail.

I'm just curious to get your take on the new policy environment that we're seeing from Ottawa, Bill C-5 and that kind of thing. And where you think this might set Canada going forward, particularly with Cenovus and opportunities?

Okay. Well, thanks for your question. I'm going to turn this over to Jeff Lawson to give you an answer.

I'll give you a bit of an answer. I think the federal liberal government has been the most constructive with us and our industry than we've seen in the course of the past decade. So they're out here often, they're visiting and they're really trying to make an effort, I think, to improve the Canadian economy. So those are bringing in on major projects. I think they're well intentioned. They've got a lot of work to do with industry and with the provinces to get things done.

And what we say is perfectly consistent. We love the notion of new projects and strengthening the Canadian economy. At the same time, we need to take a step back and say, what's precluding us from proceeding with these things. And really, there's a lot of regulatory hurdles. So there's a lot of talk about an energy corridor or a new pipe to the coast, we still have a tanker ban an emissions cap. Methane regulations, and industrial carbon tax that isn't competitive with other jurisdictions. So those are things we need to see, we think, change for major projects to occur.

And I'd say the good thing is that the governments are all engaging on those discussions and being thoughtful about what we're putting forth to them. So I'm cautiously optimistic we're moving in the right direction, but we've got a ways to go.

The other thing I was going to ask is basically when you come to that policy kind of change, I know you don't want to weigh in on M&A and MEG specifically, but I'm curious whether this broader policy change kind of shifts anything in the energy environment and infrastructure environment when it comes to mergers and acquisitions.

I think it shifts everything positively. I think just going back over the past decade, we've seen a flight of foreign direct investment in this country in all sectors because we have uncertainty of regulation. We have burdensome regulations. There are long time frames to get projects done, which are not competitive with other places. So if we become more competitive, we'll become more attractive to foreign capital.

We'll see higher valuations in various industries in different companies and would be more inclined to pursue organic and inorganic growth. So we'll have the funding to pursue organic growth, and we'll also have the funding and backing everyone will to pursue more M&A initiatives instead of simply returning capital to shareholders. So I think it's a virtuous circle, and it would drive more M&A.

There are no further questions registered at this time. I would now like to turn the meeting over to Mr. Jon McKenzie.

Great. And thanks, everybody, for their questions today and for those of you online, we absolutely appreciate your interest in the company, and please enjoy a great day. Thank you.

This concludes today's program. You may all disconnect. Thank you for participating in today's conference, and have a great.