AltaGas Aktie

Good afternoon. I'm Pentti Karkkainen, Chair of the Board at AltaGas. On behalf of the Board, it's my pleasure to welcome you to AltaGas' 2026 Annual Meeting of Shareholders. Thank you for joining us. Before we get started, I want to introduce today's speakers and provide an overview of the meeting format. We'll start with Loren Kimi, Director of HR Operations and Strategy, who will provide a land acknowledgment. Then I'll be joined by Jimmi Duce, Vice President and Corporate Secretary, who will assist me in providing an overview of the conduct of the meeting.

We'll then have the formal portion of the meeting. Once the formal meeting is complete, I will provide some concluding remarks and then turn the meeting over to Vern Yu, President and Chief Executive Officer, to provide a short corporate update. Following the update, we'll have Sean Brown, Executive Vice President and Chief Financial Officer, join us on the stage for a Q&A session to close the event. Other members of our Board and management team are joining us virtually.

And with that, I will turn it over to Lauren.

Thanks, Pentti. We are speaking to you today from Downtown Calgary, -- while we meet on a virtual platform, this land is deeply rooted in the histories and cultures of many diverse indigenous peoples and communities. Today, we recognize that we are on the traditional territories of Treaty 7 signatories including the Saga nation, the Pagani nation, Tigana Nation, the ES Custoniaacoda nation comprising the Chiniki, Barspa and Goodstony and the people of Stina Nation. Calgary is also home to the OTPemsakMeiti government of the Mansion within a strict 6. .

AltaGas acknowledges indigenous peoples as the traditional stewards of the lands on which we operate. We affirm our commitment to the journey of reconciliation through shared understanding, respectful engagement collaboration. We are grateful for the land and for the enduring contributions of indigenous peoples and we remain committed to building and maintaining relationships that support strong communities, shared prosperity and long-term well-being. As a member of the AltaGas community, I come with deep respect for this land that I am on today, and for the people who have and do reside here. I pledge to respect and honor this land and its first inhabitants, acknowledging their enduring presence and contributions to our collective future. It is my honor to continue to learn and deepen my understanding of local indigenous peoples and their cultures.

Thank you, Lauren, and thank you to our indigenous partners in the local communities where we work and call home. Before we start the formal meeting, I will ask our Corporate Secretary to address a few housekeeping matters related to the formal proceeds. Jimmy, over to you.

Thank you, Pete. Good afternoon, everyone. As is the case with our in-person shareholder meetings, only shareholders of record at the close of business on the record date of March 5, 2026, and their duly appointed proxy holders may ask questions and vote on meeting matters. If you wish to ask a question, simply click on the messaging icon and type your question in the chat box at the bottom of the messaging screen then the aero icon to submit. Your questions will be put in the queue and addressed at the appropriate moment during the meeting.

Questions about meeting business will be answered during the formal portion of the meeting. Other questions not focused on the formal meeting will be brought forward during the Q&A session. We encourage you to submit your questions early. And if your question relates to an item of business to specify the item to which it relates at the start of your question. When reading a question, I will first note the name of the registered shareholder or proxy holder submitting the question. To ensure all questions are addressed. Questions of a similar nature may be answered only once.

Any questions we are unable to address during the meeting will be referred to our Investor Relations team for follow-up. To assist us in doing so, please include your e-mail address or phone number with your question. All items for shareholder approval today will be conducted by poll online through the Lumi platform and must be approved by a majority of the votes cast. All items being pulled will appear on your screen at once. As in prior years, significant voting occurred by proxy before the meeting and the response was positive. Thank you to our shareholders who have voted in advance. We have received your votes and your votes have been included in the final count. You do not need to vote again today. any vote you cast at this meeting will revoke your prior vote.

If you plan to vote today, you may choose to vote on the resolutions immediately when they appear on your screen or wait to cast your vote until the conclusion of discussion. To vote, simply click on your choice, or withhold or against as applicable. A confirmation message will appear to show that your vote has been received. To change your vote, simply change your selection. If you wish to cancel your vote, press cancel. If you do not submit a vote, the vote will be shown as abstained. The votes you submitted on each polling item when the poll closes will be recorded. Totals in favor or against or withheld for each resolution item will be tallied by the scrutineer once the polls close and the terrible report on the outcome of all motions at the end of the formal meeting.

For meeting efficiency, the chair will make the motions, and I will second. We are both shareholders of AltaGas. As noted in the information circular, the Board amends voting in favor of each of the resolutions being tabled. With the housekeeping matters taken care of, I will turn the meeting back to the Chair.

Thank you, Jimmi. In accordance with our bylaws, I will chair today's meeting, and Jimmy will serve as Secretary. I also appoint Christopher Parsons, who joins us today as a representative of our registrar and transfer agent, Computershare Trust Company of Canada to act as scrutineer for the meeting. I now call the meeting to order. I have been advised by Computershare that the notice of meeting and meeting materials were due to deliver to shareholders and that a quorum is present. Accordingly, I declare that the meeting has been duly called and is properly constituted for the transaction of business.

Computershare statutory declaration of mailing and the scrutineer's report on attendance will be filed by the Secretary with the minutes of this meeting. I now declare the polls open on all resolutions. Each person entitled to vote shall see voting choices displayed on their screen. As a reminder, you may vote on the resolutions immediately or wait to cast your vote following discussions on the matter. We will now commence with the business of the meeting. The agenda is as set forth in the notice of meeting being the presentation of financial statements, the appointment of the auditor, the election of directors, the advisory vote on executive compensation.

Let's begin with the first item of business. The consolidated financial statements of AltaGas for the year ended December 31, 2025, Management's Discussion and Analysis and the auditor's report thereon have been provided to shareholders. They are available on AltaGas' profile on SEDAR plus and on AltaGas' website in accordance notice and access provisions. No action is required by shareholders on this idle. The next item of business is to vote on the appointment of Ernst & Young LLP as the auditor of AltaGas to hold office until the next annual meeting. I move that Ernst & Young LLP be appointed as the Auto of AltaGas until the next Annual Meeting of Shareholders or until the successor is appointed and that their remuneration be fixed by the directors of AltaGas.

Mr. Chair, I second the motion. Thank you. You've heard the motion and is now open for discussion.

Jimmy, have we received any questions on this motion from shareholders?

Mr. Chair, we have received no questions on this motion.

Thank you, Jimmy. We will proceed with the next item on the agenda. The next item of business is the election of directors. The Board of Directors of AltaGas has fixed the number of directors to be elected at the meeting at 11. As noted in the information circular, our bylaws contain advanced notice provisions, which provide a procedure to be followed for the nomination of directors at meetings of shareholders. No other nominations were received.

Therefore, the only individuals entitled to be nominated as directors at this meeting are the individuals named as nominees in AltaGas' information circular. In accordance with our majority voting policy, you are being asked to vote for each director separately. Jimmy, can you please read the names of the 11 directors nominees set out in AltaGas' information circular who are standing for election.

Mr. Chair, the Director nominees are as follows: William Bullet Jr., Victoria Calvert, David Cornhill, Jonel Duplantier, Derek Evans, Cynthia Johnston, Angela Lacaze, Peticarkanan, Philip Nowell, Nancy Tower and Vern U. Each of the nominees has consented to act as a director of AltaGas until the next annual meeting or until their successor is duly elected or appointed.

Thank you, Jimmi. The nominees bring a diverse mix of experience, skills and perspectives to the board. The skills and attributes of the nominees are set out in the information circular. All the nominees currently sit on our board, though William Bullet Jr. will be standing for election for the first time today. Bill Bullock was appointed to the Board in October. Bill is an industry veteran and distinguished leader in the sector with nearly 4 decades of experience working across complex global operations throughout different regulatory jurisdictions and across the upstream, midstream, and downstream energy markets.

Mr. Bullock brings a wealth of knowledge and experience to our board. We believe his strategic mindset and cousin value creation will benefit our organization and shareholders over the long term. I and the balance of the Board and executive look forward to working with Bill. Welcome, Bill. With, I now move that the individuals nominated as directors as listed by the secretary be elected as directors of AltaGas to hold office until the next Annual Meeting of Shareholders or until they cease to be directed by operation of law or until their resignation becomes effective.

Mr. Chair, I second the motion. .

Thank you. You've heard the motion and is now open for discussion. Jimmy, have we received any questions on this motion from shareholders?

Mr. Chair, we have received no questions on this motion. .

Thank you, Jimmy. We will proceed with the next item on the agenda. The final item of business is the consideration of AltaGas' approach to executive compensation. This is an advisory vote, so the results will not be binding, but the Board will take the results into consideration in its ongoing review of executive compensation. I move to accept on an advisory basis and not to diminish the roles and responsibilities of the Board of Directors, all together approach to executive compensation, as disclosed in AltaGas' management information circular dated March 5, 2026.

Mr. Chair, I second the motion. .

You have heard the motion, and it is now open for discussion. Jimmy, have we received any questions on this motion from shareholders?

Mr. Chair, we have received no questions on this motion. .

Thank you, Jimmi. That was the final agenda item. For those of you who have not yet cast your votes, please do so now, and I will pause briefly before closing the polls. Thank you. The polls are now closed. We will take another moment to let the scrutineer finish tabulating.

Mr. Chair, we have now received the preliminary results from the scrutineer, and I can advise that each of the motions has passed by a majority of the votes cast.

Thank you, Jimmi, and thank you to the scrutineer. On that basis, I declare that all motions have been carried. Final voting results will be published on SEDAR plus tomorrow morning. As there is no further business, I now declare the meeting terminated. Thank you all our shareholders for participating in the annual meeting, either by voting in advance or attending virtually and voting live today, and thank you for your ongoing support of AltaGas. Prior to turning the meeting over to Vern Yu, I'd like to draw your attention to our advisory statement and share a few concluding remarks. Please take a moment to review the posted advisory statement regarding forward-looking information and non-GAAP measures.

Within our corporate update, we may make forward-looking statements, which involve certain assumptions, and we have inherent risks and uncertainties. Actual results could differ from these statements. We may also make reference to certain financial measures that do not have a standardized in prescribed by U.S. GAAP. As I reflect on the past year, I am proud of the progress AltaGas has made in advancing our strategic priorities, strengthening our asset base and continuing to deliver affordable and viable energy to the communities we serve.

On behalf of the Board, I would like to thank the AltaGas leadership team and employees for their continued focus disciplined execution and commitment to safety and operational excellence. I would also like to acknowledge rights holders, indigenous and local communities and our stakeholders and partners for their ongoing engagement and trust. As I conclude my final Annual Shareholders Meeting as Board Chair, I'd like to thank my fellow directors for their stewardship down counsel and support over the past 7 years and their continued commitment to AltaGas. Serving as a Board chair has been a privilege and I'm grateful for the opportunity to have worked alongside such a dedicated group.

I am also looking forward to continuing to serve as a Board member as I'm extremely excited in the company's future and very pleased to support our incoming Board Chair, Derek Evans, Derek is a highly respected energy industry leader, and the Board looks forward to his leadership as AltaGas continues to execute its long-term strategy. With that, I'll turn it over to over.

Good afternoon, and thank you for joining us today. On behalf of the Board and the management team, thank you for your continued support and confidence in AltaGas. I'd also like to recognize our employees across North America. We deliver energy to improve lives and create opportunity. We focus on safety, operational excellence and disciplined execution. And this is the foundation of our strong 2025 results. To recognize that commitment and the values that unite us, we'd like to share a brief video that highlights what makes AltaGas such a remarkable organization.

[Presentation]

And competitively priced energy, connecting our customers to markets across North America and globally through our midstream and utes businesses with Pipestone 2 entering service in 2025 and DMS reaching a positive final investment decision, we advanced critical midstream energy in structure that stores, processes and transport liquid petroleum gas for over 70 Canadian LPG producers and aggregators providing the energy the world needs safely and affordable through our West Coast open access export we supplied Canadian PG to key markets in Asia unique business model combines our midstream advantages with the steady returns from our utilities, the rate regulated natural gas distribution and storage infrastructure.

Our utilities business 1.6 million residential, commercial and industrial customers powering their homes and businesses with our strongest safety performance record, we continue to execute on our pipeline modernization program. We also take great pride in our partnerships. We're working with our indigenous partners, communities and other key stakeholders to create shared long-term value that is anchored in local priorities and built on trust. Our story is strong. We're focused on delivering exceptional results for each other, our communities, customers and shareholders today and into the future.

2025 was a strong year at AltaGas. We continue to drive value for our shareholders and demonstrated strong execution of our strategic priorities which strengthened our foundation for long-term growth. Safety has always been our most important core value. And thanks to the great work of our employees and contractors we significantly improved our safety performance in 2025. In fact, we reduced total recordable injury frequency across the enterprise, and I'm proud to share that SEMCO achieved top quartile performance in its peer group.

Moving on to our financial results. Last year, we delivered normalized EBITDA of approximately $1.86 billion, which was in the top end of our guidance range and supports our 6% 5-year compound annual growth rate. Our normalized earnings per share came in at $2.23 and also landing in the upper half of our guidance range. We enhanced our earnings quality by prioritizing stable long-term cash flows. We did this by derisking our global export platform through long-term tolling agreements. We also advanced utilities asset modernization regulatory approvals, all of which strengthened our risk profile.

Happy to share that we advanced key growth projects, including the commissioning of Pipestone 2. We also made significant construction progress at Reef and continue to make significant investments in the modernization programs at our utilities. We reached positive FID on reef Optimization 1, the RIPET methanol removal project, Dimsdale expansions Phases 1 and 2 and the KenaConnector pipeline in Michigan. In 2025, we optimized our asset base by delivering record annual global export volumes of over 126,000 barrels a day of propane and butane to Asia and we saw record throughput volumes at North Pine and Pipestone.

We ended 2025 on strong financial footing with adjusted net debt to normalized EBITDA of 4.7x, achieving our leverage target and we received positive revisions to our credit outlook -- these results translated into a 29% total shareholder return in 2025. And and a total shareholder return CAGR of 22% over the last 5 years. This significantly outperforms our peers and reflects strong investor confidence in AltaGas. Turning to Reef. Our new LPG export facility in Prince Rupert, I'm happy to share that Reef Phase 1 is approximately 75% complete with all modules on site. -- placement of the remaining 2 jetty spans is about to be completed, and construction of the final phase of the railroad utility quarter is about to start construction.

The project currently sits with roughly 90% of its total capital cost incurred or committed and 80% of these costs are under fixed-price EPC contracts. I'd like to pause here to recognize that over 1.4 million hours have been worked on reef without serious injury. Kudos to the team in achieving these great results. Reef Optimization 1 is in its early days of construction and will add another 30,000 barrels a day of propane export capacity, which is also under long-term tolling contracts. We continue to advance in our midstream business. Currently, our sanctioned projects include our Dimsdale expansion, which will add 36 Bcf of gas storage.

This project is backed by long-term take-or-pay contracts. At RIPET, our methanol removal project improves propane specs and helps us expand into new markets like China. At Reef, we're also assessing further LPG exports, including the potential for exporting ethane. We are advancing engineering and cost estimates for reef optimization; two, which is anticipated to add another 60,000 barrels a day of LPG export capacity. And I'm happy to share that we now have received permits required to start construction. Looking ahead, we also expect to see our existing facilities in the BC and Alberta Montney to undergoing expansion.

Our growth opportunities in our utilities business are also strong. Construction of the Q1 connector begins this spring. The construction materials are arriving on site, and we've fully secured the right of way. Our regulators have approved USD 1.5 billion organization spending across our 4 jurisdictions, which enhances the safety and reliability of our systems. In terms of data centers, we've now completed multiple FEED studies and started gas connection construction for Phase 1 of a 24-megawatt Maryland facility, which project completion is anticipated by year-end 2026. The -- we also recently announced a second data center project in Virginia.

Modernization programs and customer additions will support rate base growth of around 8% per year over the next 5 years. Data center capital has the potential to add another 1% per year to that healthy 8% rate base CAGR. And -- looking at our 2026 strategic priorities, we're focused on delivering long-term value for our shareholders with today's geopolitical tensions, economic uncertainty and market volatility and energy security and access to global markets has never been more important. AltaGas is well positioned with a diversified portfolio of regulated utilities and midstream assets. that will continue to provide stability and flexibility for our customers and stakeholders in the long term.

We believe that delivering on our strategic priorities in 2026 will only enhance our long-term competitive position. Our value proposition is clear. we have a low-risk, high-quality infrastructure platform with stable, growing cash flows. Global demand for reliable and affordable energy supports our growth outlook. -- and we anticipate our organic growth backlog to drive 5% to 7% per year of growth through 2030. Finally, we're blessed to have ample investment capacity to fund all of this organic growth. noting that we will be disciplined allocators of capital, and we will continue to live within our balance sheet guardrails. Thank you for your ongoing trust and support. We're looking forward to 2026 and beyond.

Thank you, Vern. We are pleased to have Sean Brown, AltaGas CFO, join us on stage and open the floor for questions. Jimmy, are there any questions from shareholders?

We have received no questions.

Thank you, Jimmy. With that, we've reached the end of today's question-and-answer session. Should you have any additional questions throughout the year. We encourage you to contact our Investor Relations team or for more governance-related matters, the Board in accordance with AltaGas' shareholder engagement policy. Before I conclude, I'd like to thank team across North America for their continued focus on executing our strategic priorities safely, responsibly and with discipline. Your work is essential to our success.

I'm very grateful for your commitment to the communities we serve, including rights holders and digital communities and our broader group of stakeholders -- thank you for your collaboration and trust as we work together to help meet energy needs today and into the future. To our shareholders, thank you again for joining us today and your continued confidence and investment in AltaGas. We value support and remain focused on delivering long-term value.

Finally, I'd like to thank [indiscernible] for his outstanding leadership and stewardship as Board Chair. I'm glad to have your continued support on the Board and look forward to working closely with Derek Evans in his new role as Board Chair. Thank you for your participation today. This concludes AltaGas' 2026 and Annual Meeting of Shareholders.

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas First Quarter 2020 Financial Results. My name is Julie, and I will be your operator for today's call.

[Operator Instructions]

As a reminder this conference call is being broadcast live on the Internet and recorded. I would now like to turn the conference over to Aaron Swanson Vice President, Investor Relations. Please go ahead.

Good morning, and thank you for joining AltaGas; First Quarter 2026 Results Conference Call. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website. Speakers this morning will be Vernon Yu, President and Chief Executive Officer; and Sean Brown, Executive Vice President and Chief Financial Officer. We're also joined by Randy Toone, President of Midstream; Blue Jenkins, President of Utilities; and Jon Morrison, Senior Vice President of Corporate Development and Investor Relations.

We will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 in the presentation. Prepared remarks will be followed by a question-and-answer session.

I will now turn the call over to Vernon.

Thanks, Aaron. Good morning. Thanks for joining our Q1 results conference call. I'm going to kick things off by reviewing highlights from the quarter, including our strong financial and operating performance. Then I'll provide an update on our growth projects, review our backlog of organic growth opportunities and I'll close by discussing the evolving global LPG market. After that, Sean will cover our financial results and provide an update on our 2026 outlook.

Let's start on Slide 4. We had record financial results in Q1 reflecting strong performance from both Midstream and Utilities, which benefited from constructive energy fundamentals. We delivered normalized EBITDA of $818 million and normalized earnings per share of $1.33. These results exceeded our expectations and put us in a very strong position for the balance of the year.

As a result, we are anticipating 2026 results to land at the top end of our guidance range with the potential to exceed the upper end of the range, if we continue to see strength in the LPG export market. Q1 financial performance improved our balance sheet with leverage closing at 4.4x, down from 4.7x at year-end, and slightly below our 4.5x to 5x target range.

Operationally, our export terminals averaged approximately 125,000 barrels per day. Midstream throughput continues to see strong growth with our Montney infrastructure realizing 14% year-over-year growth in volumes, which included a full quarter of volumes from Pipestone II. At our Utilities business colder-than-normal weather supported customer demand. Heating degree days were 5% above normal at DC and 10% above last year's levels.

We continue to advance several strategic initiatives, including taking delivery of a new VLGC Time Charter, further extending our pipeline modernization programs, and the execution of a second behind the meter data center connection agreement.

Let's move to our growth projects, and we'll start with REEF on Slide 5. Construction on REEF Phase 1 and optimization 1 continues to progress well. REEF Phase 1 is now roughly 75% complete with all major modules on site. Placement of the 2 remaining Jetty's fans will be done shortly, and construction of the final phase of the railroad utility corridor is about to kick off. Notably, over 1.4 million hours have been worked on REEF without serious injury. The project currently has about 90% of its total capital costs incurred or committed and 80% of these costs are under fixed price EPC contracts.

REEF optimization in is in its early days of construction, and we continue to expect completion in the second half of 2027. Optimization 1 is backed off by long-term commercial agreements and will add 30,000 barrels per day of propane export capacity. We also continue to advance engineering and costing for REEF Optimization 2, another brownfield expansion that will bring 60,000 barrels per day of incremental Canadian export capacity. We have now received all the permits we require to start construction.

Slide 6 shows the recent progress that we made at REEF. You can see we're nearing completion of the onshore construction for the facility, and Jetty construction continues to progress on plan. At completion REEF will nearly double AltaGas' global export capacity and will substantially increase Canadian trade exports to Asia. Slide 7 sets out our organic project backlog, utilities modernization, customer ads, data centers and large volume commercial opportunities and utilities. Global export, extraction and fractionation expansions, gas storage and gathering and processing projects in Midstream.

Slide 8 highlights our system modernization runway across D.C., Maryland, Virginia and Michigan. We have more than 5,000 miles of pre-1970s type that will need to be replaced to enhance safety and reliability. This pipe replacement gives us decades of system modernization investment opportunities. To facilitate that, we have USD 1.5 billion modernization programs that have been approved by regulators across our 4 jurisdictions.

Modernization capital and normal course customers allow us to grow rate base at an average of 8% per year while improving the safety and reliability of our system. Each mile we replace reduces the risk of leaks, service destructions, operating costs and safety incidents for the communities we serve. We show our robust investment capacity on flying on. This allows us to invest $5 billion over the next 3 years while remaining within our target credit metrics and $3.5 billion of debt will be allocated to organic growth.

These investments support our long-term earnings and dividend growth outlook of 5% to 7% per year, with that growth being backed off by low-risk cost of service or take-or-pay cash flows.

Let's move to Slide 10, where we shift to the global LPG market. The disruption to Middle East supply is expected to have lasting impacts. At its peak, 1.3 million barrels per day of LPG supply was offline with the closure of the Strait of Hormuz. This has doubled spot propane spreads from pre-conflict levels. Based on the damages to key Middle East LPG export infrastructure, a significant portion of this production could be offline for an extended period of time. This supply disruption has driven more conversations with our Asian customers who are now placing increased value on energy security, which highlights Canada as one of the most reliable sources of global LPG supply.

A great example is what we are seeing in China, where Canada's share of China's total propane imports has grown from 0% to over 11% in the past year. The initial shift happened after U.S. tariffs were implemented as Canadian LPG replaced U.S. LPG supply, demand for Canadian LPG in China was then accelerated with the Middle Eastern supply disruption.

Turning to Slide 11. We highlight some of the shifting trade dynamics for LPGs across Asia. Overall, we're seeing strong demand across our traditional Asian markets, including China, South Korea and Japan, where AltaGas represented approximately 6% of Canada's total national trade value in Q1. Since the onset of the conflict in Iran, we've seen incremental demand from markets that have historically relied on Middle Eastern supply. This includes multiple countries in Southeast Asia.

In fact, we recently delivered our first cargo in the Indonesia. We're also advancing discussions in South Asia, where customers are looking for long-term supply diversification opportunities. This growing and diversified demand for Canadian LPGs reinforces the value of AltaGas' global export platform.

Finally, turning to Slide 12. We reiterate our strategic priorities. We remain focused on growing, derisking and strengthening the enterprise. We have materially advanced our key growth projects, and we've added several high-quality projects through our growth backlog that enhances our long-term outlook.

I'll now turn it over to Sean to walk through our financial results.

Thanks, Vernon, and good morning, everyone. As Vernon noted, a fantastic quarter and a very strong start to the year. with consolidated normalized EBITDA of $818 million, a 19% increase from last year and a new quarterly record for the company. For today's call, I'll start by providing a detailed review of performance across our utilities and midstream segments, touch on the strength of our balance sheet and finish with our 2026 outlook.

Turning to Slide 13. The Utility segment delivered normalized EBITDA of $555 million, an 11% increase year-over-year. These strong results were driven by incremental revenue from positive rate case outcomes in D.C. and new interim rates in Virginia as well as continued modernization investments and stronger asset optimization. The benefits of which we share with our customers. The segment also benefited from a $35 million gain on the partial settlement of WGL's postretirement pension plan. These results were partially offset by lower retail performance and higher G&A expenses, with the latter related to employee incentive plans linked to our share price.

During the quarter, we deployed $146 million of capital in the utility segment, including $56 million towards modernization programs and $23 million on new growth initiatives. These investments are focused on delivering long-term safety and reliability while extending our network to serve our expanding customer base. Capital spending plans in the quarter were partially curtailed by cold weather limiting construction activity, which we expect will catch up as the year progresses.

In the quarter, we signed our second data center connection agreement to provide natural gas for backup power generation to an existing 15-megawatt data center in Virginia. Both of our announced data center projects have the potential for larger follow-on phases and we continue to advance various opportunities across all of our jurisdictions.

Turning to Slide 14. We highlight our ongoing regulatory initiatives with active rate cases in Maryland, Virginia and Michigan. During the quarter, we filed a rate case in Michigan, seeking USD 61 million in incremental revenue, a 10.75% allowed ROE and a weather normalization adjustment mechanism consistent with our derisking priority. In connection with the Michigan rate case, we also filed a 5-year USD 284 million modernization program extension.

We continue to engage constructively with regulators and other stakeholders with a focus on balancing customer affordability with the safe and reliable delivery of service.

Turning to Slide 15. Midstream delivered $273 million of normalized EBITDA and up 39% year-over-year and above our expectations entering the quarter. This segment's outperformance was primarily driven by our export platform, which grew volumes and delivered strong merchant margins. During the quarter, we exported nearly 125,000 barrels a day of LPGs across 20 VLGCs at our RIPET and Ferndale terminals with volumes up 5% year-over-year. We had 14 ships leave from RIPET, including 1 that shifted into the first quarter from late 2025. Thanks to continued operational and logistical execution, we exported over 80,000 barrels per day from RIPET during the quarter, a new record for the facility.

Utilization across our gas processing, fractionation and extraction assets was strong, with throughput up 9% year-over-year. This volume growth was led by our strong Montney footprint, where our strategically located assets provide a strong advantage to capture basin growth, driven by producers targeting liquids-rich formations across Western Canada. The quarter also included the first full quarter of operations at Pipestone II, which continues to perform well and is adding critical gas processing and liquids handling capacity in the Alberta, Montney.

Looking ahead, we are well hedged, but have some positive upside price exposure with approximately 82% of expected remaining 2026 global export volumes, either toll or financially hedged with an average FEI to North America spread of approximately USD 20 per barrel on nontoll volumes, while 18% of remaining volumes have open market pricing.

Despite the FDI curve remain in heavily backwardated, we are starting to see the back end of fire as the Middle East complex continues. In addition, our entire 2026 Baltic rate exposure is hedged through a combination of time charters, financial instruments and tolling arrangements. We also continue to manage frac spread exposure through our disciplined risk management program. Finishing up the discussion on our results. Performance in the Corporate and Other segment was consistent with the prior year with [ supply ] being relatively stable.

Turning to Slide 16. As Vernon mentioned, we are highlighting that we now expect to be towards the top end of our 2026 guidance range with the potential to exceed the upper end on continued strength in the LPG export market. This is driven by a strong first quarter in both the Midstream and utility segments and what we have been seeing in our export business through April. Given the outperformance is more weighted to our Midstream business, we have adjusted our expected EBITDA ranges for the year, with Midstream expected to contribute 44% to 48% of normalized EBITDA up from 42% to 46% previously.

As noted, if LPG export spreads continue to stay elevated, there is potential for us to exceed the top end of the current guidance range and we expect to update the market on this with our Q2 results at the end of July. As shown on Slide 17, we have increased our 2026 capital budget to $1.7 billion from $1.6 billion. This increase is driven primarily by the sanctioning of Dimsdale II during the quarter and improved visibility in key vendor milestone payments on project work.

As a reminder, the utilities capital is focused on modernization and system betterment to support safety, reliability and network efficiency and is expected to drive approximately a 10% year-over-year growth in rate base, while the Midstream capital is largely allocated to advancing REEF and the Dimsdale projects. With the increase in capital coming from the Midstream segment, we now expect to allocate 31% of capital Midstream and 65% of capital utilities with the balance allocated to the corporate segment.

Let's now turn to our balance sheet on Slide 18. We exited the quarter with a trailing 12-month adjusted net debt to normalized EBITDA ratio of 4.4x, modestly below our target range due to higher-than-expected EBITDA and our first quarter capital program being slightly below expectations due to cold weather limiting activity early in the year. With the increase in our 2026 capital program, and taking into account the seasonality of our business, we would expect our leverage metric to be within our 4.5 to 5x range when we exit 2026.

On Slide 19, we highlight AltaGas' established history of delivering per share growth across our earnings, EBITDA and dividends, which has resulted in significant outperformance in share price.

Lastly, on Slide 20, we highlight our attractive value proposition. Our low-risk infrastructure platform supports stable, growing earnings and cash flows underpinned by disciplined capital allocation and a robust organic growth pipeline.

With that, I'll turn it back to the operator for the Q&A session.

[Operator Instructions]

And your first question comes from Robert Catellier from CIBC Capital Markets.

Just a couple of questions on the state of the LPG market. Just curious what you're experiencing in terms of capturing premium pricing to spot prices and separately versus the forward curve. And happy to see the windfall profits, but obviously, we're more interested in seeing what the path is to future expansions given the increased demand that you outlined?

Rob, those are great questions. I think maybe just starting on the first one. What we're seeing in the physical market is similar to what you're seeing in the oil markets where the paper markets don't actually reflect pricing that you're seeing physically. So I think in the first quarter, we were seeing physical sales trade at a significant premium to FEI when historically, those physical sales would trade roughly at a very small premium or discount to FEI. So because of the lack of supply, you've seen physical transactions -- the pricing on physical transactions does not capture what's on the screen.

On the forward market, obviously, the curves moved up. It's obviously also highly backwardated. We continue to expect that, that backwardation will continue, but prices should remain high. As of right now, you're not seeing any LPG move through the strait. So the lack of supplies you're going to get more and more acute as we move forward here. And then finally, on your last question, I think all of this turmoil in the Middle East really highlights the value of secure and stable supply. Obviously, Canada has a big role to play in that. And we are very happy to note that we were able to get all of the construction permits we need for REEF Opti II. We're progressing our capital cost estimate and commercial conversations are more tolling there. So we expect to push that forward sometime later this year.

And then we're also working on seeing if we can do subsequent phases of REEF and the most advanced one that we're working on there is working on the potential to export ethane out of REEF, but that's got a longer gestation period. So I think we covered all your questions there. Rob?

Yes, that was very helpful. And then I just wondered if you could walk through your current outlook on the Montney and production outlook given currently elevated commodity pricing, the enhanced customer need for energy security and the recent Shell acquisition of ARC?

Rob, it's Randy Toone. Yes, we're seeing a lot of activity in the Montney. And you can see even with Shell coming back into Canada point significantly with the ARC acquisition, you can see that they really live in the Montney. We really think that with this acquisition, LNG 2 Phase II is likely to go ahead by the end of the year. And again, that's just going to enhance more Montney drilling. And with that, we'll just -- we see just more LPG production coming with that. So it really helps support our export position.

Your next question comes from Rob Hope from Scotiabank.

I want to take a look at the volumes for Q1 out of RIPET, 89,000 barrels a day is above nameplate. Acknowledging that 1 shift did kind of drift from Q4 into Q1. And can you speak to kind of what you think that facility could do in the near term if producers are willing to, we'll call it, expedite supply to the West Coast?

Randy again. the ability to move products through RIPET is really highly dependent on our service agreement we have with the terminal operator and right now, we have the ability to do 85,000 barrels a day on average through the year. And so that's our goal was to do at that average. And so we actually had a really good Q1, and we expect that to continue through the rest of the year. But our capacity there is 85,000 barrels a day.

Yes. Remember, Rob, in Q1, we had 1 vessel that was scheduled to be loaded in 2025 that slipped in the first couple of days of 2026. So that's why you're seeing us above that 85,000 barrels a day.

Appreciate that. And then maybe just thinking about risk mitigation and the hedging for the global offshore business for the rest of the year, you've locked in a good Q1, you're fairly well hedged for the rest of the year. If we take a look out to Q4, you're 73% hedged and told now are you willing to leave a little bit more open just given how backward dated the curve is? And also just given the premiums in the physical market relative to the paper market?

Rob, we're going to follow our normal course hedging strategy, and you'll see our hedge percentages move up as we move through the year. Sean, do you want to add anything more to that?

No. I think you know that we're right in our hedge policy, our hedge strategy of 80%, which does leave some exposure as we move through the year, but we'll continue to take that off. As we move forward and as we talked about in our prepared remarks, the curve remains heavily backwardated. So having that 18% overall exposed should benefit us as we continue to progress here.

Your next question comes from Patrick Kenny from National Bank Capital Markets.

Maybe just following up on that hedging question there, but more on the tolling front, I guess, just given the rising customer demand and wider spreads, even a little bit longer term? Just wondering how these recent global events have changed your tolling strategy, if at all, especially as it relates to contract duration, maybe you can speak to where you're at with securing any additional time charters that might be needed to, say, maximize value for the next wave of tolling agreements related to Optimization 2?

Thanks, Pat. So just as a quick reminder, we're about 65% toll starting next year when the 2027 NGL year kicks in. So that's for, obviously, RIPET, Ferndale, REEF and Optimization 1. So I think we're bang on our objective of increasing the durability and stability of our cash flows. So we're going to be out in the marketplace for Opti 2, fairly shortly once we've got our capital costs nailed down. And we're going to continue to target to have our total export book in that 60% to 65% range tolls.

And obviously, the strength of the global markets will be a tailwind when we have conversations with our customers. So we're very positive leaning on the fact that we should be able to both increase the amount of tolling we have in the term of those tolling contracts. So that's bang on.

Sorry, what was the other part of the question, Pat?

Yes. Sorry, the time charter, obviously, we took another time charter this quarter. We're going to get another time charter later this year. that really covers off all of our merchant barrels. And as we move forward, we're looking at potentially adding another 1 later -- contracting another 1 later this year. So more to come on that.

Okay. Perfect. And then, I guess, Vernon, with the balance sheet where you want it, sort of below the low end of your target range, starting to build some dry powder, especially if you do come in above the top end of your guidance. Can you speak to what types of midstream assets might not be in your organic backlog, but might be attractive from a M&A tuck-in perspective, just to help round out your value chain from wellhead to Tidewater.

Yes. I think, Pat, we get asked that question all the time. Obviously, we look at everything that's available for sale. But I think the key point is, anything that we buy needs to be additive to the value chain, as you pointed out, and particularly needs to come with liquids handling and the ability to integrate into our global exports platform. The good news that we have is we have an abundance of organic growth projects in front of us where we're able to invest, I don't know, 3x to 8x build multiples which are extremely attractive. So any inorganic investment is going to be challenged to compete the organic opportunities we have in front of us?

And maybe just to follow up on the organic side. I mean, just having to compete with Dow and some other major projects. Just curious your strategy around labor availability anything you're doing now to get ahead of what looks to be a rising cost environment and perhaps weaker productivity across the basin?

Yes. We've been really -- we performed really well over the last couple of years. And really, that's based on the strategy of trying to get as much work built off-site as we can in control manufacturing environment. With REEF, you will notice that almost everything that we do there is manufactured offsite and then brought on site and a small workforce is required to kind of LEGO-set the thing together. That was no different with Pipestone and the other projects that we're pursuing right now will be executed on that type of principles where we're minimizing the actual labor out in the field. So I think that's a real strategic advantage for us.

Your next question comes from Morris Chao from RBC Capital Markets.

Just want to touch on the opportunity set here. You mentioned the growing and diversified LPG exports to Asia. It sounds like you believe this demand will be durable even beyond the conflict. So how would you characterize the incremental opportunity set in particular, versus the maximum incremental potential at REEF?

Well, Morris, I think we've been very bullish about the long-term opportunities at REEF for quite some time. The determining factor, ultimately of the -- our ability to grow reef is how egress works for natural gas and crude oil for the rest of the production in Western Canada. So if we're able to get all of the LNG facilities built that are currently out there. If we're able to get more data center infrastructure built in Alberta, all that's going to drive natural gas drilling in Western Canada, which will provide a significant amount of liquids for us to export.

So the demand globally for Canadian LPG is extremely high. It's continuing to go up. I think the fact that we're transportationally advantaged into Japan, Korea and China has always been there. Now we're seeing Southeast Asia and South Asia looking to diversify for security of supply over both the Middle East and the U.S. So it really comes down to if we're able to make progress on these major projects and the MPO is successful, then we'll see benefits to us. So the demand has always been there. It's rising, but we're limited by supply.

Just as a quick follow-up to that. Obviously, when you think about REEF 1 and Opti 2 you've got way over 100,000 barrels a day of capacity through these 3 projects. Is there a way to characterize what the maximum potential capacity is. Because it sounds like you're suggesting this is not the limiter. It's more about LNG and crude oil export rather than at REEF?

Yes. REEF ultimately, we'll be able to export 500,000 barrels a day of LPG. Phase 1 is just under 60,000 barrels a day. Opti 1, 30,000 barrels of propane, Opti 2 is 60,000 barrels of propane and butane. So that's a sizable increase in a doubling of our global exports platform, but there's still lots more to come. And really, the speed and pace of those incremental phases, it will be dictated by overall egress on the basin.

That's great. If I can just finish off with a focus on the customers. How would you characterize the customer profile differences between China, India and Indonesia versus your more traditional Japanese and South Korean customers?

Well, Japan and Korea are mostly the large trading houses, which are integrated in their value chain. Chinese buyers are quite diverse. And Sean will speak to this in a minute that we've got a strong credit backstopping for that type of business, into markets such as Vietnam and other Asian market is really national companies [indiscernible] counterparties. [indiscernible].

And the last question comes from Ben Pham from BMO Capital Markets.

I had a couple of questions on Opti 2. And I'm curious, when you think about the potential probably of sanctioning that project. Is it more a question of really demand pull on that project from international buyers versus more of a supply partially we've maybe seen historically for it? And maybe secondary to that, could you add context around CapEx and returns? Is it more similar to a REEF project versus an Opti Phase I?

Well, maybe I'll answer the latter part of that question first. Remember that REEF Phase 1, we're pre-building 100% of the Jetty we're pre-building the rail infrastructure, and we're prebuilding the power generation. So the build multiple on Phase 1 is going to be in that 7 to 8x, which is probably the highest build multiple of anything that's going to happen at REEF. Opti 1 is an extremely capital-efficient expansion. So that is not indicative of other phases. So I think the way I'd characterize it, Opti 2 is going to be in between REEF Phase 1 and Opti 1. On the supply push versus demand pull, obviously, we're seeing lots of interest from Asia. So there should be stronger demand pull than we've seen historically, but it's still early days of us having discussions with customers about tolling for Opti 2. So I think we'll just say stay tuned for further updates as we move along throughout the year.

Okay. Got it. And you mentioned earlier in comments beyond the potential opt to 60,000 barrels loan ethane. Is there a reason why there's not looking for more LPG export first and status in the context that 500,000 barrels you mentioned earlier?

We will be able to bring phases of different phases of REEF to market as supply grows, Ben. I think what we're trying to move ahead right now as we know there's going to be good demand for Opti 2 that should meet the current forecast of LPG supply to the end of the decade, we currently in Alberta are extremely long ethane with no outlet market for it. There's hundreds of thousands of barrels that are getting reinjected into the natural gas stream. So there's an obvious need there. So should LPG supply grow at a faster rate, we can bring subsequent phases of REEF to market very quickly. So I wouldn't say that we're limited by our ability to increase capacity is really we want to match that capacity growth to supply growth.

Okay. That makes sense. And maybe just one last one on the data center opportunities and WGL and Michigan as well. Can you remind us, you got the 5-megawatt second project. Can you remind us what's in the backlog right now, maybe context and on average sizes? And is it still that estimated 1% potential uptick to the 8% or still think could materialize?

Ben, it's Blue. Yes, you're spot on. So as you know, the first couple of projects that we brought on here are fairly small. We talked about that first one in Maryland that expands in phases. This second one is for backup generation existing center. We are in conversations, as you know, across both Virginia, Maryland and Virginia. And those range anywhere from something that looks like this in the 15 or 20 megawatts up to the 50 megawatts but they're in various stages of assessment in FIE on their side to move forward. But we still think that looks like a 1% upside for us.

And this concludes the Q&A portion of today's call. I will now turn the call back over to Mr. Swanson.

Great. Thanks again to everyone for joining the call this morning. The Investor Relations team is around, if anyone has any further questions. Have a great day.

[Audio Gap] Sylvie, and I will be your conference operator today. [Operator Instructions] As a reminder, note that this conference call is being broadcast live on the Internet and recorded. I would now like to turn the conference call over to Aaron Swanson, Vice President, Investor Relations. Please go ahead, Mr. Swanson.

Good morning, and thank you for joining AltaGas' Fourth Quarter 2025 Results Conference Call. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website. Speakers this morning will be Vernon Yu, President and Chief Executive Officer; and Sean Brown, Executive Vice President and Chief Financial Officer.

We're also joined by Randy Toone, President of Midstream; Blue Jenkins, President of Utilities; and Jon Morrison, Senior Vice President of Corporate Development and Investor Relations. We will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 in the presentation. As usual, prepared remarks will be followed by a question-and-answer session. I'll now turn the call over to Vernon.

Thanks, Aaron. Good morning, everyone, and thanks for joining our Q4 conference call. I'll start by introducing Sean Brown, who joined us in January as our new CFO. Sean has been in the energy business for more than 25 years as an executive and an investment banker. Sean's strong financial background adds to our existing bench strength at AltaGas, and he will help drive the continued execution of our strategic priorities. Today, we will review our Q4 and full year financial results.

We'll reaffirm our 2026 guidance and update you on our progress of our strategic priorities. Our performance in 2025 reflects the strength of our people, assets and relationships, which positions us well for continued success in 2026. I'm going to kick off my remarks by reviewing some of the highlights from 2025, including our financial performance and the execution of our strategic priorities.

I'll then review our growth projects and our project backlog, talk about the importance of natural gas for long-term customer affordability and close by reviewing the current LPG export market. John will then cover our financial results and outlook in more detail.

Let's start on Slide 4. Our 2025 results were driven by strong performance in both Midstream and Utilities. We delivered normalized EBITDA close to the top of our guidance range, exceeding $1.86 billion for the year. Earnings per share came in at $2.23, which was in the upper half of our guidance range. We executed our strategic priorities by optimizing our asset base, delivering record global export volumes, record throughput at North Pine and Pipestone, along with active regulatory filings at our Utilities.

We continue to de-risk the business through long-term contracts and export market diversification in Midstream and extending regulatory approvals for the Utilities asset modernization program. We strengthened our balance sheet, exiting the year at 4.7x adjusted net debt to EBITDA and saw our credit rating outlook move from negative to positive.

We advanced key growth projects. Pipestone II came into service in December, and we saw great construction progress at REEF, reached positive FIDs on REEF Optimization 1, the RIPET methanol removal project Phases 1 and 2, expanding the Dimsdale gas storage facility and the Keweenaw Connector Pipeline in Michigan. These results translated into a 29% total shareholder return in 2025 and a 5-year TSR CAGR of 22%, where we have meaningfully outperformed our peers.

Turning to Slide 5. Pipestone II is complete and is operating close to full capacity. The project was delivered on time and on budget, further strengthening our Midstream value chain. On Slides 6 through 8, we highlight our construction progress at REEF. Phase 1 is now 70% complete, which was in line with our plan. We now have all the LPG accumulators and bullets on site.

All 3 LPG accumulators should be placed on their foundations this week. You can see a picture of the arrival of the 2 accumulators on Slide 8. Study construction has accelerated and remains on plan. We have successfully installed 8 of the 13 spans. The remaining sections will be put in place later this spring, and we've kicked off work on the loading platform. Phase 1 of the rail corridor and utility corridor have been finished.

This includes the full rail yard and the rail offloading modules. Opti-1 is also advancing on plan and is expected to be in service for mid-2027. Overburden removal has been completed and blasting activities will start this month. Opti-1 will add another 30,000 barrels a day of propane export capacity, which is higher than our original expectations.

Slide 9 shows that the RIPET methanol removal project and the Dimsdale gas storage expansions both remain on time and on budget. These new facilities will contribute to our 2027 growth outlook.

Slide 10 highlights our Midstream project offer, where we continue to advance multiple growth projects, including a Townsend De-Propanizer, a Northeast BC liquids expansion focused on improving long-term rail logistics, progressing additional phases of REEF, including the potential of adding ethane exports given the strong demand from China as well as a North Pine frac expansion and more gas processing with Pipestone III.

Let's turn to Slide 11. We're set to start construction of the Keweenaw Connector pipeline this spring. All the long lead items have been ordered and the entire right-of-way has been secured. We remain very active with $1.7 billion of modernization programs across our 4 jurisdictions, which will improve the safety and reliability of our network.

We are also advancing our data center opportunity set with multiple FEED studies completed. And we have now started construction of the natural gas connections to feed Phase 1 of a 24-megawatt facility in Maryland, which is expected to be completed by year-end.

Slide 12 highlights the importance of natural gas during today's energy affordability crisis for Utility customers across North America. Natural gas is the most affordable and reliable heating source in the U.S. The cost of electricity for home heating is more than 3x more expensive than natural gas across our jurisdictions.

This cost advantage is only getting bigger. Recent electric bill increases are coming in at over 10% per year, which is 4x current inflation. This trend will continue as more and more investment is needed to replace America's outdated electrical grid. Natural gas is the only energy solution that is scalable, affordable and reliable to meet growing North American energy demand.

Public policy should prioritize cost-effective outcomes by avoiding unnecessary electrification that increases customer bills and reduces energy reliability. We believe that policymakers should be incentivizing natural gas infrastructure for space heating across the country. Asian demand continues to grow and is expected to be up by nearly 25% by 2030. This is being fueled by new household demand in markets like India and the continued growth at PDH facilities in China.

In 2026 alone, we are expecting to see 300,000 barrels per day of increased propane demand due to Chinese PDH start-ups. Since the beginning of 2025, we've seen very strong demand for non-U.S. LPG supply with global trade sanctions. This has caused Chinese imports of U.S. propane to decline by more than 50% in 2025. And the market continues to pay a premium for non-U.S. propane. On the supply side, the local Canadian butane market is currently oversupplied due to certain facility outages.

Both of these supply and demand factors are tailwinds for our 2026 outlook. The FEI forward curve has strengthened materially in 2026 as highlighted in the bottom right chart. We saw FEI move up with winter weather in Asia, then further up with the recent Saudi supply disruption and even further up with the Iranian conflict. As a result, March FEI propane spreads are almost 50% higher than the start of the year, underscoring the severity of the Middle Eastern supply shock.

Let's turn to Slide 14. 2025 marked a step change in our export destinations with 45% of our volume landing in China, where our market share has now increased to about 6% of China's imported propane. AltaGas now represents 5% of Canada's total national trade into Japan, South Korea and China, amounting to about $2.5 billion in 2025, which we expect to double by 2030 with the start-up of REEF and Optimization 1 and the continued debottlenecking at our existing export facilities.

We're also proud to be investing in Asian economic activity with $600 million invested in Japan, South Korea and China over the last number of years to support the expansion of our global export business. This is in concert with very large investments that we've made with domestic manufacturers and engineering companies in Canada and the U.S.

Finally, on Slide 16, we're committed to our strategy of disciplined capital allocation. With approximately $5 billion of investment capacity over the next 3 years, we can fund $3.5 billion of growth while staying within our financial guardrails. Investment in our high-quality organic growth backlog supports long-term enterprise growth of 5% to 7% per year, which will generate meaningful and sustainable shareholder value creation. And with that, I'll now turn it over to Sean.

Thanks, Vernon, and good morning, everyone. I'm excited to be here for my first quarterly conference call with AltaGas. I'll begin with an overview of our consolidated quarterly financial results, followed by segment performance, a discussion of our balance sheet strength and conclude with our 2026 outlook.

Turning to Slide 17. We closed the year with a strong fourth quarter, delivering normalized EBITDA of $564 million, an 8% increase year-over-year and normalized EPS of $0.77, consistent with the same period last year. In the quarter, we exported more than 124,000 barrels per day of LPGs, including over 85,000 barrels per day from RIPET, a new quarterly record despite the impact of a 28-day labor disruption. At RIPET, we are pleased to sign a new 5-year agreement with the union in late December.

This agreement supports increased vessel loading and higher throughput moving forward and reflects AltaGas' commitment to working collaboratively with our unions to deliver positive outcomes for all stakeholders. Utilization across the balance of the Midstream platform was strong with throughput volumes up an average of 4% year-over-year across our gas processing, fractionation and extraction assets.

With respect to our Utilities business, colder weather and a growing customer base drove increased usage, as I will discuss on the next slide. The fourth quarter also saw several important regulatory outcomes, including approval of new rates in D.C. at 61% of our ask, a USD 25 million extension of the PROJECTpipes 2 ARP program in D.C. through June 2026, approval of a USD 700 million ARP amendment in Virginia extending through 2028 and the filing of a new rate case in Maryland late in the year.

In addition, subsequent to year-end, we recently filed a USD 61 million rate case in Michigan. And this week, we received approval for our DC SAFE ARP program to spend USD 150 million from mid-2026 to mid-2029.

In terms of segmented results, I'll start with Utilities on Slide 18. Utilities normalized EBITDA was $383 million, up 14% year-over-year. Performance was driven by rate base growth from ARP modernization investments, asset optimization initiatives and an 18% increase in usage, supported by colder weather in D.C. and Michigan and continued customer growth. Results also benefited from the partial settlement of Washington Gas' pension plan.

These positives were partially offset by lower realized contributions from the retail energy business and higher operating and maintenance costs, driven by increased labor requirements during cold weather and higher employee incentive expenses driven by AltaGas' rising stock price. During the quarter, we deployed $255 million of capital in Utilities, including $117 million towards modernization programs and $113 million towards system betterment initiatives. As noted, we remain active on the regulatory front with 3 active rate cases.

Shifting focus to our Midstream business on Slide 19. Normalized EBITDA was $202 million, an 11% increase over Q4 of last year. As noted, we exported more than 124,000 barrels of LPG per day during the quarter through 21 VLGCs and for the full year, averaged in excess of 126,000 barrels a day across 83 ships at our Ferndale and RIPET terminals.

Throughout the year, demand for our open access export terminals continued to strengthen, supported by long-term tolling agreements with investment-grade counterparties. These agreements enabled us to achieve our 60% tolling target, further enhancing cash flow durability. The remainder of the Midstream portfolio also performed well year-over-year, particularly our Montney focused assets where gas processing volumes increased 6% and fractionation volumes increased 14%.

Pipestone throughput increased 11%, while North Pine operated near its 25,000 barrel per day capacity. Constructive fundamentals for natural gas storage continue to reinforce our decision to advance both phases of the Dimsdale expansion, which will play a key role in managing Montney production growth and large LNG demand pulls in the years ahead. During the quarter, we remain disciplined in managing commodity exposure.

Our export business was largely insulated from price volatility through commercial tolling agreements and a structured hedging program. Looking ahead, approximately 80% of expected 2026 global export volumes are either tolled or financially hedged with an average FEI to North America spread of approximately USD 19 per barrel on non-toll volumes.

In addition, substantially all of our 2026 Baltic freight exposure is hedged through a combination of time charters, financial instruments and tolling arrangements. We continue to manage frac spread exposure through our disciplined risk management program. We have seen a meaningful uplift in frac spreads since the beginning of the year, which we have used to increase our hedge position, which now sits at roughly 70% through 2026.

Let's turn to our balance sheet on Slide 20. Following the decision to retain our stake in the Mountain Valley Pipeline, we issued $460 million in equity, achieving an equivalent deleveraging impact as if we had divested our working interest while retaining asset upside. These actions resulted in a year-end adjusted net debt to normalized EBITDA ratio of 4.7x, slightly below the midpoint of our 4.5 to 5x target range and led to positive credit revisions from both S&P and Fitch.

As we have commented recently, operating performance and progress on expansions at MVP continue to reinforce our decision to retain the asset. Since announcing our decision, the Southgate extension received unanimous FERC approval and key North Carolina water permits. The MVP Boost, which will add 0.6 Bcf a day of capacity through low-risk compression continues to progress well and is expected to enter service by mid-2028. The project is supported by investment-grade Utilities and is expected to generate a build multiple of approximately 3x EBITDA.

We are reaffirming our 2026 guidance, as shown on Slide 21, with normalized EBITDA of $1.925 billion to $2.025 billion and normalized EPS of $2.20 to $2.45. Headwinds and tailwinds remain relatively balanced at this stage. Year-over-year tailwinds in 2026 will include new utility rates in Virginia, Maryland and D.C., incremental contributions from Pipestone II and the Dimsdale Phase 1 expansion and continued growth in global exports supported by increased dock capacity at RIPET. These are expected to be partially offset by lower merchant volumes and more moderate retail energy performance.

The 2026 capital budget, as shown on Slide 22, remains unchanged at $1.6 billion with 69% of consolidated capital dedicated to Utilities and 27% to Midstream. Compared to last year, Utilities will see a meaningful increase in both spending and share of total capital reflecting significant opportunities around asset modernization as well as reduced requirements in Midstream following the completion of Pipestone II and lower capital needs at REEF.

Of the $1.1 billion Utilities capital program, 71% is allocated to modernization and system betterment initiatives, supporting safety, reliability and efficiency. This is expected to drive approximately 10% rate base growth in 2026.

Turning to Slide 23. I'll close by reiterating AltaGas' proven track record of delivering per share growth, which has translated into material share price outperformance. The company continues to offer an attractive value proposition, as shown on Slide 24. Our low-risk infrastructure platform supports stable, growing earnings and cash flows, underpinned by disciplined capital allocation and a robust organic growth pipeline. With that, I'll turn it back to the operator for the Q&A session.

[Operator Instructions] And your first question will be from Robert Catellier at CIBC Capital Markets.

I know this is a bit of a sensitive question, but I feel -- compelled to ask it. I was wondering, just understanding you've had a long history of constructive respectful dealings with First Nations. I'm wondering if there's anything you can share on the Metlakatla situation and their interest in the Trigon terminal. Any update you can provide there would be much appreciated. And specifically curious if you can confirm whether you're still engaged in active discussions with the Metlakatla.

It's Vernon here. I think you're absolutely bang on that we're disappointed that we're having a disagreement with the Metlakatla First Nation kind of in the public. At AltaGas, we take a lot of pride in the fact that we're a good neighbor and that we've been have had very strong relationships with all of our communities and particularly with our First Nation partners.

We've had indigenous equity participation deals and mutual benefit agreements for many, many years. And in fact, we've been working with the Metlakatla and Prince Rupert since 2017 with the development and start-up of RIPET and REEF. So across our footprint, I think we have 15 mutual benefit agreements in Alberta and British Columbia. In fact, we have 6 mutual benefit agreements on the coast for both REEF and RIPET.

With the construction of REEF, we've been actively working with various indigenous businesses where, in fact, about $350 million of REEF's total capital cost is being done by indigenous businesses, and we're really proud of that. So our hope is to continue to work with all of our First Nations partners. Obviously, we want to continue to have dialogue with them at Metlakatla. We do speak with them fairly regularly.

We're at a point right now where we're having a disagreement on a couple of items, particularly related to Trigon. And I guess we felt like we've been drawn into the situation because Trigon would like to build a competing LPG export facility on Ridley Island. The regulator and the landlord of Prince Rupert, the Prince Rupert Port Authority doesn't agree that they have the ability to do that.

And we need to obviously defend our commercial rights and protect our export franchise. So we feel that having exclusivity is an important feature. It's a common feature that you see in port development globally and in Canada. As an example, for REEF, we spent along with our JV partner, Vopak, about $100 million of that risk capital before we were able to get our permits to go ahead and that regulatory process, in fact, took around 7 years.

So without these types of commercial arrangements, it's very difficult for project proponents to put risk capital at work because you need to ensure that you're going to get a healthy and reasonable return on your overall capital once your facility is up and running. So long and the short is we've continued to have active dialogue with all First Nations along the coast, and we hope that we can find a mutually benefit solution as we go forward.

Okay. I had a couple of questions on the operations. A little surprised, Sean, to hear your comment about the puts and takes of the tailwinds and headwinds being relatively balanced. I would have thought maybe the change in commodity prices would have put the balance in favor of the tailwinds.

But with that in mind, given the change in commodity prices we've seen some producers such as Tourmaline are claiming to reduce deep Basin activity. With that in mind, are there any direct impacts from that disclosure from Tourmaline on AltaGas? And just in general, what's your sort of expectation of how the G&P business might develop for '26 compared to when you released guidance?

Maybe I'll start, Rob. So we've seen upstream customers want to take more control of gas processing, both in BC and Alberta for some time. And I think that the interesting part of that is by them taking control of that part of the business, they get more control over their liquids, which is positive to us because Tourmaline and other producers realize that the best outlet for their liquids is for global exports.

And Tourmaline is obviously one of our largest customers. So I think anything that they're contemplating, we generally stand to benefit because they have a deep understanding of market dynamics and how to maximize the netbacks of their LPGs. I think Sean and Randy can talk about just the outlook for this year.

Yes, I can start, certainly. I mean, I hear your comment, Rob, around the puts and takes. I mean, as we sit here today, certainly, there is constructive tailwinds given some of the geopolitical activity. But the thing I would say is it is early in the year as well. So we're trying to remain balanced as we think about the discussion around the full year.

And if you look at the shape of the curve in general, I mean, it's fairly backwardated. So it's all of that, that we put together when we thought about our prepared remarks. But your point is a good one where as you sit here today in isolation, probably the tailwinds are quite positive, and we feel good about where we are to start the year.

Okay. And just one quick one on the Utilities. Just wondering if you could provide a sensitivity to rate base growth, sort of big picture outlook should the various building energy performance standards in your jurisdictions pass as intended and survive any of the legal challenges?

Yes, thanks, Rob. It's a good question. We continue to work our way through that. As you would expect, the uncertainty seems to be more impactful than the actual change in the standards. So as we look across our business, the growth rate, we don't think is materially impacted as we look across how things are being built and what's being built.

What we're seeing is uncertainty of investment being more driven by the -- some of the other policies in the area. So as we look across that growth rate, we still connect -- we still have positive customer growth, very strong customer growth in Maryland. As you saw in the prepared remarks, we still see -- our first data center contract happens to be in Maryland right in the middle of all of those battles.

So at the moment, I don't know that I'd call it significant by any stretch, and I think that process is going to take a while, but we continue to educate the regulators and the decision-makers and of course, the investors in these projects about the overall affordability impacts and how to think about that more holistically. So we're optimistic that we'll get to a good place without significant impact.

Rob, just as a data point, the municipal government in D.C. excluded all of their buildings from those net zero standards. So it just tells you how [indiscernible] some of these initiatives are.

Next question will be from Rob Hope at Scotiabank.

I want to go back to the forward curve for global exports. You are correct. It is very backwardated, but we continue to see kind of, we'll call it, higher pricing push further out into the curve. Just given these dynamics, how do you think about your remaining merchant exposure through the year? Will you be looking to lock in pricing? Are you willing to ride out some spot exposure there? And in addition, are you able to push incremental spot barrels through if you're able to accumulate them?

Well, Rob, let me start and Randy can jump in if I miss something. So you're right. The curve is highly backwardated, but the curve has gone up a little bit. We're quite comfortable with our hedge positions right now where we're about 80% hedged for the year. We are benefiting a little bit from supply differentials. And then on our open merchant volumes, we are seeing strong demand for those barrels with obviously the supply outages coming out of the Middle East.

We will -- and it is a unique market where you're seeing everything on the screen that you see may not be fully representative of the final sales price that we get. So we think we're perhaps being a bit cautious in talking about this. But if this continues to play out where the straits are shut down for an extended period of time, I think we're in a good position with our current financial hedges that we don't really need to do any more.

All right. Appreciate that. And then maybe just turning over to REEF Opti-1. So can you walk us through how it went from 25,000 barrels a day to 30,000? And is that 300 now firm? Or could there be some further upside there as well?

Rob, it's Randy. Just with the further detailed engineering of Opti-1, the teams identified some adjustments that added the extra 5,000 barrels. So there's nothing unique there. It's just as you go through detailed engineering, the team plans optimizations.

Next question will be from Sam Burwell at Jefferies.

Dovetailing on with the prior question, I'm curious if you could give some sort of breakdown as to like what really drove the wider hedge spreads in the second half versus the first half. Is that a function of like layering on hedges recently with Far East propane spreads being a lot wider? Is it contribution that's pretty meaningful on the butane side? Just curious if we could get a breakdown of that to inform the much wider locked in spreads in the back half of the year.

It's Randy. I think it's a combination of both. It's -- we actually have seen some -- the spreads widen, and so we've took advantage of that to put in some hedges. But it's also -- it's higher -- we have higher hedges on butane, which is a larger spread.

Okay. Understood. And then just on the potential projects that you guys called out in the slide deck, I mean a lot of those addressed liquids growth out in the future. So just like curious how you guys would, I don't know, maybe clarify some of the hurdles that are remaining on each of them where you might rank order them in terms of build multiple or timing perhaps?

I think the Townsend depropanizer is probably the most we should see an FID sometime in the next 12 months or so. That really is customer-driven at this point, whereas customers bring on more volumes, we have an obligation to process those volumes for them. Then we, obviously, with the depropanizer are able to get the liquids out and move them to the West Coast at our North Pine rail facility. I think REEF Optimization II is also a 2026 potential FID project.

There, obviously, the strong commercial support. It's really just locking down the capital cost. So we have a firm Class III cost estimate and then finalizing one permit amendment that we need to go ahead with that. The other ones are probably in that 12 to 15 months out, maybe 24 months out. And all of these projects are relatively low capital, low build multiples, so highly attractive and should be very competitive as we do our capital allocation going forward.

Okay. Great. One real quick one just on REEF Opti-2 since you brought it up. I mean is that sanctioning contingent upon any progress made with the discussions with the Metlakatla?

We're obligated to do consultation with all of our First Nations, and the consultation process will go into the regulator, and the regulator will make a determination if we've done sufficient consultation.

Next question will be from Jeremy Tonet at JPMorgan.

This is Eli on for Jeremy. Just wanted to start on the balance of Midstream versus Utility capital within the backlog. We see nearly twice as much Utility growth capital versus Midstream. And so if we see some of these projects in the backlog move ahead on the Midstream side, could we see that mix shift move a little? Or -- and then maybe just thinking about sort of the strong returns you generate from those Midstream projects, could we see sort of higher within the range of that 5% to 7% long-term annual growth if you were to sanction more Midstream projects?

Eli, I think you've asked a great question. You would have seen us in the last couple of years slow down our Utility spend a little bit when we had some very attractive Midstream projects to execute. And the good news that we found is that those Utility growth opportunities didn't go away. They just got deferred a year or 2.

So I think if we are in a situation where we have more projects than investment capacity, we're going to have to go through and do our process of capital allocation and the best risk-adjusted returning projects will get priority. So the nice thing about Utility capital is its ratable growth. So -- because the bulk of our capital that we're spending is modernization capital with rate riders, so we get that almost immediate growth from it.

Midstream projects do have a longer gestation period and build cycle. So while they may be more attractive, they are lumpier in nature. So I think if we're successful in filling up the full growth hopper, we'll be very comfortable to be in the upper end of our medium-term growth guidance.

Great. I had a smaller accounting question as a follow-up. We've seen some consistent transaction or restructuring expenses, and I know it's been a while since the last larger transaction. Any color on what those kinds of add-backs pertain to?

Are you -- sorry, are you referring to sort of normalization in general?

Yes. I mean I think we see restructuring costs and transaction costs, just looking at some of the reconciliations within the MD&A.

Yes. I mean if you look -- just think about last year alone, I mean, with respect to the MVP transaction, there certainly would have been some there. There was some changes otherwise. But I mean, in general, the biggest one would have been really around MVP that I'd highlight.

Next question will be from Ben Pham at Bank of Montreal.

Maybe more detailed question on WGL. Can you quantify or attempt to quantify what the realized ROE was for 2025 versus 2024.

I'm going to -- just give me a second here, Ben.

Yes. So on the portfolio for WGL, realized we were within about 100 bps of the authorized on the total portfolio. That varies a bit by jurisdiction, as you would expect, but the total portfolio, about 100 bps of authorized -- within authorized.

Okay. So it sounds like it's generally unchanged versus 2024 then in terms of the relative difference?

I think it's a little bit better than 2024, maybe 10 or 20 basis points. We expect that to improve further in this year because of the DC rate case going in, getting approval for the DC rate case and having those rates go ahead. So we think we'll be in the range of about 70 basis points in 2026, Ben.

Yes. I think that's right. I would add, Vernon, to that and just Ben, so that we have a full year of the DC rate case. We have rates in effect from Virginia at the start of the year, subject to refund on that final case. And then we filed for Maryland, and we expect to have rates -- new rates in effect in Q4. So I think you see a consistent progression in '24 to '25 to '26.

And as we've said in the past, Ben, that doesn't include asset optimization, which is always an opportunity for us to improve returns as well, and that will be consistent this year.

Got it. And there was an earlier question on the propane export hedging. You provide some details there on the level and the shape of it. You also provided the sensitivity as well; $1 a barrel is $10 million. Is that sensitivity, is that incremental to the price levels you disclosed? Is that some lower number that's baked into your 2026 guidance?

So that would be what's baked into our 2026 guidance, Ben.

And presumably, that's probably lower just given when you put your budget out versus how the spot has moved since then?

Yes, that's fair.

Next question will be from Robert Kwan at RBC Capital Markets.

First question here is just on Prime Minister Carney's meetings in India and the government's release citing the ongoing engagement for more LPG exports into India. So I'm just wondering, generally, just what your thoughts on that given of all the different things you talked about energy-wise, LPGs are probably most actionable in the near term. And then there was also a statement about addressing higher shipping costs. And I'm just wondering if you've got some color or thoughts on that as well.

Well, I think, Robert, the dynamic with India is there is very strong demand in India for more LPGs. Remember, I think 300 million people in India still cook with charcoal. And I had recently met with Minister Hodgson, who indicated when he was in India that India is very keen to get people off that cooking charcoal and propane is obviously the best alternative for that market.

As you know, India is a little bit far away from Canada. So Middle Eastern barrels will always be advantaged going into India just because of shipping costs. Once you go past about South China, we become disadvantaged on a shipping cost basis. So you've seen us kind of move initially with RIPET into Japan and Korea, where we had a material shipping advantage.

We've seen the Chinese market open up to us primarily because of U.S. trade tensions. And then as demand continues to go up and if Canada disproportionately grows in supply, we do have an opportunity to expand to other markets. And that's why we're so keen to have REEF Opti-1 and hopefully Opti-2 follow up and provide access to Canadian producers to all of these markets.

And just in terms of the government statements that both are going to work on helping address the shipping cost differential, do you see that then as just a redirection of flow? Is that maybe higher contracting for you or possibly new capacity?

We haven't seen any direct linkage yet. So we look forward to engaging with the government and seeing what they're thinking about.

Okay. Just the last is on fractionation capacity, and you kind of outlined some potential projects in North Pine and Townsend. I guess just as you think about your existing integrated network and possibly further increasing capacity at REEF, do you feel the need to even further increase your control of NGL fractionation beyond what you've outlined for Townsend and North Pine?

We're actively working with a number of our customers, primarily NGL aggregators that have significant amounts of frac capacity and growing frac capacity. So we're looking to offer full-service solutions from the wellhead to the dock, basically in a JV-like partnership with a number of these companies.

Obviously, you've seen in the last 12 months, we press released transactions with Keyera, Pembina and Wolf, all of which are building incremental fractionation. So our view is if we're able to bundle these solutions through partners, so it's not critical that we own more frac capacity. But I think we're uniquely situated in Northeast BC, where with North Pine and Townsend, we can provide just that much of a better logistical option because of where our rail facilities are, Robert.

And our last question will be from Patrick Kenny at National Bank Capital Markets.

I guess just on the appointment of Mr. Evans as Chair, we've seen a decent uptick in bitumen production over the past few years and a fairly constructive outlook here for egress expansions going forward. I know the exports platform and execution of REEF is top priority.

But just wondering if we should be reading into any longer-term shift in strategy related to looking at participating in any opportunities to extend your service offering to oil sands producers, whether it be on the propane solvent front for SAGD projects or perhaps investing more heavily into condensate infrastructure, either in BC or Fort Saskatchewan?

Well, Pat, I don't think you can read a ton into Derek's appointment of a change in strategy. We're going to be disciplined in how we put our capital to work. We feel like we obviously have strategic advantages in NGLs and global exports, as you pointed out.

If there are opportunities to work with oil sands producers about moving NGLs from Fort McMurray to other markets, well, for sure, we'd be happy to investigate that. But I wouldn't read too much. And we just want to have Board members with deep industry knowledge and great management experience that provides advice as we continue to try to grow and optimize our business.

Okay. Got it. And then maybe just back on the unsecured growth backlog. So you touched on the cost advantage of gas over electricity on the Utilities front. It seems to suggest some upside there to the CapEx plan. Yet obviously, still a lot of attractive projects in the queue on the Midstream side.

So I'm just wondering how you might be thinking about bringing in some strategic JVs or other financial partnerships, just whether it be on the U.S. side of the border or up in Canada, just to make sure you don't have to pass up on any opportunities from a funding standpoint.

Well, the good news is our investment capacity grows each and every year as we add cash flow. So we have a natural uplift in the amount of capital we can put to work. Some of these things that we're looking at, obviously, in the unsecured hopper are further out in time where we'll have more investment capacity. But at the end of the day, if we've got great projects that pass all of our investment hurdles, our finance team will figure out a way to get them financed.

Thank you. This concludes the Q&A portion of today's call. I will now turn the call back to Mr. Swanson.

Great. Thanks again to everyone for joining the call this morning. The Investor Relations team is around if you have any further questions. Have a great day.

Thank you, sir. Ladies and gentlemen, this concludes today's conference call. Once again, we would like to thank you for attending and at this time, ask that you please disconnect your lines.

Good morning, ladies and gentlemen, and welcome to the AltaGas Ltd. Third Quarter 2025 Results Conference Call. [Operator Instructions]

I would now like to turn the conference call over to Aaron Swanson. Please go ahead.

Good morning, and thank you for joining AltaGas' Third Quarter 2025 Results Conference Call. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website.

Speakers this morning will be Vern Yu, President and Chief Executive Officer; and James Harbilas, Executive Vice President and Chief Financial Officer. We are also joined in the room by Randy Toone, President of Midstream; Blue Jenkins, President of Utilities; and Jon Morrison, Senior Vice President of Corporate Development and Investor Relations.

We will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 in the presentation.

As usual, prepared remarks will be followed by a question-and-answer session.

I will now turn the call over to Vern.

Thanks, Aaron. Good morning, and thanks for joining us. I'm pleased to discuss our strong Q3 results and the continued advancement of our key strategic priorities. Our performance in Q3 positions us well to deliver on our 2025 guidance.

I'll start by highlighting the key developments from the quarter, which include 3 new growth projects, an update on our construction progress at REEF and Pipestone II, and I'll finish by touching on the macroeconomic trends that continue to provide tailwinds for our business. James will then walk you through the details of our Q3 financial results and provide an update on our guidance and outlook.

Let's start on Page 4. Our third quarter results were anchored by strong operational performance in both Midstream and Utilities. We increased throughput in Midstream with record global export volumes and continued operating cost reductions in the Utilities. We derisked our portfolio by adding additional long-term tolling agreements, systematically hedged our residual commodity exposures and made regulatory filings in Virginia and D.C. to maximize our regulatory outcomes.

Our balance sheet remains strong. Continued deleveraging has expanded our investment capacity, which allows us to increase our secured growth inventory. Pipestone II has now reached mechanical completion and all of the permanent piles have now been installed at REEF and major equipment like the LPG accumulators are scheduled to be delivered over the next couple of weeks. Our actions continue to be guided by disciplined capital allocation, where we fund the best risk-adjusted returning projects to create long-term shareholder value.

As shown on Slide 5, we delivered a normalized EBITDA of $268 million, slightly below Q3 2024 due to the pension settlement recorded in 2024. Excluding that item, year-over-year normalized EBITDA grew by 18%. Q3's operational performance was excellent. We achieved record global export volumes in the quarter, over 133,000 barrels per day, with year-to-date volumes up 4%. This reflects strong demand for Canadian LPGs at our open access terminals and great operational performance by our teams. We also saw robust gathering and processing activity where throughput grew by 3%. Our North Pine frac plant recorded 13% year-over-year volume growth, achieving a processing record.

We continue to be very active with our regulatory actions. In D.C., we advanced our rate case, while in Virginia, we filed for new rates. We also submitted amendments to extend our ARP programs in Virginia and D.C., which reinforces our commitment to make our systems safer and more reliable.

Utilities also performed well, supported by $121 million in modernization spending and a 5% reduction in O&M costs at WGL.

We are very excited to announce the FID of 3 new growth projects this morning. All of these projects are underpinned by extremely strong demand by customers for our services. REEF Optimization One, or Opti 1, will add up to 25,000 barrels a day of propane export capacity with a total capital cost of $110 million, $55 million net to AltaGas. The project is expected to be in service in the second half of 2027.

As a quick reminder, Canada produces around 500,000 barrels a day of LPGs, where we use half of it domestically and the balance gets exported to the U.S. and Asia. The U.S. is already long LPGs, so Canada needs to increase Asian exports to maximize the value of our product. Opti 1 is the first in a series of optimizations and expansions at REEF that will unlock significant additional global market access for Canadian LPGs.

We are also excited to move forward with our Phase 1 expansion of the Dimsdale gas storage facility. The 6 Bcf expansion is backed by 2 10-year firm service contracts with Tourmaline and Gunvor. The capital cost for the project is estimated to be about $65 million with a target in-service date of year-end 2026. The project will focus on facility debottlenecking to expand capacity and will also significantly reduce our operating costs. We also continue to advance a larger Dimsdale expansion, Phase 2, which will more than double storage capacity from 21 Bcf to upwards of 70 Bcf.

In Michigan, we're moving ahead with the 30-mile Keweenaw connector pipeline following regulatory approval in Q2. Keweenaw is USD 135 million project that will come online in early 2027. It will enhance system reliability for 14,000 SEMCO customers. As highlighted on Slide 7, our secured growth project inventory continues to increase. We have many more opportunities in the project hopper, and we look forward to announcing additional FIDs as these projects are sufficiently derisked. We have approximately $5 billion of investment capacity over the next 3 years, of which $3.5 billion can be dedicated to growth initiatives, which all can be executed while we live within our financial guardrails. Successful execution of these growth projects in Utilities and Midstream allows us to grow the enterprise at an average of 5% to 7% per year over the long term.

Let's move to project execution. Construction on REEF continues to be on time and on budget. 77% of the project's costs have either been incurred or committed with nearly 70% of the capital under fixed-price EPC contracts, significantly derisking the project's cost. Off-site manufactured equipment has started to arrive at Ridley Island, with the first of 3 LPG accumulators, along with the butane and propane bullets expected to arrive over the next couple of weeks. Fabrication in Asia is progressing to plan with the remaining 2 accumulators 95% complete. Steady construction is advancing, and we're now 60% complete. All of the permanent piles are in place. Five out of the 12 platforms are now ready for topside work, and we have begun installing the prefabricated pipeline [ thrusts ].

We've also made strong progress on the rail loop, on-site roads and the utilities corridor. Slide 9 highlights some of our recent construction progress.

As shown on Slide 10, we're pleased to announce that Pipestone II has reached mechanical completion with commissioning underway, and we remain on track to be fully operational by late 2025. I want to congratulate the team on their strong project execution and safety performance. They worked over 420,000 project hours without serious injury, having up to 450 workers on-site at peak times with no quality regulatory environmental issues during construction.

Moving to Slide 11. We want to highlight some of the key macro drivers that support our Midstream business. Canadian gas production is positioned to continue to grow and be led by strong economics in the Montney, and LNG demand pull over the long term. With 3 Canadian LNG projects now operational or under construction and another 3 at various stages of pre-FID, Canada is positioned to export upwards of 7 Bcf per day by 2030. This highlights why we've made considerable infrastructure investments in the Montney over the past decade. More than half of our G&P and fractionation assets are positioned in this region to service the growing demand for gas processing, liquids handling, fractionation and global export connectivity.

As highlighted on Slide 12, the macroeconomic outlook for our Utilities is equally robust. U.S. energy demand continues to rise with all roads leading back to natural gas as the most scalable, reliable, affordable and environmentally-friendly energy solution. These fundamentals support our modernization investments, where we have long-term plans to replace vulnerable pipelines to enhance our system safety and reliability. These investments will allow us to deliver the most affordable and reliable energy to our customers for decades to come. As you see on the top of the chart, the delivered cost of electricity is more than 3x higher than natural gas across D.C., Maryland and Virginia and even higher in Michigan, but the delivered cost of electricity is over 5x greater than natural gas.

Affordable, reliable energy is essential to economic growth in our franchise areas, and it's our responsibility to deliver it. It's becoming increasingly evident that we're operating in a period of growing energy in security, particularly in the PJM market, where concerns about power capacity shortfalls are accelerating. We are seeing a massive increase in the gas generation backlog across the U.S. And in PJM alone, the region has 16 gigawatts of gas-fired power generation backlog. To meet rising demand, U.S. electric utilities are increasing capital spending. 2025 spending is up 25% over 2024. Between 2025 and 2027, nearly $700 billion of capital is expected to be invested to support robust power demand and the need to replace aging electric infrastructure. This level of investment will likely put further upward pressure on electricity rates, further enhancing the affordability advantage of natural gas.

AltaGas is well positioned to benefit from these macro tailwinds that support continued growth in our businesses. We will remain disciplined in how we operate and allocate capital to ensure that we deliver long-term value for all of our stakeholders.

And with that, I'll turn it over to James.

Thanks, Vern, and good morning, everyone. We're pleased with our strong third quarter performance, continued operational execution across the platform and the progress we've made on our strategic priorities. I'll start with a detailed review of our financial results from each segment, provide an update on the Mountain Valley Pipeline, its growth projects and our monetization process, discuss our 2025 outlook and close with our value proposition.

Let's start with the Midstream business on Slide 13. Segment delivered a solid quarter, supported by strong execution across our integrated value chain. Normalized EBITDA for the second quarter was $204 million, up 13% from $181 million in the same period last year. This performance was supported by record global export volumes, which increased 4% year-over-year and was accompanied by stronger realized margins. We exported over 133,000 barrels per day of LPGs across 23 VLGCs during the quarter. This included more than 77,000 barrels per day across 13 ships at RIPET and nearly 56,000 barrels per day across 10 ships from Ferndale, the equivalent of a vessel departing our docks every 4 days. These volumes approach the effective near-term operational capacity of our current export platform, which highlights the need to bring REEF online and our decision to move forward with the REEF Optimization One project.

AltaGas' export business was largely protected from commodity price volatility during the quarter through our commercial tolling agreements and our active hedging program. Operating results across the balance of the Midstream business was strong and continue to benefit from the strategic locations of our assets, our long-term contracts and our strong customer base. The greatest strength was seen in our Northeastern BC Montney footprint, where North Pine volumes were up 13%, Blair Creek volumes were up 9% and Townsend volumes were up 6% year-over-year. This strength was partially offset by lower volumes at Younger, which is a nonoperated facility that experienced an extended unplanned outage during the third quarter.

Volumes at Pipestone I in the Alberta Montney were also lower on a year-over-year basis in the third quarter due to a planned turnaround where the facility was offline for most of September. Since then, volumes have returned and the plant is operating near capacity.

The value of our Dimsdale natural gas storage facility was demonstrated during the third quarter, where gas storage reached record levels and highlighted the critical need for increased storage capacity in Western Canada. This reiterated our decision to reach a positive FID on the first phase of expansion for Dimsdale. Dimsdale will be critical for balancing needs of the Montney and increased natural gas demand from LNG export facilities. We are pleased with the value and protection the asset will unlock for our customers in the years ahead.

In terms of risk management, principally all of AltaGas' remaining 2025 global export volumes are either tolled or financially hedged with an average FEI to North America spread of approximately USD 17 per barrel on the non-toll volumes. We've also substantially hedged all of our 2025 Baltic freight exposure through a combination of time charters, financial instruments and tolling arrangements.

Turning to Slide 14. The Mountain Valley Pipeline delivered another strong quarter, which reflected the pipeline's long-term contracts and robust demand to move Appalachian gas into key downstream markets. The 2 Bcf per day pipeline is operating near current capacity under 20-year contracts with strong customer demand for additional capacity. Following a highly oversubscribed open season, the partners have increased the size of the proposed MVP Boost expansion project by 20%. Boost is expected to increase overall MVP capacity by 600 million cubic feet per day with the mid-2028 in-service date. This is a year earlier than previously expected with the entire 600 million cubic feet per day of incremental capacity fully contracted by investment-grade utilities under 20-year take-or-pay agreements. USD 450 million project is targeting an approximate 3x CapEx-to-EBITDA build multiple. The proposed MVP Southgate project is also progressing under the more efficient project plan with FERC publishing its environmental assessment in October, including that Southgate will not cause significant negative impacts from its development as the project will adhere to certain mitigation measures and environmental safeguards.

AltaGas continues to move through our sales process, inclusive of recent positive developments on the pipeline over the past months and expects to provide an update in the coming weeks.

Let's turn to Utilities on Slide 15. Normalized EBITDA was $68 million in the third quarter of 2025 compared to $117 million in the same quarter last year. The year-over-year reduction was principally driven by the absence of the partial settlement of the Washington Gas' post-retirement benefit pension plan that was recognized in the third quarter of 2024. Excluding this impact, Utilities performance was strong as a result of higher revenue from modernization investments, a 5% reduction in operating and maintenance costs at WGL, and stronger performance from the retail business. The steps we took to reduce our cost structure in 2024 continue to drive productivity improvements that benefit all our stakeholders. By maintaining operating costs within approved rate structures, we preserve affordability for customers while creating financial headroom to invest in asset modernization, system reliability and safety enhancements, improving the reliability of our system and reducing leak rates, which benefits our customers over the long-term.

We deployed $206 million of capital in Utilities during the quarter, including $121 million towards modernization programs and $33 million for new meter connections. For full year 2025, we expect to invest over $700 million in Utilities as we continue to make critical investments for the future. We remain active on the regulatory front with 2 active rate cases and modernization amendment applications in D.C. and Virginia. In July, we filed a $65 million rate case in Virginia, net of the SAVE surcharge with a requested 10.85% ROE. With a 120-day statutory time line, we expect interim refundable rates to be in effect by 2025 year-end. In early August, we filed an amendment to the Virginia SAVE modernization program, seeking to extend the program by 1 year and move forward with an amended 3-year plan. The proposed plan is to invest approximately $700 million in modernization capital between 2026 and 2028. Decision on the proposed amendment is expected by 2025 year-end.

In D.C., we continue to advance the 2024 rate case filed last August and are expecting resolution by year-end 2025. While the PSC of D.C. continues to review the district SAFE application, we recently submitted an application to extend the existing PROJECTpipes 2 program through June 30, 2026, with the additional spending of USD 33 million, which ensures our modernization investments will continue uninterrupted while earning an immediate return on capital.

We continue to progress data center business development initiatives with active opportunities in Virginia, Maryland and Michigan. FEED studies are underway for both primary and bridge power solutions with pipeline interconnect infrastructure. These projects are being pursued on a derisked basis through traditional rate-regulated investments with unique rate structures.

In the Corporate and Other segment, we reported a normalized EBITDA loss of $4 million, consistent with the third quarter of 2024 as lower G&A costs were offset by lower contributions from Blythe.

Turning to our 2025 outlook on Slide 16. We are reiterating our 2025 guidance. While we've seen a number of tailwinds and headwinds this year, they have largely balanced out. And coupled with our performance year-to-date, we are on track to deliver full year 2025 results in line with our guidance ranges for normalized EBITDA and EPS.

There are no major changes to our 2025 capital budget, as shown on Slide 17. We expect to deploy $1.4 billion with 51% allocated to Utilities and 45% to Midstream as we complete Pipestone II while making material advancements on REEF. Majority of the Utilities capital will continue to support ARP modernization programs and system betterment, with the remainder targeting new business and customer connects.

We continue to optimize our capital structure and drive costs out of the enterprise. In early September, AltaGas issued $200 million of 5.38% junior subordinated hybrid notes with proceeds used to redeem the Series A and Series B preferred shares. This issuance will result in cash savings of approximately $30 million over the initial 5-year term due to lower taxes and financing charges relative to the potential reset rate on the Series A and Series B preferred share dividends.

In closing, we delivered a strong third quarter, reinforcing the value of our diversified infrastructure platform and our continued operational execution. As highlighted on Slide 18, we have a compelling investment proposition with low-risk infrastructure that provides stable and growing earnings and cash flows. We have strong organic growth across the platform. We have been disciplined allocators of capital over the past 6 years, and we'll continue to focus on that into the future.

And with that, I will turn it back to the operator for the Q&A session.

[Operator Instructions] Your first question is from Jeremy Tonet from JPMorgan.

This is Eli on for Jeremy. I just wanted to start on the returns and build multiples across exports, frac, gas processing, storage, all the opportunities you have. It seems like there's a lot of optionality in the hopper, both sanctioned and ahead. So can you talk a little bit about the returns on those projects and then how you kind of stack rank the opportunity set? I think you said $3.5 billion worth of dry powder in the next couple of years. And maybe just provide a little more color on that.

It's Vern here. I think what we set out in our prepared remarks was that over the next 3 years, we have about $5 billion of total investment capacity. We'll use about $400 million a year for system betterment and then about $500 million a year on ARP programs. After that, we start funding our best risk-adjusted returning projects. And in the near-term, the series of Midstream projects that we have, as evidenced by REEF Opti 1 are very attractive projects for us where the build multiples are relatively low given the fact that the base REEF project prebuilds out a lot of the common infrastructure for further optimizations and expansions. And that's similar to how we've looked at the Dimsdale gas storage FID that we did this morning as well.

So, again, it's lots of opportunities, both in Midstream and Utilities. Utility build multiples tend to be a little bit higher just because of the difficulty of doing construction and busy metropolitan centers.

Got it. And then yes, maybe just on the kind of data center-driven power demand. I think you mentioned some pipeline infrastructure opportunities as well in the opening remarks. So, are these kind of more of those like bolt-on size projects? Or is there anything chunkier out there that would contribute more meaningfully to your system or rate base?

Yes. Eli, it's Blue. Thanks for the question. What we're seeing are smaller projects consistent with what we shared in the past, those are rate base items that are in that single-digit millions up to the $40 million range. So we connected one in Michigan recently that was about $10 million. We've got some other projects in the hopper that look to be in those type of ranges. So they're incremental single-digit up to $40 million that will roll into our rate base.

And your next question is from Rob Hope from Scotiabank.

So good to see REEF Optimization One sanctioned. When -- and on the call, you did mention that there could be a series of further expansions, including Opti 2, which is 60,000 barrels. How should we think about the sequencing of these events or the key gating factors? Is this -- do you need additional customer commitments, additional engineering and work there? Or do you have to have construction largely done on the first phase just logistically to get Opti 2 off the ground?

I can start, and Randy can chip in if I miss something, but I think you've hit the nail on the head. We have to make progress on all 3 fronts before we are comfortable sanctioning Opti 2. Number one, I think, is critically, we haven't finished the detailed engineering and don't have a firm Class III cost estimate yet on Opti 2. We see very strong commercial interest for more tolling, but we would need to do a little bit more incrementally commercially to maintain our current 60% toll target for the aggregate global export business. And then finally, we want to make sure that anything we go ahead with on Opti 2 doesn't impact the in-service date of REEF itself and then Opti 1. So that's kind of how we're looking at it. So we'll have much more comfort around all that probably end of Q1, early Q2 next year.

All right. Appreciate that. And then just maybe over to Dimsdale. Can you confirm that you could move up to 70, I believe, is what you said? And then secondly, are you engaging customers already on that expansion? And could that be done in phases as well?

The actual number is around 69, and we are in active commercial discussions with a whole host of customers right now.

And can it be done in phases?

Yes.

And your next question is from Sam Burwell from Jefferies.

First off, on MVP, did the upsize of the Boost expansion have any impact on the timing of your sales process? I mean, it seems like the [ upgraded ] timing making the project [ more attractive for ] potential buyer. So I'm wondering if that [indiscernible].

Sorry, Sam, can you repeat your question? You broke up.

Sorry, can you hear me better now?

Yes.

Okay. So just on MVP, did the upsize of the Boost expansion have any impact on your sales process timing? I'm just curious what the remaining gating items or hurdles are getting a deal finalized.

Yes. No, I mean, look, we've been pretty consistent about the fact that we're moving through that process, and we are in the very late final stages of our sales process. We have, though, said in the past that we want to get a fair value for MVP. And you touched on some recent developments in terms of the success that MVP Boost saw in its open season. Obviously, the increased throughput, they've been able to realize slightly better rates per dekatherm, too. So we would expect that valuation to be reflected in any transaction that we're looking to consummate on MVP, but we continue to work our way through that sales process.

Okay. Great. That makes sense. And then on the REEF Optimization, what drove the decision to upsize that up to $25,000 a day? Is that a function of wanting to get the contracted tolling percentage to the right level or perhaps a function of more tolling agreements coming through?

And then also, I'm just curious if you can quantify the build multiple on that. I know that you've said that the brownfield expansions are extremely attractive in the past.

Yes. I think we've seen tremendous interest in tolling from our customers. And there's -- obviously, we're right now moving as much LPG as we can to Asia, and that interest continues to grow. So the optimization was very well received commercially. So we're very happy to be able to bring that to market.

I don't think we're going to comment specifically on the build multiple, but it's a very, very attractive project for us.

And your next question is from Maurice Choy from RBC Capital Markets.

I just wanted to start with the investment capacity. You mentioned $5 billion, of which $3.5 billion will go to growth while maintaining your leverage guardrails. My question is more of a philosophy discussion about how you see the timing of your growth opportunities versus the funding capacity that you have? Is it that there is a lot of growth opportunities, but your growth investments are limited to $3.5 billion because of your leverage guardrails and the capacity? Or put differently, there's so much projects that makes sense to go for in these years such that you actually have more balance sheet headroom to do more?

I think we're in a great position, Maurice, where we have growing investment capacity with the $5 billion represents an uptick over what we've had over the last couple of years. And really, that's on the back of the improvements in the balance sheet and the material growth we've seen in our cash flows. We see lots of opportunities in front of us, both on the Utility and Midstream side. So I think we're kind of in the right balance where we're seeing an uptick in investment capacity and the fact that we have lots of projects on the go and those projects now have to compete with each other to deliver the best risk-adjusted returns for us.

And I wouldn't mind just adding something to that, Maurice. Obviously, our investment capacity and Vern talked about it, it's increasing and it increases every year, right? I mean, if we look at the end of '25, we're going to have Pipestone II coming on, which is going to generate incremental EBITDA that will take our investment capacity higher into '26 and give us additional headroom to fund some of these projects that we just FID-ed. Obviously, the completion of the MVP process will increase our headroom within 2026.

And the last thing I'll add is that, a lot of these opportunities that we have in the pipeline have different gestation periods. So as we start to build out the ones that we've FID-ed and REEF comes online and Opti 1 comes online, it just continues to expand the annual investment capacity that we can allocate to the development pipeline that we have in front of us. So there's a timing element to moving those projects.

And maybe just a quick follow-up to that. Are you directionally seeing the risk-adjusted returns staying roughly the same? Or do you think that the competition for capital ultimately leads to some of these returns moving higher, be that because customer demand is changing because the landscape is changing?

I think generally, the utility risk-adjusted returns are staying fairly constant. I think we make progress on all of our capital at the utility as we manage our costs effectively and manage our rate filing process properly. I think it's fair to say in Midstream, the risk-adjusted -- the returns are higher. Obviously, there's a slightly different risk profile, but I think those returns are trending in the right direction, particularly on global exports because of the fact that we've prebuilt a bunch of common infrastructure in REEF Phase 1. So the optimizations and subsequent expansions will be at return better -- provide better returns than the initial investment.

And if I could finish off my questions with a question on natural gas storage in general. Just wanted to see how you would characterize what is in equilibrium market in Western Canada for natural gas storage. Obviously, like you mentioned a lot of LNG coming on board. There's probably a lot of other demand for local gas usage as well. But you also have your expansion, let's say, through the 69 Bcf. There's another one in Aitken Creek as well. So just curious how you would characterize what is an equilibrium market.

I'll make a general comment and maybe Randy can follow-up. I think you've seen a material uptick in production happen in Western Canada as a whole with -- on the back of LNG and potentially even more natural gas production coming to support potential data center opportunities in Alberta. But we've seen natural gas storage remain fairly constant in Western Canada outside of our expansion and expansions at Aitken Creek. So I think the amount of aggregate storage available per molecule production has actually come down over the last several years. And given the nature of some of these larger facilities, if there are operational disruptions, you will need more storage going forward.

So, is there anything you wanted to add to that, Randy?

Yes. I think where Dimsdale is located in the -- on the NGTL system, it's upstream of what we call the upstream of James River, and that's where a lot of the new production is coming on. So the changing in flows really helps support gas storage in that area. And also with LNG Canada, that demand, we see that as a big pull. And so, again, that's why natural gas storage is really in high demand in that area of the system.

Your next question is from Robert Catellier from CIBC Capital Markets.

Lots of interesting things on the business development side. I wanted to follow-up on the Dimsdale gas storage here. I wonder if you could just describe how you're approaching the optimization piece of gas storage. Maybe you could comment on how much of your [ working ] capacity is contracted versus available for optimization and how you plan to manage that?

And then the second part of my question has to do with the implications of storage for the rest of your value chain. So I'm wondering if there's an opportunity to leverage the scarce capacity for integrated deals that include more than one service.

Yes. That's a great question, Rob. Storage is very valuable. And I think that's how -- that's why we chose to purchase Dimsdale with the Pipestone assets as we could offer an integrated service for our customers, and that will be something we'll progress as we look at Pipestone III and subsequent expansions of Dimsdale.

I think on your first question is, from a high-level perspective, we've been on this path to increase the stability of our cash flows as we move forward. I think similar to what we were doing in global exports, we want to make our gas storage cash flows more stable over time. So this phase of expansion is basically 100% backstopped by firm service take-or-pay contracts. Our expectation is the next phase will be very similar.

The only thing I'll add is that, the storage that we bought, the working storage of 15 Bcf before these expansions, even that wasn't used by us for optimization. Most of that was parking loans where we were being paid on injection and withdrawal. So we weren't really exposed to the commodity price there. And as those roll off, we will be looking to contract them longer term for that additional or the initial 15 Bcf on the same basis that Vern touched the expansions would be contracted on.

Right. So you're not going to have a lot of optimization exposure other than what you need for operational flexibility?

You bet.

Yes. Okay. And then assuming you come to an agreement on MVP, which seems likely, what are your expectations in terms of timing for a closing date? It seems pretty straightforward, but there's a government shutdown. So I'm just wondering about the regulatory approvals.

Yes. Great question, Rob. So look, I mean, in terms of regulatory approvals, we believe that any buyer would just need a FERC approval. And our understanding is despite the government shutdowns, there is a smaller staff at the FERC that's still trying to move these type of applications forward. And the type of time line that we would be looking at is anywhere between 30 to 90 days for FERC approval. But that's the only approval that we anticipate needing to get the transaction closed. And obviously, any announcement, obviously, would be seen positively by the rating agencies even if a potential close slipped into the next calendar year.

Okay. And then last question for Blue. I just wanted maybe a more detailed update on the ERP initiatives, particularly District SAFE in D.C. As you're trying to get an extension and then have this separate program approved. I just wonder what the tone is like with the -- in this process. Are we likely to see a shorter extension of District SAFE? Or will it -- is there an appetite in the regulatory body for a longer-term program?

Yes, Rob, good question. A couple of things I'll note. So we've been working that particular, as you recall, we filed Pipes III is where we started based on the time line. Commission asked us to refile Pipes III, which we did. They've granted us 2 extensions so far, and we filed for a third. There isn't anything in the conversation that leads us to believe that there's any apprehension to getting that process done. I think it's just a timing and a demand. They're also working diligently on our rate case, which we're hoping to have done by the end of the year. So I think it's a timing issue on the workload that they're trying to balance. I don't anticipate any particular challenge to that as we sit here today.

In their communications, they've been pretty transparent some of this very publicly, of course, on it. So we're expecting -- we asked for a 3-year program under District SAFE. The extensions they've approved have been in line with the spend profile of Pipes II and District SAFE. So all of those data points lead us to believe it's just a timing and workload effort. So we remain positive that there's a good outcome coming our way.

Your next question is from Ben Pham from BMO.

I'm just wondering beyond the assets you mentioned today with expansion opportunity, like is there other assets that you can point to that utilization is ramping up quite a bit that you would start to think about or consider sanctioning expansions?

Yes. I think our actions in Northeast BC have been very positive. I think we talked about how our Townsend facility is approaching -- has seen volume growth and then North Pine, which we recently, not too long ago, had done a brownfield expansion is also achieving record volumes. I think as you see more drilling in the BC part of the Montney, for sure, you're going to see the need for more incremental facilities from us.

Yes. And I would add to that, our Harmattan facility has a lot of activity. And I do think Harmattan is a consolidator around that area. So that potentially could lead to a small expansion at Harmattan.

Okay. It just sounds like from all your commentary today and all the announcements, there's a long list of midstream opportunities you're working at favorable returns. Does that suggest then that your capital allocation exhibit that even balance between the 2, that's a good picture of how it's going to look in the next couple of years?

Well, I think, Ben, the utility is going to get the majority of the capital just because the ongoing need there is very high. And there's -- as we've talked many times about a 20-year backlog of aging infrastructure that needs to get replaced with more modern infrastructure. We have, for sure, a very strong project hopper in midstream. The thing to remember is midstream projects tend to be smaller in size and take a couple of years generally to build out. So the amount of capital we actually spend in each individual year for midstream capital tends to be muted.

Okay. Got it. And then my last one on the Blythe power gas plant out in California, we've seen a couple of favorable recontracting outcomes years and years ahead of expiry. Is there opportunity for you, AltaGas then to look at crystallizing something similar to that?

I mean, look, from our standpoint, we're -- we just started a new contract that expires in 2027. I mean, we would always actively participate in those kind of discussions if they're constructive with the end users. But there's obviously still a need for thermal power in California and Blythe will continue to be a major contributor to meeting energy demand there. So if there's an opportunity for us, we would pursue extensions of the existing contract for sure.

Okay. So the base case then, James, is more a typical like 12, 18 months before. I only ask because we saw one that cut 2030 extension so four years ahead of time, which we haven't seen before. So it sounds like the base case is more the typical cycle.

Yes. Right now, our contract expires in '27. That is the base case. But like I said, those kind of discussions are always very fluid, especially with data center demand that's starting to emerge across the lower 48, right? So that could be something that initiates a discussion ahead of the time line that we've experienced historically from a renewal standpoint.

[Operator Instructions] And your next question is from Patrick Kenny from National Bank Financial.

I guess just at a high level, I know you're still a month away or so from finalizing guidance for 2026. But just based on what you can see today, curious if you had any thoughts on a few of the headwinds and a few of the tailwinds that you expect will come into play or be sustained next year relative to this year?

Yes, Pat, it's James here. Yes, we're actually about 5 weeks away from getting our budget approved and rolling out 2026 guidance. We're obviously still working through trying to lock down where our CapEx is going to be. But in terms of what we're seeing as tailwinds right now is FX is a bit of a tailwind relative to last year. Obviously, we continue to see strength in volume exports at the global export platform, and we continue to see some strong rate base growth, and we expect to have new rates in place in 2 of our 3 jurisdictions -- sorry, 2 of our 4 jurisdictions within the utility footprint. So those are some of the tailwinds that we see as well. But very premature for us to actually to give you a range here, but we would expect a slight uptick in CapEx, just given some of the FIDs that we have here relative to where we were in 2024. But some of the headwinds and tailwinds are the things that I mentioned that we will incorporate into our guidance when we roll it out to the market.

Got it. And then, James, just on the leverage front, I know there's some noise in the trailing ratio. But as you look ahead to year-end, assuming you are able to close the MVP sale, are you still expecting to end the year with debt-to-EBITDA at or below the 4.65x? And then I guess, as you look to bring some additional midstream growth into that secured bucket, you mentioned the uptick in CapEx next year. But should we expect the incremental growth to be more back-end weighted within the 3-year funding plan? Or do you still have some dry powder through '26?

Yes. Let me try to address the second part of your question first, and then I'll come back to the debt target metric, right? I think some of the comments that we made a little earlier on the conference call about our investment capacity growing is what's going to give us the ability to fund some of these additional FIDs and maintain our leverage metrics, right? Pipestone II is coming online, and you touched on the other major catalyst or increase to our investment capacity, and that's the completion of the MVP process. So I do think, even though CapEx grows, our investment capacity will grow relative to 2025 to be able to fund it as a result of those 2 points.

On the debt target, look, what we want to say is that, the 4.65x is still something that we feel we're going to achieve at year-end because of the completion of the MVP process. But we do want to remind people that the 4.65x, we're going to fluctuate a little bit around that because we do have a seasonal business if you're looking at it on a trailing 12-month basis, right? And I'll give you the perfect example of that seasonality. If you look at Q3, we were clearly an injection season within our natural gas utilities where we're putting gas into storage to be able to service customers in the winter, right? So that basically takes up some working capital, and that's what pushed us up above the 4.65x target at the end of Q3. And the other contributor was that we just had a higher FX rate relative to where the Q2 FX rate was. So those 2 would have us fluctuate a little bit because of seasonality, but we fully intend to get to that target by year-end once we complete the MVP process.

Okay. That's great color. And then just for Vern, maybe with the federal budget coming out next week, wondering if there's anything you'll be looking for on the regulatory front in terms of perhaps repealing certain policies or legislation that might help you to firm up some of the FIDs here for your other midstream growth projects?

Well, I think, Pat, over the next few years, we're in really good shape because all of our projects, we have the permits in hand to go ahead and build these things. I think longer term, what would be helpful for the industry as a whole would obviously be egress for both natural gas and crude oil. I think as everyone knows, drilling for natural gas in Western Canada is for LNG and then to provide liquids, condensate and LPGs that can be used either in the oil sands or elsewhere. So anything that helps production grow in the Western Canadian Sedimentary Basin will be beneficial for us as we have our strong position on maximizing netbacks for producers on the LPGs.

There are no further questions at this time. Please proceed with the closing remarks.

Great. Thank you. Yes. So before we conclude the call, we did want to highlight the REEF construction video that was put on our website yesterday. The updated video is on our infrastructure landing page and provides some nice highlights of recent construction progress at REEF. So definitely worth checking out.

Thanks again to everyone for joining this morning. We hope you have a great day.

Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Second Quarter 2025 Financial Results Conference Call. My name is Jenny, and I will be your operator for today's call. [Operator Instructions] As a reminder, this conference call is being broadcast live on the Internet and recorded.

I would now like to turn the conference call over to Aaron Swanson, Vice President, Investor Relations Please go ahead, Mr. Swanson.

Good morning, and thank you for joining AltaGas' Second Quarter 2025 Results Conference Call. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website.

Speakers this morning will be Vernon Yu, President and Chief Executive Officer; and James Harbilas, Executive Vice President and Chief Financial Officer. We are also joined by Randy Toone, President of Midstream; Blue Jenkins, President of Utilities; and Jon Morrison, Senior Vice President of Corporate Development and Investor Relations.

We will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 of the presentation. As usual, prepared remarks will be followed by a question-and-answer session.

I'll now turn the call over to Vern.

Thanks, Aaron. Good morning, and thanks for joining us today. It's great to be here this morning to discuss our strong Q2 results. We're pleased with our Q2 performance, where we continue to execute on our strategic priorities and our strong Q2 results put us in good shape to meet our 2025 guidance.

Let's start with our strategic priorities. We've continued to maximize return on our assets by increasing midstream throughput and reducing operating costs in our Utilities segment. We've actively derisked our portfolio through long-term tolling agreements, and we're pursuing weather normalization in D.C. Our balance sheet is stronger with trailing leverage now below our target. And we're executing on our growth plans with investments in modernization programs and system expansions at our utilities, and we've made strong progress on the construction of Pipestone II and REEF. Through it all, we've maintained disciplined capital allocation to drive shareholder value.

I'm going to start with some highlights from the quarter, provide an update on our major projects, talked about optimization and expansion opportunities at REEF and review the macroeconomic tailwinds that are driving growth in both of our businesses. I'll then turn it over to James. He'll review Q2 in more detail, give you an update on 2025 guidance and our longer-term financial outlook.

Let's start on Slide 4. We delivered normalized EBITDA of $342 million in the second quarter, 16% higher than Q2 2024. Normalized EPS was $0.27, nearly double the $0.14 per share we recorded in 2024. Customer demand for open-access export terminals continues to be robust. And this has led to new agreements with Keyera, BASF and Pembina.

We have now firmly exceeded our global exports tolling target of 100,000 barrels per day for the 2027 NGL year. Given the commercial support that we've seen for our global exports platform, we're looking to advance some debottlenecking opportunities at REEF, which I will discuss in more detail shortly.

We filed a new rate case in Virginia yesterday, seeking a $65 million increase in base rates that will be effective in early 2026. We also continue to advance the DC rate case and our DC ARP extension. We're expecting resolution of both of these items by the end of 2025.

Within midstream, we delivered record second quarter global export volumes, almost 128,000 barrels per day of LPGs to Asia. Midstream throughput also grew by 6% year-over-year across the balance of our midstream facilities, led by our Montney assets.

Utilities also performed well in the quarter, driven by modernization investments, improved asset optimization and colder weather in Michigan. We're excited about the long-term outlook for our utilities, which continues to deliver the most reliable and cost-effective energy for space heating in our jurisdictions.

The delivered cost of electricity is almost 4x that of natural gas. And we're operating in a period of growing energy and security, particularly in the PJM market, where concerns about power capacity shortfalls are rising. In response, we're making significant investments to connect new customers and modernize our network to enhance long-term safety, reliability and energy security. This includes securing regulatory approval for projects like the Keweenaw Connector Pipeline and advancing infrastructure to serve emerging opportunities such as data centers, where we are progressing projects across Maryland, Michigan and Virginia.

We will also continue to advocate on behalf of our customers against public policies that undermine reliability, affordability and customer choice. The local economies in Maryland, Virginia, D.C. and Michigan can't grow without affordable and reliable energy, and it's our job to provide it to our customers.

Let's turn to our midstream growth projects starting on Slide 5 with REEF. Construction on REEF continues to be on time and on budget. Approximately 70% of the project's costs are now incurred or committed with 60% of the total capital cost under fixed-priced EPC contracts. The earthworks phase is complete and concrete foundations are now being poured for the LPG bullets and accumulators.

Off-site fabrication in Asia is also progressing according to our execution plan. Propane and butane bullets are over 90% complete and the three LPG accumulators are over 85% complete. Major equipment will arrive on site in Q4 of this year.

Progress on the Jetty continues to recover from weather delays seen in the winter construction season. Overall, the Jetty is around 40% complete with almost 60% of the permanent piles driven into the seabed. Construction efficiency has ramped up as we've now entered our first summer construction window.

On the ground, we've moved to the construction of the rail loop, the on-site roads and the utilities corridor. Commercially, we continue to see strong demand for our open access terminals, which gives us conviction to advance REEF's optimization and expansion initiatives.

Slide 6 outlines the optimization and expansion opportunities we're currently evaluating beyond Phase 1. Optimization 1 has the potential to add up to 20,000 barrels per day of propane export capacity. We have sufficient commercial support to advance Optimization 1, and we are working through the final stages of detailed engineering and cost estimates. Our goal would be to complete Optimization 1 within 12 months of REEF's in-service date.

Optimization 2 is a larger project with the potential to add up to 60,000 barrels per day. Timing of this project will be dependent on market demand and availability of LPG supply. But we will be positioned to deliver the project by the end of the decade, further expanding global markets for Canadian LPGs.

Beyond these optimization projects, we will also progress work for future expansion phases where we are evaluating the potential for further LPG expansions, including the potential to add other products like ethane. The global waterborne trade for ethane has grown considerably over the last decade. And we've received strong interest from Asian buyers looking to diversify their long-term feedstock sources. To unlock the ethane opportunity, we need to solve a few technical hurdles and ensure ethane exports can comfortably coexist with strong petrochemical demand in Western Canada.

We're also making excellent progress on Pipestone 2, which is shown on Page Slide 7. We're on track to be in service by late 2025. Facility construction and assembly is the only major remaining work stream, and we are now over 85% complete. The project is fully contracted under long-term take-or-pay agreements and all the project work has either been completed or is under fixed price EPC contracts.

Let's move to Slide 8. Our midstream business is well positioned to match increasing Asian LPG demand with increased Canadian LPG supply. Led by petrochemical demand in China, Asian LPG demand is expected to grow by more than 30% by 2030. Asian propane demand for PDH facilities, which has been growing at 15% per year since 2020 is expected to grow by another 300,000 barrels per day through the end of 2026. Canadian supply continues to be driven by the development of the Montney. The Montney is very liquids-rich, and we're seeing improved liquid yields from the play.

Slide 9 highlights why we've made considerable infrastructure investments in the Montney over the past decade. More than half of our G&P and fractionation assets are positioned in this region to serve growing demand for gas processing, liquids handling, fractionation and global exports connectivity.

Turning to the macroeconomic outlook for our utilities, which is found on Slide 10. We continue to see rising demand for all forms of energy across the U.S. with natural gas being critical to meet long-term energy needs. U.S. natural gas demand is increasing with coal-fired power plant retirements, increased industrial activity and data centers. The constructive outlook for natural gas reinforces our continued investment in modernization projects where we've invested more than $2 billion since 2018. This has driven an 8% annual rate base CAGR since 2019, and we expect that to continue for years to come.

Our modernization runway remains extensive. More than 30% of our system is made up of vulnerable pipes, which we will replace over time to enhance safety and reliability of our network. These investments will allow us to continue to deliver the most affordable and reliable energy for our customers.

The expected increase in energy demand coming from AI and data centers is set to accelerate natural gas demand through 2030. This is particularly prevalent in PJM. We're seeing a significant increase in the gas-fired power generation interconnection queue. Currently, 16 gigawatts of power interconnections are backlog, nearly double the amount from last year.

Lastly, I want to reiterate our 2025 strategic priorities, which we show on Slide 11. We'll continue to maximize the value from our existing assets, actively look to reduce our commercial risks, continue to drive down long-term financial leverage, advance our strong organic growth projects and remain disciplined allocators of capital.

I'm very excited about AltaGas' future and the value we can unlock through the execution of our strategic priorities. And with that, I'll turn it over to James.

Thanks, Vern, and good morning, everyone. We're pleased with our strong second quarter performance, the continued operational execution across the platform and our progress on our strategic priorities.

I'll start by providing a more detailed review of our financial and operating results in the quarter, then discuss the strong progress we have demonstrated on balance sheet deleveraging and close by discussing the 2025 outlook and our value proposition.

Turning to Slide 12. The Midstream segment delivered a strong quarter, driven by solid execution across our value chain. Normalized EBITDA for the second quarter was $215 million, up 23% from $175 million in the same period last year. This performance was supported by record second quarter export volumes, which increased 4% year-over-year and were accompanied by stronger realized export margins. We exported nearly 128,000 barrels per day of propane and butane across 20 VLGCs during the quarter. This included more than 80,000 barrels per day across 12 ships from RIPET and nearly 47,000 barrels per day on 8 ships from Ferndale, the equivalent of a ship departing our docks every 4.5 days.

Export margins included some benefit from our ability to capture premium pricing amid U.S. trade tensions with select merchant cargoes delivered to China when importers were looking for alternatives to Gulf Coast LPGs.

Tolling volumes were relatively consistent year-over-year compared to the rising levels we have seen in the past couple of quarters. As a reminder, while long-term contracts enhance cash flow stability, they carry lower absolute margins.

Across our broader midstream footprint, we continue to benefit from strategically located infrastructure and a high-quality customer base.

G&P volumes increased 8%, led by a 12% rise in Montney volumes, including Townsend, Pipestone I and Blair Creek. Townsend volumes continue to benefit from increased deliveries under the 100 million cubic feet per day gas processing contract we signed in late 2024 with a major international energy company. At this stage, we have seen approximately 60% of the volumes associated with that contract now come online with the balance expected to ramp up during the fourth quarter of 2025.

From a risk management perspective, 98% of our expected 2025 global export volumes are either tolled or financially hedged. with an average FEI to North America spread of approximately USD 18 per barrel on the non-toll volumes.

We've also substantially hedged our 2025 Baltic freight exposure through a combination of time charters, financial instruments and tolling arrangements. Finally, midstream results included higher equity earnings from the Mountain Valley Pipeline, which started operation late in the second quarter of 2024. As the project transitioned into service, AFUDC contributions were modest last year, leading to a large year-over-year contribution this quarter.

Turning to Utilities segment on Slide 13. Normalized EBITDA was $134 million, up 10% from $122 million in Q2 2024. Growth was driven by modernization investments, improved asset optimization contribution and colder weather in Michigan, where we do not have weather normalization, partially offset by lower retail contributions in the quarter.

As we have messaged in the past, we have taken strong steps to manage our cost structure and keep operating expenses in line with our approved rate structures. We deployed $160 million of capital in the utilities during the quarter, including $96 million for modernization programs and $21 million for new meter connections. For full year 2025, we expect to invest over $700 million in utilities as we continue to make critical investments for the future. Modernization will remain a key focus as these programs improve safety and reliability while also reducing leaks and lower long-term operating costs.

We have active modernization programs across all four operating jurisdictions with $1.7 billion in preapproved spending, supporting steady and ratable growth. On the regulatory front, we filed a $65 million rate case in Virginia yesterday, net of the SAFE surcharge with a requested 10.85% return on equity. With a 120-day statutory time line, we expect interim refundable rates to be in effect by 2025 year-end.

In D.C., we continue to advance the 2024 rate case filed last August as well as our district SAFE application to extend our modernization program into the future. We expect resolution on both by 2025 year-end.

We continue to progress data center business development initiatives with active opportunities in Virginia, Maryland and Michigan. FEED studies are underway for both primary and bridge power solutions with pipeline interconnect infrastructure. These projects are being pursued on a derisked basis through traditional rate-regulated investments with unique rate structures.

In the Corporate and Other segment, we reported a normalized EBITDA loss of $7 million compared to a $2 million loss in the second quarter of 2024. The year-over-year change was primarily due to higher G&A costs, primarily from long-term incentive plans.

Turning to our outlook on Slide 14. We are reiterating our 2025 guidance. While we've seen both tailwinds and headwinds so far this year, they have largely balanced out.

There are no major changes to our 2025 capital budget shown on Slide 15. We expect to deploy $1.4 billion with 51% allocated to utilities and 45% to midstream as we expect to complete Pipestone II prior to year-end while making material advancements on REEF.

Most utilities capital will continue to support ARP modernization programs and system betterment, with the remainder targeting new business and customer connects. This will include commencing work for the Keweenaw Connector, which is expected to come online in early 2027.

As shown on Slide 16, we reduced adjusted net debt by approximately $215 million quarter-over-quarter and are in line with our long-term debt target at 4.6x, including 50% debt treatment for preferred shares and subordinated hybrid debt. As a reminder, our revised 4.65x leverage target now includes 50% debt treatment for preferred shares and hybrids.

We continue to work through our monetization process of our interest in the Mountain Valley Pipeline with proceeds to be used for leverage reduction, which would further bolster our financial flexibility and improve our long-term investment capacity. The asset has performed above expectations since going into service and benefits from being expandable through additional compression on the mainline and extendable into North Carolina through the Southgate project, both of which are progressing towards near-term final investment decisions.

In closing, we delivered a strong second quarter, reinforcing the value of our diversified infrastructure platform and the operational execution that drives it.

As highlighted on Slide 17, we have a compelling investment proposition with low-risk infrastructure that provides stable and growing earnings and cash flows. We have strong organic growth across the platform. We have been disciplined allocators of capital over the past six years, and we'll continue to focus on that into the future.

The results of this focus can be seen on Slide 18. We've achieved industry-leading normalized EPS, EBITDA and deleveraging metrics and have rewarded our shareholders with exceptional total shareholder returns.

And with that, I will turn it back to the operator for the Q&A session.

[Operator Instructions] Our first question comes from Jeremy Tonet from JPMorgan.

This is Eli Jossen on for Jeremy. Congrats on the strong quarter. Just wanted to start on the LPG contracting you laid out today, some of the new announcements. Should we think about these as simple fee times volume arrangements? Or are there more margin sharing elements with commodity price exposure?

I'll start here, Eli. These are typical tolling agreements where effectively, we earn a return on capital for our investment and the operating costs are passed through to the customer. So it's just more of the same.

Got it. And you touched a little bit on the MVP expansions nearing FID. Would you say those are the primary gating item for sale at this point? Or what inning should we think about for the sale discussions overall?

Yes, Eli, it's James Harbilas here. I would say that we're in the late innings of the process and definitely approaching the finish line. We continue to be committed to completing a transaction, and there is strong interest throughout the process from global infrastructure funds. But as I indicated on our Q1 call, we are dependent on the operator to close out operational due diligence. And as you touched on due diligence related to the expansion projects, both of which are advancing extremely well, and we're seeing strong interest in the open season.

But being -- EQT has been a great partner to work with. But any time you have an intermediary, there could be slight delays in terms of information flow related to the due diligence items. So I would say that, that is the biggest factor contributing to a slight delay in timing here.

And your next question is from Maurice Choy from RBC Capital Markets.

I just wanted to touch on the midstream business for a moment here. Just curious how you think that over the long term, how NGL molecules will move differently from how it does today. Obviously, today, you've got quite a bit of fractionation across your facilities, but there's also a big hub in Fort Sask. A lot of liquids-rich growth is coming out of Northeast BC and Northwest Alberta and a lot of exports heading out west through your terminals as well. So just curious how you see flow changing over time.

Okay. Maurice, it's Vern. I'll start. And then if I miss anything, Randy can jump in. I think our view is that propane and butane need to go west. And the most cost-efficient way for our customers to get it west is through rail loading facilities directly in the Montney, and you've seen us do that at North Pine and there's other customers out there who have similar ideas. So I think from an economic basis, it's best that the product that we're moving go directly to the West Coast and skip the Port Saskatchewan hub there. Obviously, condensate needs to go back into Alberta ultimately to the oil sands. So there's kind of a mixture of infrastructure required with propane and butane going west and condensate going east.

Is there anything you want to add to that, Randy?

Yes, we see NGL growth coming in obviously, Northeast BC, where we do think that the LPG will go west where it's the best economics. But we also see growth in Northwest Alberta and the Montney and that those barrels will likely go to the port, but we do think that the LPG ultimately from the port will go west as well.

Maybe along those same lines, do you see the potential for, I guess, the second hub and where you are right now growing larger over time and so much LPGs are heading out west?

Yes. I think we're focused on incremental fractionation at North Pine, and that's something we're actively working on with some very large volume customers. And hopefully, we'll be able to talk more about that later this year. And as you see these customers work on their development plans, I think they're also looking at potentially some of their own infrastructure that would be aligned with what we're doing.

Understood. And if I could just finish off with a question on utilities. I know in one of your slides, I think it was Slide 4 you've highlighted that data centers are under evaluation in the utility segment. So far, across the earnings season, not just yours, but everyone else's as well, we've continued to hear that there's a lot more investments to power AI that just keeps getting stronger.

I know historically, you've mentioned that this could just increase your rate base growth to, say, 9%, up from 8% currently. Have you seen any evidence that this may go beyond 9%? Or is it more about making a runway of growth a little bit longer?

Well, I think the determined the gating for like a full flurry of data centers in our markets, which is really the DMV at Michigan is the full path of getting that energy to the data centers. So you need visibility into long-haul pipes, you need visibility into what we can do with our distribution pipes. And then ultimately, the data centers would be looking to procure the equipment that they need to actually generate the power. And I think all along the value chain, there's multiple parties working on making that happen. So I think the way I'd characterize it, we continue to see lots of customer interest, but it is taking a while to get all of those moving parts put to bed.

Blue, is there anything you wanted to add?

No, Vern, I think you're spot on. The components that we control, we're very comfortable with timing and managing those. As Vernon points out, we're trying to help facilitate both upstream of where we are with access to long-haul capacity and supply, if required and downstream turning those molecules into electrons. So I think Vern nailed it.

And your next question is from Sam Burwell from Jefferies.

So obviously have plenty of growth avenues ahead of you in midstream. But just curious to the extent you need to prioritize things from a capital standpoint, how do the returns or build multiples or just general opportunities compare across exports versus frac versus gas processing?

Well, I think exports is definitely -- once we get into these optimizations and potential expansions at REEF are going to have the lowest build multiples just because we've prebuilt a bunch of the infrastructure with REEF Phase I, where we are prebuilding the dock and the rail loop to accommodate all these other phases of REEF. I think fractionation would be then the next most attractive investment opportunity followed by gas processing.

Okay. Understood. And then with respect to MVP, is it fair to assume that at least the lion's share of those proceeds are all recycled into growth CapEx given where you guys have leverage now?

Yes. Look, I do think that we would basically use it to immediately reduce leverage and give ourselves a little more headroom and obviously, a lot more investment capacity that maybe we can then allocate to these growth projects as they start to move forward through our development pipeline and we start to lock down costs and start to lock down commercial underpinning so that we can declare an FID. But the immediate use will go to deleveraging. That will create additional investment capacity and headroom. And then obviously, yes, we would be able to fund more of these projects that we're moving through our development pipeline.

And your next question is from Patrick Kenny from National Bank Financial.

Yes, just on the upsizing of REEF here, the Optimization 1 opportunity. Can you just clarify whether or not the incremental contracts announced this morning, combined with the other commitments locked in through the quarter, effectively underpin the 15,000 to 20,000 barrels a day from a commercial standpoint?

And then just thinking about the timing around securing commitments for Optimization 2 capacity. Curious how we should be thinking about the timing of securing these volumes as well as the quantum of capital or the build multiple relative to the first optimization?

Okay. I'll start and Randy can correct me if I missed something. I think for Optimization 1, commercial isn't the gating item. I think we're very comfortable with the level of tolling that we have in our portfolio for us to have enough commercial support to go ahead with that. Really, the gating item on Optimization 1 is a couple of things, making sure that this optimization doesn't impact the in-service date of Phase 1 of REEF and then finalizing our Class III cost estimate. Obviously, this optimization will have an extremely attractive build multiple, and we're quite excited about the project. But really, we're just making sure our -- I's and T's are dotted on the capital front.

With Optimization 2, there's a little bit more work to be done here. I think we're working through detailed engineering and costing. We're not going to have that done probably until sometime in the first half of 2026. And then we do need to make sure all of our stakeholders are fully aligned with us on this particular project. This one has a very minimal amount of permitting, and we need to start that process as well.

And then finally, commercially, we want to time the project to make sense with growing LPG supply in Western Canada. So I think Optimization 2, again, will be a very, very attractive project, but we do have a little bit more work to do here.

Do you want to add anything, Randy?

No, I think you covered it well.

Okay. And then I guess from a customer mix perspective for your exports business as a portfolio, despite these midstream customers having strong investment-grade credit profiles.

Just wondering, Vern, if you're looking to diversify your customer base going forward with more downstream or even large upstream customers? Or do you remain sort of agnostic to customer types as long as they are a strong counterparty?

Yes. It's critically important that we have strong counterparties. If their credit rating is below investment grade, we would be looking for credit support. I think when you look through our contract mix, we support pretty much every producer in Western Canada with our export facilities, and we have numerous offtake customers in Asia, again, with very strong balance sheet. So some of these things we haven't disclosed for commercial reasons, but the portfolio is quite diverse and very strong from a credit perspective, Patrick.

Got it. Okay. And then last one for me. Just looking at the leverage ratio already being where you wanted it even without the sale of MVP. But I couldn't help but notice the omission of the 5% to 7% dividend growth guidance through 2029. So I just wasn't sure if you're thinking about potentially retaining more cash going forward in light of all these growth opportunities or if you're just being a little bit more cautious in light of geopolitical or capital markets uncertainties.

No, Patrick, it's James here. Like we're still committed to the 5% to 7% dividend growth. I mean that's obviously underpinned by strong growth across the entire platform, inclusive of utilities. And given where the payout ratio is, we feel very comfortable reiterating the guidance with respect to dividend growth as well.

Okay. Great. But I guess in terms of allocating the potential proceeds from MVP, just in terms of dry powder for new growth opportunities versus previously, I think you had earmarked some of those proceeds for the balance sheet on a permanent basis. Just wondering if there's been any change there.

No, I tried to address that in an earlier question where the immediate use will go to further debt reduction, and it will give us the opportunity to build a little more investment capacity and some dry powder. And as we work our way through these projects and get them to the state where we can declare FID, and we will start to allocate some of that capital. So right now, it's just going to create a little more dry powder for us to be able to continue our growth trajectory.

And your next question is from Robert Catellier with CIBC Capital Markets.

Just wanted to follow up on the LPG export business and maybe an early look into 2026, given the higher tolling levels and what appears to be tighter margins than the very strong margins experienced in 2025 on a spot basis.

I think we're -- we'll give you that, obviously, when we give guidance later this year. I think the percentage of tolling will be ballpark similar to the percentage of tolling in 2025. Obviously, there's been a huge amount of volatility in 2025 on merchant FEI to Fort Saskatchewan spreads. There have been opportunities where Canadian propane is obviously priced higher than FEI. So we're working through all of that, but we're pretty confident that our results in 2026 will be strong as well.

Okay. And what do you see as the implications of Keyera's acquisition of the Plains NGL business, should that close. Do you see an opportunity for more volumes similar to previous contracts signed with Keyera? Or do you anticipate any other changes in the business?

Well, I think from a high level, we hadn't historically done a lot of business with Plains. Plains has been historically focused on moving NGL volumes to Eastern Canada. I think Keyera with a broader knowledge of NGL markets will have an opportunity to optimize their NGL portfolio as far as pointing barrels to different markets. So we look forward to doing more business with Keyera as we move forward.

Okay. And last one for me, maybe for Blue. I'm just wondering what the practical implications are of the -- next Generation Energy Act in Maryland. -- specifically as it relates to rate base growth and the asset replacement programs.

Yes. Rob, good question. As you know, Maryland is very active for us. So we were happy to come out of the legislative session with support to continue the accelerated pipeline replacement program. So as you know, we've got a remaining three years in there. So we're happy with that.

As Maryland continues to wrestle with their balance on what they're going to do with their economic growth drivers as well as how are they going to hit their stated climate goals. They continue to look for different alternatives. We're clearly not supportive of anything that limits customer choice. That's not news to you or anyone else who follows us.

And of course, we're very supportive of the utility model where providing safe, reliable, affordable gas to consumers within our operating jurisdictions that drives economic output for the region is important.

So you should expect to see us challenge anything that comes counter to that, just as you've seen us do with some of the gas ban activity in Maryland. So we're in ongoing dialogues with the regulators. We have filed appeals to things that we think don't make sense. And as we've done in the gas band, you'll see us use the leg or the legal process to continue those challenges.

So we continue to work our way through it. I think the reality for us at a macro is this that those type of policies that make it harder to do business as an investment process, whether it's building homes or building new businesses or whatever it may be. The region is fairly small. And so what it tends to do is just push those economic activities across the river into one of our other jurisdictions.

So it may simply just be a fact where it moves some investment into Virginia, for example, as opposed to Maryland. But we're trying to work with Maryland to help them understand the impact of those decisions and why it's important that they look at the broader picture.

Let me just follow up. I think, obviously, it's -- in our view, it's just bad policy. So we're going to fight this very vigorously in the courts. And -- the fact is we deliver for space heating a product that is 4x cheaper than the electric alternative. And in fact, we do it on a lower emissions basis when you consider that PJM is a highly carbon-intensive generation mix. So we will ramp up our advocacy efforts in Maryland and reiterate to regulators and policymakers that this is harmful to the ratepayers.

And your next question is from Jessica Hoyle from Scotiabank.

Just one for me on the global exports business, but it appears that most ships out of RIPET are going to China versus Japan previously. Can you just speak to these dynamics and the impact on margin?

Jessica, it's Randy Toone. We normally have been selling our cargoes into Japan or South Korea. With the tariff noise, we have been able to sell some cargoes into China. And we are -- one of the reasons why we're putting in the methanol removal unit at RIPET is to open up the Chinese market. So we always are looking at diversifying our offtake, and we have been successful lately selling into China. But we still see Japan as one of our main customers.

And the last question is from Ben Pham from BMO Capital Markets.

I wanted to ask about the LPG export positioning and the Trigon project. Can you update us on the status of the legal situation there? When do you expect that to clear? Do you expect Bill C-5 Prime Minister to be involved in superseding any sort of exclusive rights you have?

And then lastly, like any sort of customer feedback you had in terms of Trigon view that you need another alternative LPG export facility on the West Coast?

Well, I'll start. I think ultimately, the Port of Prince Rupert has jurisdiction in deciding what various terminals are able to do. The port -- PRPA has given us the right to export bulk liquids at REEF. And what we're most focused on is making sure that we get REEF built on time, on budget and provide that open access export capacity for the multiple customers that we have. Obviously, by progressing REEF Opti I, REEF Opti II, we have plenty of cost-effective capacity to make sure our customers have access to that Asian market. And you can see through the announcements that we've made over the past several months is that effectively, every major NGL aggregator has now committed very significant volumes to our projects. And similarly, while it's not publicly disclosed, every major NGL producer in Western Canada has made those commitments as well. And BASF is an indication of the offtake agreements we're seeing on the downstream side of things.

So we have permits. We have good relationships with our stakeholders on the ground. And then we obviously have line of sight to how we can continue to grow our facility. So that's the thing we're most focused on. I think PRPA will work through the Trigon litigation. They are looking for summary dismissal of that lawsuit from Trigon. And the actual court date for the hearing has now been pushed out, I think, till 2027. So the ability for Trigon to get the ability for them to actually export any LPGs through the court process has been pushed out materially. So all we can do is focus on what we're doing. And I think we're providing ample access for LPGs to Asia on a very cost competitive basis for our customers.

It sounds like then, Vern, with the debottleneck proposal, it doesn't sound like you need to wait for these legal challenges to clear, right, because you're basically just contracting out. There's a significant need for propane exports at the moment.

Absolutely. We manage what we can manage, and we have strong customer support.

Okay. Maybe one more for me with MVP. I know you're steadfast on monetizations and you go through the process. Is there any scenario where you may not want to sell MVP, just given its position and strong position in market expansion opportunities that it's better to hold that on yourself versus monetizing it?

Ben, it's James here. I mean, look, I think we've been pretty consistent about identifying it as a noncore investment. I mean there's obviously a lot of value to that asset, and we've touched on the expansion projects. We've seen a very robust process, and we're in the late innings. So we are committed to a transaction on that. And we feel that we can reallocate those proceeds to projects that we can build out where we have operational control, and we can continue to surface value through that operational control. And that's been a consistent theme for us when you look at our history as well in terms of some of the assets in our portfolio that we decided to monetize.

We always reallocated those proceeds to be able to build out assets that we directly operate. That's how we've been able to surface significant value and capture synergies across the entire platform for our shareholders. So that's the approach that we'll continue to use with MVP.

Thank you. This concludes the Q&A portion of today's call. I will now turn the call back over to Mr. Swanson.

Thanks, Jenny. Before everyone jumps off, I just want to point you to a recent video we updated on to our website, a REEF construction update. You can find it on the Infrastructure section of our website. It's a nice overview, and I think it was taken in early July. So it gives you a fresh picture of how things are progressing. Thanks again for everyone joining. Have a great day.

Thank you, everyone. You may now disconnect your lines.