AltaGas Aktie

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Third Quarter 2026 Financial Results Conference Call. My name is Joanna, and I will be your operator for today's call. [Operator Instructions] As a reminder, this call is being broadcasted live on the Internet and recorded. I would now like to turn the conference call over to Eric Swanson, Vice President, Investor Relations. Please go ahead, Mr. Swanson.

Good morning, and thank you for joining AltaGas' Third Quarter 2026 Results Conference Call. This call is being webcast, and we encourage following along the supporting slides that can be found on our website. Speaking this morning will be Vern 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; Crean Bushfield, President of Utilities; and John 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'll now turn the call over to Vern.

Thanks, Aaron, and good morning, everyone. I'll start by reviewing our Q3 results, provide an update on construction progress at Reef and our other growth projects. After that, we'll review the current state of global LPG markets. I'll then review recent regulatory outcomes at our utilities and wrap up by reviewing our 2026 strategic priorities. Sean will cover our quarterly results, discuss our 2026 guidance and close with an update on our leverage and capital plans. Let's start on Slide 4.

In Q3, we generated normalized EBITDA of $389 million, which is 45% higher than Q3 2025. In Q3, normalized EPS came in at $0.29 compared to $0.04 last year. Our record third quarter results were driven by our Midstream segment, which continues to benefit from strong operational performance and global LPG tailwinds. Based on our year-to-date performance and our outlook for Q4 and we expect to be towards the high end of our recently increased 2026 guidance range for both EBITDA and EPS. We exported a record 147,000 barrels per day of LPGs to Asia off the West Coast, loading 24 VLGCs. Midstream throughput continues to grow with Montney processing up over 20% year-over-year, driven by the addition of Pipestone 2 and higher throughput at our Townsend facility.

We recently took delivery of our fourth VLGC time charter in Japan and have executed agreements for two more vessels with deliveries anticipated in 2027 and 2029. These additional vessels mitigate us from uncertainties with global shipping rates. In utilities, we finalized rate case settlements in Michigan and Virginia, which will add USD 68 million in revenues. We're also expanding our footprint with an agreement to acquire roughly USD 20 million of rate base in Michigan's Upper Peninsula. Let's turn to Slide 5. In Prince Rupert Reef continues to progress with the highest risk work now complete. I'm happy to share that the project is now 90% complete and moving into commissioning. We remain on track for an in-service date in the first quarter of next year. Brief Optimization 1 remains on schedule for an in-service date in the second half of 2027 and we continue to advance the 60,000 barrel a day reef optimization two project, which we expect to FID before the end of this year.

Slide 6 highlights progress on the jetty. All of the piles and platforms have now been installed. This means the most complex phase of the in-water construction has been completed. In September, we completed installation of the [indiscernible] loading platform and loading [indiscernible] these last major work stream is the installation of the VLGC mooring system. The suction anchors will be installed this quarter with the balance of the mooring system scheduled to be completed in early 2027. Mechanical completion of our RIPET methanol removal project is only weeks away, and commissioning is now 25% complete.

The project will enhance our propane specs, and it will all be done by year-end. We continue to make good progress on our [indiscernible] storage expansions. Once complete, these expansions will add 36 Bcf of natural gas storage in the Alberta Mont. The pipeline for Phase 1 expansion has now been finished, and the Phase 1 facilities are more than 80% complete which puts us on track for a Q4 2026 in servicing. For Phase 2, the facility is 40% complete, and the drilling program is now over 50% complete with the wells expected to be done in early 2027. Turning to Slide 8. I want to provide an update on the conflict in the Middle East and its impact on the global LPG market.

LPG export volumes through the Strait of Hormuz remain more than 70% below pre-conflict levels with less than one ship exiting the street each day. Since the disruption began, we estimate that more than 240 million barrels of LPG supplies have lost. This has resulted in very high Asian LPG prices. with recent pricing approaching peak pricing. As the situation drags on, we've seen a significant increase in long-term export spreads. For the second half of 2027, export spreads have increased by more than $5 per barrel compared to 3 months ago. The conflict has also driven spot shipping rates to triple since early 2026.

While shipping rates are expected to stabilize in 2027, subject to Middle East supply returning to normal, our tolling contracts and our time charters isolate alpha gas on these abnormally high shipping rates. Finally, the disruption in Middle Eastern supply has highlighted the value of Canadian LPG exports with global buyers placing a premium on security and reliability. Slide 9 highlights why we are bullish on LPG supply growth in Western Canada. As Canada expands its access to global energy markets, we're seeing major LNG and crude oil pipeline projects advancing, driven by LNG projects and growing in-basin demand, Canadian gas supplies positioned to grow over 35% or 8 Bcf a day by 2035. We anticipate much of this growth will be in the liquids-rich Montney.

This, in turn, will drive higher LPG supply. We estimate that 8 Bcf per day of gas will add about 280,000 barrels per day of propane and butane, and all of these barrels will need to be exported to premium markets in Asia. In addition to natural gas egress, nearly 1 million barrels a day of sanctioned crude oil expansion projects are slated to come online by 2029. The crude oil outlook is even stronger if we include unsanctioned projects, which would add a further 2.4 million barrels per day of crude oil egress. This growth will be filled by oil sands production, increasing domestic demand for both gas and condensate, further supporting LPG supply growth in the basin.

Slide 10 show how we plan to connect this growing LPG supply to global markets. When Reef comes online, you will add 56,000 barrels a day of export capacity. The dock, the rail loop and utility quarter have been prebuilt to accommodate Reis's ultimate capacity of 500,000 barrels per day. When Reef and OPI and two are online, our global export capacity will grow by over 185,000 barrels a day to over 300,000 barrels per day by the end of this decade. Additional crude and natural gas egress will drive even more LPG supply growth. creating additional phases of rev expansion, which Reef can accommodate well into the 2030. We are also excited about the long-term potential of ethane exports.

Here, we have the opportunity to connect the oversupplied Canadian ethane market with strong petrochemical demand in Asia. This capacity can be added to REIT, and we are currently targeting to have an initial 60,000 barrels per day of ethane export capacity online in the early 2030s. Let's move over to our utilities. We've been very active with our regulatory filings, and we have recently had some constructive rate case outcomes, which ensures that we will make the appropriate returns on our rate base investments. Across D.C., Maryland, Michigan and Virginia, we have received approval for USD 115 million of incremental revenue. with an average allowed ROE of 9.67% across these jurisdictions. We also have USD 1 billion of approved modernization rate riders that provide predictable recovery that allows us to continue to make investments that enhance the safety and reliability of our system.

Our utilities will continue to focus on maintaining strong cost and capital discipline to support customer affordability. We will also continue to file regular rate cases to ensure inflation and non-modernization capital investments do not result in material ROE led. Finally, I'll close on Slide 12 with the progress we've made on our 2026 priorities. We continue to deliver on our strategic priorities by growing, derisking and strengthening the enterprise. We're optimizing our assets by delivering record global export volumes, seeing higher throughputs across our midstream assets and regularly filing rate cases in our utilities. At the same time, we're making great progress on our growth projects. We've been very disciplined in how we allocate capital and we're only investing in the best projects.

Taken together, we've extended our competitive advantages, improve the quality and visibility of our cash flows while creating a long runway for industry-leading shareholder returns. I'll now turn it over to Sean to walk through our results and outlook.

Thanks, Vern, and good morning, everyone. As Vern noted, we are very pleased with our record third quarter performance, delivering normalized EBITDA of $389 million, a 45% increase over the third quarter of last year. For today's call, I'll focus on our segmented financial results, discuss our balance sheet strength, 2026 outlook and finish with our investment proposition.

Turning to Slide 13. Our midstream business continues to exceed expectations, delivering $337 million of normalized EBITDA, an increase of 65% year-over-year. This sale performance was driven by the global exports platform, which delivered record export volumes and strong margins. From an operational perspective, we exported a record 147,000 barrels a day of LPGs across 24 VLGCs. During the quarter, we shipped an average of 89,000 barrels a day at RIPET across 14 ships and 58,000 barrels a day across 10 ships at Ferndale.

In total, export volume grew 11% year-over-year. We also saw continued strength across the balance of our asset portfolio with total volume growth of 12% led by our Montney assets. Plant utilizations remain strong with notable year-over-year throughput increases of 11% in the Gathering and Processing segment and 40% within extraction, while the fractionation in liquids handling segment benefited from strong margins during the quarter. Our strategic footprint in the liquids-rich Montney continues to drive performance, supported by strong producer activity and basin growth. In the Alberta Montney, extraction volumes at our Pipestone complex increased by nearly 3x year-over-year, owing largely to the addition of Pipestone 2.

The Pipestone complex had 94% utilization during the quarter as producers fill or exceed their take-or-pay commitments. In Northeast B.C., North Pine continued to operate near its 25,000 barrel a day frac capacity. Across our system, underlying basin growth and constructive egress dynamics continue to reinforce the value of our midstream platform, while our expansion projects position us to support further growth. In terms of risk management, of AltaGas' remaining 2026 global export volumes are either told or financially hedged. With an average FEI to North America spread of approximately USD 23 per barrel on non-tolled volumes. We've also substantially hedged all our 2026 Baltic freight exposure through a combination of time charters, financial instruments and tolling arrangements, which has been positive on the back of the spike in freight costs.

We continue to manage frac spread exposure and have 86% of expected volumes hedged at an average price of approximately USD 24 per barrel. Separately, we are managing through a labor strength at Trigon Pacific terminals, which began on October 2. Trigon provides rail logistics and birthing services for RIPET. And to date, we have seen no material impact to our operations. Following a Canada Industrial Relations Board ruling over the past 48 hours, we now expect some impact in the coming period. We are actively mitigating that impact and continue to expect results towards the upper end of our recently increased guidance ranges, including any potential financial impacts.

Turning to utilities on Slide 14. The segment delivered results consistent with expectations, typical of summer seasonality. Normalized EBITDA of $66 million was relatively in line with the same quarter last year. A stronger contribution from asset modernization and asset optimization activity was largely offset by increased O&M and G&A costs, including the impact of our rising stock price on incentive plans. During the quarter, we deployed approximately $370 million in the segment, including $120 million towards modernization programs, $30 million on new growth initiatives and $220 million on system betterment programs. These investments are focused on delivering long-term safety and reliability while extending our network to serve our expanding customer base.

Additionally, the team continues to progress construction of the [indiscernible] Connector pipeline, which now offsets 85% complete and remains on budget and schedule for completion by year-end 2026. The pipeline will increase the reliability for 14,000 SEMCO customers in Michigan's Upper Peninsula. We also recently announced the acquisition of 5,800 customers and approximately USD 20 million of rate base in Michigan's Upper Peninsula. This transaction marks an important milestone for SEMCO expanding its service territory, while reinforcing its commitment to delivering safe, reliable service to customers with the transaction expected to close in the second half of 2027.

Lastly, on the regulatory front, the team was pleased to receive final orders for rate cases in Virginia and Michigan. In Virginia, WGL received approval for a total annual revenue increase of $74 million including $39 million previously recovered through a rate rider and a 15 basis point increase to the midpoint of the allowed ROE to 9.8%. In Michigan, SEMCO received approval for an annual revenue increase of $33 million and an allowed ROE of 9.85%. The Michigan modernization programs were also extended through 2031 and supporting $271 million of additional capital over the next 5 years. We view these outcomes constructively. They will add $68 million to revenue next year and reflect the continued execution of our regulatory strategy. For clarity, for the discussion around the rate case outcomes, all figures I noted are in U.S. dollars. Looking ahead in utilities, our growth outlook remains strong. We continue to prioritize capital towards our accelerated pipe replacement programs and new customer connections, while we advanced data centers and large load industrial opportunities. Finally, results in our Corporate and Other segment declined year-over-year, primarily reflecting higher employee incentive costs due to strong performance across the business and share price strength, while financial performance at late was consistent with the same quarter last year.

Turning to Slide 15. We are pleased to be tracking towards the upper end of our recently increased 2026 guidance ranges of $2 billion to $2.1 billion in normalized EBITDA and $2.35 to $2.60 in normalized EPS, primarily reflecting sustained strength in the LPG export market. Looking forward, we expect LPG spreads and margins to remain supportive. That being said, we are mindful of a few potential headwinds, including the potential impact from lower throughput volumes due to the Trigon strike, the impact in El Nino weather pattern could have at our utilities and higher incentive costs linked to share price strength. With that said, reflective of these factors, we still expect to land towards the upper end of our guidance ranges. From a capital perspective, there are no major changes to our outlook.

As shown on Slide 16, we continue to expect capital investment of approximately $1.8 billion with roughly a 60% allocation to utilities and the remainder to the midstream and corporate segments. As shown on Slide 17, we exited the quarter with a trailing 12-month adjusted net debt to normalized EBITDA ratio of 4.3x, including 50% debt treatment for preferred shares and hybrids which is down meaningfully from year-end 2025 and modestly below our 4.5x to 5x target leverage range.

On Slide 18, we highlight AltaGas's established track record of delivering growth in EBITDA, earnings and dividends, while driving meaningful per share value creation including an average annual TSR of 26% over the past 5 years. I want to conclude with our investment proposition, which is shown on Slide 19. The AltaGas has a resilient, low-risk infrastructure platform that underpins stable and growing cash flows. The diversification of our business provides strong earnings visibility and capital allocation flexibility. Our visible organic growth opportunities position us to grow earnings and cash flow per share while maintaining financial flexibility and supporting sustainable dividend growth. With that, I'll turn the call back to the operator to begin the Q&A.

[Operator Instructions] . First question comes from Rob Hope with Scotiabank.

Can you maybe dive a little bit deeper into the Trigon impact, just given the recent ruling, is the expectation that you'll still be able to load ships during the work stoppage or does the guidance assume that the strike continues for an extended period of time with limited volumes there?

Rob, it's Vern here. The strike at Trigon started October 2, and it's been ongoing for almost a month. We've been working very collaboratively with Trigon where the contingency plans were put into place that allowed us to effectively operate at planned throughputs. For about 48 hours ago, we got a ruling from the Canadian Industrial Relations Board that our mitigation actions needed to change. We're obviously very disappointed about this ruling because we don't believe that the ruling takes into account all case law in Canada and we're going to vigorously take all legal actions we can to reverse its decision.

But in the interim, we're going to operate under modified mitigation plans, which will slow down our ability to load vessels at planned throughputs. So at this time, it's a little unclear on how much that's going to impact throughput. But I think we've taken a relatively conservative view on that, and we'll have to see how that plays out. But this gets to a bigger issue. I think that the federal government is trying to deal with in its proposed Bill C 39, where labor actions are creating choke points for the Canadian economy, and we need to have a better method of how the government can help labor and companies deal with these actions.

So obviously, we're extremely disappointed about how a third-party service providers, labor disputes are impacting our throughput we'll do everything we can to maximize the volumes that we can move through the system. And I think we've put in a fairly healthy contingency in our outlook.

All right. I appreciate that. And maybe taking a look still on global exports, but a little bit longer. Can you maybe provide a little bit of incremental thoughts on how you're thinking about hedging 2027. Just given the Trigon outage, the potential or the planned in-service in a couple of facilities as well as kind of where you're seeing mobile characterized as attractive spreads. Both on the LPG side as well as the transit side as well.

Well, maybe I'll make one quick comment. So these labor disputes have historically on the -- historically, the relatively short lived. And when you get to a 1-month disruption, you're approaching the median, and I think the worst-case scenario we've ever seen is a couple of months. So we don't expect that this is going to impact 2027. But I'll pass it over to Sean to give you more color on how we're thinking about it in '27.

Yes. Thanks, Vern, and thanks, Rob. Yes, I mean, our approach to '27 hasn't really changed to what historically we have done. I mean, at a very high level, we are about 60% tolled -- as we get to the NGL bid season. Our target is to be 80% told or financially hedged for the remainder of the year, and that won't change as we move into '27. We think that is fundamental to the investment proposition here as we think about it. If you start to think about '27, we actually have started to hedge some of that Q1 exposure in advance of that. I think curve remains heavily backwardated, but we are seeing liquidity into that Q1.

As we sit here today, we're actually about 75% hedged and/or tooled for that Q1 period at what we would view as being relatively attractive rates. So in all, really no change in how we're going to approach our sort of tolling/hedging philosophy or practice as we move into '27 here.

Next question comes from Patrick Kenny with National Bank Capital Markets.

Thank you. Vern, I wanted to get your thoughts on the change in government in B.C. What this could mean for potentially flexing your capital plan in the province going forward? And any specific projects that you might be able to either rekindle or bring forward based on the new Premier's platform?

Well, obviously, there's been a massive change in the political environment in BC, and we believe that's extremely constructive. I think the premier designate as indicated they this government wants to double LNG by 2032, I think, and then triple it by 2035 that's in line with our kind of our house view on how we see natural gas ramping up and obviously, that provides a lot more liquids for us to export. So I think we'll see -- obviously, we talked about in the call script about how we expect more phases of reef to follow OPT 2. This is also helpful towards our ethane project.

And then finally, I think as we see more and more LNG demand, we might see an acceleration of our investments in Northeast B.C. both at North Pine and Townsend and our ability just to continue to add a phase of reef every couple of years post Ott. So it's extremely exciting.

That's great. And then I guess specific to LNG Canada, too, now officially on its way, but still a few years out, of course, in terms of coming online. Can you just update us on how you're thinking about the cadence of adding that extra or incremental G&P capacity, frac capacity, storage and other opportunities to support what you see in terms of both gas and NGL supply growth?

Yes. So we FIDed towns in debottlenecking earlier this year that it will unlock a bunch of liquids at that facility. The LNG Canada producers are big customers for us up there. And I think that will accelerate the timing for when we see a North Pine expansion. As you recall, we have the ability to effectively double our fractionation capacity up there, given we have permits from both the First Nations and the BC provincial government. So we're extremely excited about those products.

Next question from Sam Burwell with Jefferies.

Just a follow-up on the Trigon related labor dispute. Is there any ability for you guys to reroute LPG volumes down to Ferndale and kind of maintain the overall export cadence or help ameliorate the problem?

Sam, it's Randy Toone here. Yes, we are looking at potentially redirecting some of the and some of the LGCs to Ford. But Ferndale is limited on how much capacity it can push out. So it doesn't fully offset. But we believe with the -- like a lower rate to RIPET, we'll still be able to get cargoes out there plus redirecting deferred deal. It is going to be -- it's already reflected in our outlook.

Okay. Understood. And then maybe switching gears a little bit. So I saw the small acquisition that SEMCO made from Excel I mean could we anticipate more material acquisitions within youth going forward or maybe even more broadly than that? Like how would you guys characterize the M&A opportunity set across the whole business?

I think we're excited to be able to acquire that -- those customers from Excel. We were able to do that on extremely attractive financial terms. Generally, that's not something we're able to do in the utility space where assets are trading at high multiples to rate base. So it was kind of an opportunistic situation. But if we're able to acquire additional gas utility assets at a reasonable multiple of rate base, that's something we'll definitely pursue. And then on the midstream side, we're always looking at opportunities. But anything we do needs to be on strategy needs to be financially accretive, needs to be accretive to our long-term growth profile and neutral to our credit rating. So those opportunities are going to be difficult to execute, but we for sure look at everything that comes our way.

Next question from Maurice Choy with RBC Capital Markets.

Just wanted to start by continuing discussion on the levers, Trigon. If this is not a short-lived event, are there actually force mature clauses or other clauses that protect you and your ability to meet your contractual obligations?

Maurice, it's Randy Toone here. As Vern talked about, like labor disruptions don't usually last for an extended period of time. So we believe that's the case. But obviously, we're looking at all options to make sure we -- it doesn't impact pit long term, and we don't believe it will be. And that includes looking at potentially fourth year clauses in the agreements. So.

I think it's very important. As we talk to customers and governments and everyone interested in this, the reality of the global situation is the world is extremely short LPGs right now. Obviously, Canada has been a growing supplier of these global LPGs. And we've seen extremely strong demand from our Asian customers for these LPGs. The feedback we've already seen from these customers is they're highly disappointed in Canada's ability to provide these LPGs because of this labor unrest. So this is something I believe the government is going to have to keep a keen eye on as I mentioned earlier, and this is one of the things I think the federal government is trying to deal with their proposed bill C3.

Understood. And maybe just as a quick follow-up on the guidance for the labor strikes as well as the super El Nino effects. Is there a way that you can quantify what contingencies you're reflected in these outlooks? Or put differently, what would the guidance have been if wasn't for these two elements?

Yes, I'll take that, Maurice. We're not going to give specific numbers. But I mean, as you think about the labor dispute, I think we've answered a couple of questions here. We do think that we've been somewhat conservative burn walk through sort of a typical time line for a dispute like this with more typical being a couple of weeks. As Vern said, probably the median and around close to a month, an sort of an outside case being close to 2 months. I think the way you should look at the way we've approached guidance is basically the worst case based on historical precedent or the outside case, which would be closer to a 2-month outage, which would be or not aged story 2 months with the next month having reduced volumes through the facility.

But as Randy touched upon, we're doing everything we can really to try and mitigate that to make sure we can continue to get volume through. But I mean as we approached guidance, I think we would have viewed it as being relatively conservative. From an El Nino perspective, I wouldn't say there is really a big impact there. We would just highlight that as something that there's potential.

Understood. And if I could finish off with a discussion on freight rates. I wonder if you could elaborate a little bit more about the landscape for these rates comparing what you see in Prince Rupert versus, say, what you hear in the Gulf Coast? And given your 2-time charters that you're expecting in 2027, 2029, between now and then what is your exposure to spot rates?

Yes. I think we had some of that in our disclosure, but we feel fairly protected from the current high freight rates. The time charter investment has been good to us, and that's why we're looking at getting more time charters. But when you look at our time charters or tolling and our hedges in place, we're fairly protected from rates. When you look at our West Coast export platform, like we are the closest distance to Asia. And so compared to other supply sources, we have the cheapest rates even at higher rates. So we feel fairly comfortable going forward.

Yes. I think, Maurice, what higher shipping rates means is our arbitrage over the U.S. Gulf Coast actually just goes up. I recall that earlier in the year, you've been quite fixed on your Baltic freight exposure for the whole of 2026, again, pretty early in the year. Is that a similar strategy you will take for 2027 as well? Or is that not possible right now given the disruptions No. It's the same approach for 2027. Obviously, we have -- we do have REIT coming on. And so we have that ramping up, so we have to have some flexibility there, but we do feel comfortable for '27.

We did just add a time charter. I mean, so if you think about the time charter basically mitigating that, I mean, it's going up. And so we're very comfortable and then we're adding another one in '27 as well.

Next question is from Jeremy Tonet with J.P. Morgan.

This is Eli on for Jeremy. Just starting with the midstream project backlog. Obviously, a lot of optionality on the unsanctioned projects. How should we think about project sequencing. Is there a way to logically think about which projects make sense to bring on before others in the backlog?

Sorry, can you repeat that? I wasn't entirely following the question, Eli?

Project sanctioning sequencing the projects in your backlog? How should we think about that?

Well, there's a natural sequencing based on permitting, commercial agreements and construction. So if I understand the question correctly, you'll see within the utilities relative ratable investment coming from system modernization and customer growth. along with investments in Betterment, which will offset depreciation at the utility. On the midstream side of things, I think the sequencing is really dependent on permitting, construction and supply growth within Western Canada. Obviously, through our capital allocation process, we will FID the highest risk-adjusted returning projects each and every time and then move on to the next highest risk-adjusted returning project. So I think we're very disciplined in how we go about that. So hopefully, that answers your question.

Yes. And then maybe just moving to the premiums you're seeing in Asian markets. Can you just frame the fiscal financial spreads right now and how they've kind of trended since the quarter closed? Just thinking about what it might look like in 4Q?

. I mean it is -- the dynamic has been very similar as it has been sort of throughout the year. I mean, the curve is still heavily backwardated. And so we see that. I'd say the 1 observation I'd make relative to earlier in the year, the curve has moved up somewhat if you look sort of especially as you look into what we're seeing into next year. So as a whole, I wouldn't say a real change in the dynamic that we've experienced throughout the year other than the observation that it remains devoutly backwardated. But as we look out into the future months, the curve has moved up, certainly relative to sort of the shape we saw earlier.

I think relative to 2026 at this point in time, the prompt is basically double what it would have been last year. And then Q1 and all of 2027 is materially higher as well.

Next question from Robert Catellier with CIBC Capital Markets.

I just wanted to quickly go back to Trigon. Maybe you can describe what you're doing in terms of mitigation measures and what cost those might attract?

Well, I think, Rob, we don't want to get too detailed on what we're actually doing. I think if you recall, we had a labor situation at RIPET last year. And effectively, we were able to manage our way entirely through that situation where we saw very, very minimal decline in throughput. We're working hand in glove with Trigon to see what we can do to minimize those impacts. And we -- through October, we're extremely successful. Obviously, the CI RB ruling impacts how we're actually going to do that going forward. So we're working through with our service providers to see how we can maximize that. And we expect that there will be some volume loss, but we're doing everything we can to minimize the effects [indiscernible].

And Rob, it's Randy. I would just add that, obviously, we do have storage. We do have rolling starts with rail. And so we are looking at all those options and that has been put into our outlook, those additional costs.

Okay. And then I just wanted to move to capital allocation for a minute here. I think on I think it was Slide 17, you show the balance sheet and the leverage coming down, basically 0.4 multiple points per year. And I would characterize your operating environment as strong as it's ever been. So what is the plan for capital allocation going forward here other than the normal annual dividend review considering you're below your leverage target at this point? Is there anything new we can expect on the capital side?

Well, as you know, our investment capacity has been going up as we grow. That gives us more opportunities to invest capital, and we'll pick the best place to put that capital. You would expect -- you should expect that our dividend cadence isn't going to change much. So that really allows us, if we choose to invest more in organic growth projects, organic growth projects are the most attractive thing we have in front of us in our capital allocation process. So we will -- I think and the backdrop is hopefully going to accelerate more opportunities to make some investments both in midstream and utilities. So we're really excited about what we have in front of us and the tailwinds that we have. So you should expect us to continue to deploy capital and deploy it perhaps even a little bit faster, but given our strong financial performance that we've seen.

Okay. Great. And then last one for me, just a quick one on the data centers. Can you quantify the scale of the two data center agreements and also comment on the timing for cash flow generation?

So this is in speaking, Robert. So just on both of the deals, they're relatively small, both in scale Think of this as under 15 megawatts per project. And that's what we're focused on. So the cash flow generation at this point in time going out into 2027 isn't that significant on what we're doing. But for us, we're going to continue to look and target these projects and the growth that we see around our jurisdictions and look for opportunities that we can invest in that both help our rate base growth and as well as on the unregulated side, add to our portfolio to from a rate base perspective, we really want to make sure we're not overburdening our current customers. So that's a focus for us as well.

So we still have lots of opportunities on the go, Rob. So I think despite some -- all the news you read about putback and local counties and jurisdictions, there is still a lot of activity from the developers, but we need to be extremely careful on which ones we pick and choose.

The last question will be from Ben Sam with BMO.

I want to start off with OPTI 2 last quarter, you mentioned the finalization or as the Class 2 estimate incremental tolling arrangements that you wanted to finalize within a few months. Could you update us where you're at on that and specific what remains before FID? And also wondering the 2029 in-service date you've mentioned in the presentation that a bit of a slight tweak from what you've mentioned before?

Ben, well, the good news is we have our permits. We've had this for a while. We've finalized our Class III and it's a good number. We're just in the late stages of finalizing some commercial agreements, which is really a matter of dotting the [indiscernible] and crossing the Ts. So we're extremely excited about [indiscernible] we're looking to bring that on late '29, early 2030, depending on supply growth. So there will be some flexibility there as we -- how we see the basin ramps up. So we'll give you more color when we have our Investor Day in about a month or so.

Okay. Got it. And not that I want to get into your '27 guidance ahead of the Investor Day, you mentioned some trends, I think about, you have the hedges in Q1, you got new projects coming on. You don't expect the labor disruptions to persist this next year. But can you maybe talk about high level other key trends or puts and takes you're thinking about it as you head into 2027 versus '26.

Yes. I mean I'll start there. But as you noted, Ben, we're not going to steal the thunder from our Investor Day. So we'd encourage everybody to come and hear that, I mean what are we seeing as we move into '27? I think -- as we talked about, we've invested quite a bit of capital and that will come online. That's both at the utility through our accelerated replacement program. So we'll see the benefits of that. We'll see the benefits of recent rate cases. On the midstream side, we have been deploying capital and are very excited to see Reef come online which will be a material contributor to EBITDA as well. We talked about it a bit, but Dimsdale Phase 1 comes online to the year-end this year and Phase 2 midyear.

So there is real benefits that we're going to see from the capital that we've deployed. And then from a commodity perspective or an export perspective, as we talked about, we continue to see tailwinds as we move into the year. We expect that to continue. But I think from a conservative perspective, there could be some normalization. So at a high level, what we're most excited about is to see our investment capital earn a return and that's on a take-or-pay fee-for-service utility basis. And yes, I think I'd leave it at that.

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

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.

Good morning, ladies and gentlemen. Thank you for standing by, and welcome to the AltaGas Second Quarter 2026 Financial Results Conference Call. My name is John, and I'll be your operator for today's call. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session. 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 2026 Results Conference Call. This call is being webcast, and we encourage following the law of the supporting slides that can be found on our website. Speaking this morning will be Vern Yu, President and Chief Executive Officer; and Sean Brown, Executive Vice President and Chief Financial Officer. We are also joined by Randy Toone, President of Midstream; [indiscernible], 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 and 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'll now turn the call over to Vernon.

Thanks, Aaron. Good morning. I'm going to start by reviewing highlights from the quarter, including our strong financial and operating performance. Then I'll walk through progress on our growth projects in Midstream and Utilities. I'll finish by reviewing the state of the global LPG market and how that is creating growth opportunities for AltaGas. After that, Sean will cover our segmented financial results and provide more details on our increased 2026 guidance.

I'd like to start by introducing [ Karen ], who is now leading our utilities business. [ Karen ] has been with AltaGas for more than a decade and is a valued member of our executive team. We're excited to have Karen step into this role, given our proven track record of operational excellence and strong financial leadership.

Let's begin on Slide 4. We delivered record financial results in Q2. We reflecting strong performance from both midstream and utilities. I should note that Midstream's financial results in Q2 benefited from historically high global export spreads and physical sale premiums. We generated normalized EBITDA of $391 million and normalized EPS of $0.31. And increases of 14% and 15% over Q2 2025. Our strong first half gives us the confidence to raise our 2026 guidance. We've increased normalized EBITDA guidance by 4% to a new range of $2.0 billion to $2.1 billion and normalized EPS by 6% to a range of $2.35 to $2.60 per ship.

Our balance sheet remains strong throughout the quarter with leverage closing at 4.4x, below the low end of our 4.5 to 5x target range. Operationally, we exported a record 144,000 barrels per day of LPG, a 13% increase over Q2 2024. Midstream throughput continued to grow with Montney volumes up 8% year-over-year, and we added 2 high-quality partnerships to our platform. the Groundbirch rail terminal with Tourmaline and the ACE rail terminal in Fort Saskatchewan with Keyera and CN Rail. In utilities, we continue to advance our system marization programs. Year-to-date, we have deployed over $200 million of capital and replace 21 miles of pipe.

Let's move to our growth projects, starting with REEF on Slide 5. Construction on REIT continues to advance and the project is now 85% complete. Onshore execution has been strong and ahead of plan. On the uplines, all major equipment is installed, and commissioning should begin in late August. The railroad corridor is entering its final construction phase and will be completed before year-end. While onshore execution has been ahead of plan, in-water construction has proven more challenging due to maritime conditions and weather delays. Since we started in water construction at REIT in the fall of 2024 and we have lost over 450 rig days due to extreme weather, extreme ocean swells and marine mammal activity. These lost rig days significantly exceeded any normal contingency plans.

As a result, onshore efficiencies are no longer expected to fully offset higher in water construction costs. We now expect REIT to come online before the end of Q1 2027 and have increased REIT's capital cost estimate by 12% to approximately $1.5 billion. With the Jetty and loading on platform now 80% complete, post in-water construction is set to be completed over the next 6 weeks. We view the revised schedule and cost is highly achievable, and we'll get into those details shortly.

REEF Optimization 1 remains on schedule for an in-service date in the second half of 2027. We and we will add 30,000 barrels per day of incremental propane export capacity. We're also advancing reef optimization to with key regulatory permits secured and engineering progressing towards final Class III cost estimates before the end of the year.

On Slide 6, we outlined REIT's remaining major work streams and highlight what has been completed to date. The in water works have been the most challenging, but we're almost done. All 48 of the piles for the jetty peers have been drilled and completed. Only 5 files remain to be drilled for the loading platform, and that should be completed by the end of August. All of the Jetty trusses that span 1.2 kilometers have been installed. The transition platform has been delivered and set Fabrication of the main loading platform is complete and is about ready to be loaded for an August delivery. The mooring system fabrication is nearing completion, and is set to be delivered in November and installed in December.

With the aging water phase of construction, the most complex and challenging part of REIT nearing completion, we're highly confident that we'll be able to meet our revised cost estimate and schedule. Slide 6 shows how the platform and mooring system will be installed on the jetty which is a low-risk installation and part of our modular design.

Turning to Slide 7. You will see the progress on onshore construction activity. All modules have been received and all equipment has been set. Mechanical completion is now 90%, and we expect to commence upland commissioning by the end of August. The rail loop and utility corridor are now 70% finished and are on track to be completed by mid-November.

Slide 8 shows the progress on our other growth projects. At RIPET, our methanol removal project remains on track for completion by year-end. Our Dimsdale storage expansions are now more than 50% complete, with pipeline tie-ins completed. We're on track to start the drilling of the injection wells in the third quarter. Phase 1 will add 6 Bcf of storage by year-end 2026 and Phase 2 will add another 30 Bcf of storage by mid-2027. At the Mountain Valley Pipeline, Southgate construction is underway. Pipeline welding began in early July, and the project is on track to be in service by year-end 2026 ahead of schedule. MVP boot continues to advance through its regulatory steps and is expected to be in service by the middle of [indiscernible].

During the quarter, we reached a positive FID on a debottlenecking project at Townsend which will add 6,000 barrels per day of fractionation to posit within utilities have more than 5,000 miles of pre-1970s pipe that needs to be replaced to enhance safety and reliability. To support that, we have USD 1.5 billion of modernization programs approved by regulators across our 4 jurisdictions. Modernization capital, system expansion and customer adds are expected to drive 10% rate base growth in 2026. This rate base will improve the safety and reliability of our system, every mile we replace reduces the risk of leaks and safety incidents, service disruptions and operating costs for our customers.

Despite these large increases in rate base, we have been able to keep customer bill increases around 4% per year based on operating cost savings from these modernization investments another on cost management initiative. Demand for natural gas across the U.S. continues to rise, driven by heightened commercial and industrial activity. data center and large load development and ongoing population growth. The mid-Atlantic sits in the center of this expansion. For example, PJM data center load is forecast to increase by fourfold over the next 8 years.

Turning to Slide 9, I want to touch on the disruption in the Middle East and what this means for the global LPG market and our global export business. LPG exports through the Strato farmers are more than 70% below pre-conflict levels. Since their disruption began, more than 160 million barrels of LPGs have been displaced from global trace. That had tightened market balances and reinforce the value of stable Canadian LPG supply. We're seeing very strong demand across our traditional markets in Japan and South Korea and growing demand from China.

We're also seeing incremental demand from other Asian markets that have historically relied in Middle Eastern supply. Given the favorable market dynamics, we continue to advance Rett and see the need for additional rephase every 2 to 3 years to meet the market demand in Western Canada. We're also seeing significant interest from China for Canadian ethane exports as a way to diversify its long-term ethane needs.

Today, roughly 500,000 barrels a day of ethane is left in the natural gas stream in Western Canada, while age and demand keeps growing. We're actively, we're working through the complexity of connecting these markets as we see this as another opportunity to provide Canadian energy to the best global markets.

Finally, let me close on the progress we've made on our strategic priorities in 2026. AltaGas' future is very bright. We've executed consistently growing, derisking and strengthening the enterprise through the first half of the year. In the second quarter, we delivered record volumes from our global export platform and higher throughput across our midstream value chain. We continue to actively manage risk through hedging, commercial contracting and diversifying our downstream markets. We're advancing multiple rate cases in our utilities to earn appropriate returns on our capital investments and minimize rate lag.

Our balance sheet is strong, with leverage below our target range, which has allowed us to advance multiple projects that will drive long-term growth. Taken together, we're extending our competitive advantages, improving the quality and visibility of our cash flows and creating a longer runway for disciplined expansion across AltaGas.

I'll now turn it over to Sean to walk through our segmented results and increase 2026 guidance.

Thanks, Vern. And good morning, everyone. As mentioned, we are very pleased with our record second quarter performance. The continued execution across our platform has enabled us to increase our guidance and positions us to deliver over 10% year-over-year EBITDA growth.

For today's call, I'll start by walking through our segmented financial results, and then I'll discuss our updated 2026 guidance and capital budget and closes our balance sheet strength and investment proposition.

Turning to Slide 12. In the quarter, the utility segment delivered normalized EBITDA of $142 million a 6% increase year-over-year. This increase was driven by higher revenue from continued system modernization investments, new rates in D.C. and interim rates in Virginia, as well as stronger retail performance. Compared to the same quarter last year, results were partially offset by higher G&A expenses and lower asset optimization activity at Washington Gas.

From a capital perspective, during the quarter, we deployed approximately $240 million in the Utility segment, including $130 million toward modernization programs, on new growth initiatives and $86 million on system betterment programs. Of note, our modernization spending has resulted in us replacing over 20 miles of vulnerable pipe year-to-date. These investments are focused on delivering long-term safety and reliability, while extending our network to serve our expanding customer base. In addition, in June, we officially kicked off construction of the Kia Connector pipeline.

The majority of the materials are now on site with pipe welding, bending and placement ongoing. We continue to expect construction to be completed by year-end 2026. We are also making solid progress on our 2 data center pipeline connection projects in Virginia and Maryland, both of which remain on schedule for completion in the fourth quarter of 2026. Though individually not material in size, these projects underscore the increasing importance of our gas utility infrastructure and enabling reliable energy delivery for large load customers.

Looking forward, we continue to see a robust pipeline of opportunities with sustained interest from data center and large load industrial customers seeking reliable, scalable and cost-effective energy solutions.

Turning to Slide 13. We highlight our ongoing regulatory initiatives. This week, we received a final order in Maryland, where the commission approved USD 38 million in new revenue including certain costs currently recovered through the Stride surcharge based on an allowed ROE of 9.4%. Active rate cases in Virginia and Michigan are ongoing. In Virginia, interim rates remain in effect with WGL seeking USD 65 million of incremental revenue, net of a USD 39 million ARP surcharge. In Michigan, we are seeking new rates and an extension to the modernization program, requesting USD 61 million in revenue and USD 284 million of proposed spending for Michigan's modernization programs through 2031.

We expect final orders in Virginia by the end of Q3 and in Michigan before year-end. Late in the second quarter, the Public Service Commission of DC approved a 6-month USD 18 million extension of the existing project type 2 modernization program through the end of 2026. This came after our USD 150 million District safe ARP program was approved, but subsequently reopened as the commission determined a further hearing was necessary. The hearing was held this week, and we expect resolution by the fourth quarter.

Importantly, our utilities investments are expected to drive 8% long-term rate base growth through 2030, supporting stable cash flows earnings growth, dividend durability and shareholder value.

Turning to Slide 14. The strength in our midstream business continued, delivering $285 million of normalized EBITDA, and up 33% year-over-year and above our expectations. The segment's outperformance was driven by our export platform, which exported record volumes and delivered strong merchant margins. The segment also benefited from continued strong performance across the balance of our midstream assets, particularly in the Montney, where producer activity remains strong and continues to drive basin growth.

From an operational perspective, we exported a record 144,000 barrels a day of LPGs across 23 VLGCs at our Ferndale and RIPET terminals, with volumes up 13% year-over-year. Strong terminal execution and logistics supported record Ferndale exports of nearly 60,000 barrels a day, driven by improved rail switching efficiency, along with higher rail, refinery and trucking volumes. RIPET exported roughly 84,000 barrels a day of propane and continue to operate near capacity.

In the rest of our midstream platform, GMP utilization remained strong in the quarter, although margins were tempered by lower realized frac spreads due to the impact of hedging. Ormat was offline for 32 days for planned maintenance. Excluding the impact of the Harmattan turnaround, throughput volumes were 9% higher year-over-year. Money growth remained a key driver supported by our strategic footprint across liquid-rich areas of the basin and continued producer activity.

In the Alberta Montney, our Pipestone complex continued to perform well. averaging roughly 90% utilization through the quarter as area volumes continue to increase. In Northeast BC, strong volumes continued across our Montney assets with North mine throughput up 23% year-over-year, continuing to operate near its 25,000 barrel a day capacity. But looking across our system, the underlying growth we are seeing reinforces the value of our Northeast BC liquids expansion projects, which are designed to unlock additional value from Townsend and North Pine while deepening our strategic producer relationships.

Looking ahead, we are well hedged for the balance of 2026 and have derisked much of our Q4 exposure. With approximately 91% of expected remaining 2026 global export volumes, either tolled or financially hedged with an average FEI to North America spread of approximately U.S. $2.81 per barrel on non-toll volumes, while 9% of volumes remain open to market pricing.

In addition, our entire 2026 Baltic freight exposure is hedged through a combination of time charters, financial instruments and tolling arrangements. We also continue to manage frac fed exposure and had 84% of expected volumes hedged at an average price of $22 a barrel. -- post the discussion on our financial results. The Corporate and Other segment was lower year-over-year, primarily due to higher employee incentive costs tied to our rising share price.

Turning to Slide 15. Year-to-date, -- we have seen outperformance from both business segments with significant strength in our LPG export business driving an increase to our guidance. We have raised our EBITDA guidance to a range of $2 billion to $2.1 billion, representing a 4% increase over the original guidance midpoint and 10% growth year-over-year. At the same time, we are raising our EPS guidance to a range of $2.35 to $2.60 per share, a 6% increase over the original guidance bit point and 11% above last year's levels.

Additionally, as outperformance is more weighted to our midstream business, we've adjusted our estimated year-end 2026 segment EBITDA mix with midstream now expected to contribute approximately half of normalized EBITDA, resulting in a range of 48% to 52% for both segments.

As shown on Slide 16, also increased our 2026 capital budget, which now sits at $1.8 billion, up from $1.7 billion previously. This increase reflects higher capital expenditures to the construction of Reed as well as capital associated with the positive FIDs of the Northeast D.C. liquids expansion project and the Groundbirch Rail Terminal. 1% of 2026 capital is now expected to be allocated to the utility segment, 36% to the midstream segment, with the balance to the corporate segment. Utility capital is primarily directed towards modernization and system betterment initiatives, which are expected to drive 10% year-over-year rate base growth. Midstream Capital remains focused on Reef, including Optune, Dimsdale and our new Northeast DC project announcements, all of which underpinned the segment's robust growth outlook.

As shown on Slide 17, our $1.8 billion capital program remains well within our investment capacity. Our relatively low dividend payout ratio, along with our strong business performance, has allowed us to increase our 2020 fixed capital program while remaining within our debt target ranges and deliver on our 5% to 7% EBITDA and EPS CAGR.

Looking forward, our capital allocation priorities remain the same as we look to cover maintenance spending and advance key growth projects that position the business to deliver on its long-term growth guidance.

As shown on Slide 18, we exited the quarter with a trailing 12-month adjusted net debt to normalized EBITDA ratio of 4.4x, honestly below our target range. With the increase in shape of our 2026 capital program and considering the seasonality of our business, we expect our leverage metric to trend towards the midpoint of our 4.5 to 5x target range as we progress through the year.

On Slide 19, we highlight AltaGas' consistent track record of delivering per share growth in earnings, EBITDA and dividends, which has translated into sustained share price outperformance. The updated 2026 expectations have driven an increase to our 5-year EPS CAGR to 8% and our 5-year EBITDA CAGR to 7% from 6% previously.

Our investment proposition, which has remained the same as highlighted on Slide 20, a resilient, low-risk infrastructure platform underpins stable and growing cash flows, and a diversified business mix that provides earnings visibility and capital allocation flexibility. Visible organic growth opportunities position the company to grow earnings and cash flow per share while maintaining financial flexibility and drive sustainable dividend growth.

With that, I'll turn the call back to the operator and open the line for questions. Operator, we're ready for questions, if there's any in the queue.

[Operator Instructions] Your first question comes from the line of Rob Hope from Scotia Bank.

I want to dive a little bit deeper into the potential for further producer partnerships up in Northeast BC. Are you having conversations up there to support incremental infrastructure build that could be a header in essence for your global export business?

Rob, it's Vern. I'll start that off and then hand it over to Randy. I think in Northeast BC, we're in a great position. I think as you know, it's sometimes challenging to build infrastructure up there. given the precedence with the First Nation. So the good news is we're well situated with our Townsend and North Pine assets to add significantly more volumes up there. And obviously, we've sized up our rail facility to -- at North Pine to handle unit trains -- this new partnership with Tourmaline gives us a second and significant loading opportunity where if other volumes come in we're able to capture those as well. So I'll turn it over to Randy. He can just fill in a little bit more color.

Yes. Thanks, Vern. I would just add that we do think that LNG Canada Phase 2 is likely going to be FID here soon. And also the federal government has been very supportive of other LNG projects. And so that's just going to add more supply in the Montney, and we think that our assets are well positioned to take advantage of that.

Appreciate that. And then maybe just moving over to the global export business. I understand that pricing is volatile, but we are hearing about physical premiums to the posted FEI pricing. Can you speak to how you're benefiting from this dynamic? And do you realize that even when you do hedge relative to FEI as well as moving forward, how it is informing kind of your hedging profile?

I think the way to characterize that, Rob, is with this massive disruption in global supply and demand remaining relatively constant is the fact that often times, people are not want to show their physical sales on the index. So that's why there's particularly a disconnect between a physical sale and the index. So going forward, on our merchant capacity, we're able to capture the actual physical sale premium over FEI, and we're seeing that continue as we work through this situation.

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

Maybe just on the new tolling agreement with Tourmaline. Just wanted to get your initial thoughts here on their 1-year pause on growth spending and any read-through to perhaps any broader temporary slowdown in activity across Northeast BC? And I guess what that could mean timing-wise for some of your unsanctioned growth opportunities, whether it's ODI or further upsizing it North Pine, Pipestone or Diversa?

Patrick, it's Randy. Yes, we totally understand why Tomlin wanted to pick a pause given where the natural gas prices are. But when you look at what their Phase II expansions that was Conroy and Dohan that's really not kind of feeding our existing infrastructure. So it doesn't change our plans. Obviously, we want to see that development and we know it will be developed, but it doesn't impact our long-term plans.

Yes. And, I'd just jumping in here. I think, obviously, we're seeing heightened activity from other producers, which is really driving the towns and debottlenecking that we announced today. And I think the demand we're seeing on -- for OCI is extremely high, Patrick. We expect to be concluded on commercial negotiations on incremental tolling arrangements within the next couple of months here.

Okay. That's great. I appreciate that. And then I guess, Vern, as you think about your portfolio of tolling contracts, you've had good uptake from midstream peers, as well as upstream customers and now you're seeing increased demand from China. I guess as you think about maximizing realized margins going forward, how are you thinking about the right mix in terms of customer type and maybe an update on where you're at today versus your longer-term target?

Sure. Patrick, we're still targeting to be 60% told on a long-term basis. So as we bring OTIF later this year, we're still wanting to have at least 60% of the total export capacity under tolling agreements. We're starting to see early signs of Asian demand for more Canadian product. We're in active discussions on all kinds of supply arrangements between Japan, Korea, China and other jurisdictions. So the disruption we're seeing in the Middle East, obviously, is highlighting how important it is to have a secure and reliable supply in Canada obviously a great place for that.

So as we approach the end of the decade and have 300,000 barrels a day of export capacity, we think there's going to be very high demand for tolling contracts and we'll see that play out over the next couple of months.

And I guess as you look to potentially add ethane exports to the franchise, can you provide just a bit more color on maybe how those discussions are progressing to secure the offtake contracts and also along the value chain, how you're thinking about sourcing the ethane and securing the rail logistics and whatnot?

Yes. Ethane is obviously, in an earlier stage than OPTI 2 and even OPTI 3. We've made great progress and 1 of the most critical elements, which is just the rail logistics. We've recently received Transport Canada approval to use a pressurized car to move ethane. So that removes a significant gating item. I think where we're at now is obviously to get a better line of sight on the capital cost involved on all the logistics from loading and then export facility wise, the dynamic is the China imports almost 100% of its ethane today from the U.S. Gulf Coast with global trade tensions, China is extremely eager to get different -- a variety of supply sources in Canada is well positioned for that.

I think as we mentioned on our prepared remarks is 500,000 barrels a day of ethane in the gas stream with lots of facilities across Alberta and BC for that ethane to be railed. So we think a lot of the parts are already there. We just need to do a little bit more work on figuring out what is a competitive rate. And then with the thing, given that it's a new product with probably 1 buyer or a series of buyers in 1 location, we're going to look to target a much higher percentage of tolling on that kind of transaction.

Your next question comes from the line of Robert Catellier from CIBC.

Just wanted to clarify on the ground with rail project that there is an ability to accommodate third-party volumes, and it's not exclusive to Tourmaline?

Rob, it's Randy. Here we do have rights to participate if there's any available space. But for the first initial phase it is entirely terminaling, but we do have rights to bring in third parties if there is a capacity available, and we also do have rights to potentially participate in expansion.

Can you provide updates on -- how do we say this, the aspirational drag on LPG project. I know there's been a couple of project filings from Trigon and also your replying -- so maybe you could just summarize where we're at there and then your response. Maybe you could touch on where you see First Nations support line for your export assets versus some of the other projects?

Rob, maybe I'll just comment on Trigon, and I'll hand it over to Andy to talk about our stakeholder relations. At the end of the day, I think it's pretty clear that there's only 1 anti city on Rite Island that has the ability to develop LPG handling and export and that's us. That's been reinforced several times by the Prince rereport authority. And obviously, there's a legal court case coming up here in the spring of 2027. I think our case is extremely strong, and we are not very worried about it. And just to reiterate, we will make sure that we protect our commercial rights all the way in any possible way.

And then finally, before Randy chime in, is our goal is to have all of our stakeholders aligned with us over the long term. We've done that over and over. And I think Northeast BC is a great example of how we really positive relationships with our First Nations. So with that, I'll let Randy talk about the particular situation with the math.

Yes. So we've been -- had a strong relationship with the MAP for over a decade since we've been in Prince Rupert. We see them as a long-term partner. We do think that we're making positive progress on on the issues in hand, and we think we'll have a positive outcome in the end.

Okay. And my last question is for Karen. I know it's early days as you step into the role here, but I wondered if there was any thoughts on possible changes to the regulatory strategy, especially as it relates to those building emissions performance standards or on the efforts to narrow the ROE gap.

Good morning, Rob. Thank you. So excited to be here today. Just want to say upfront, -- there really is no change in our utility strategy. The team has done a great job making improvements in the utility, and we're going to continue to build on that foundation. As we think about the regulatory strategy tied to what you were mentioning, I'm going to just maybe go right to gas fans, and we're going to continue to oppose gas expense as they limit customer choice and customer affordability. The mid-Atlantic, it needs natural gas to support reliability, long-term energy security and customer affordability and restricted policies only increase regional energy challenges -- so we're going to continue with both our legal and our advocacy strategy that supports ultimately what we're trying to earn our regulatory strategy. And at a high level, we have no change, and we're going to continue to close our ROE gap there's no change in our focus there. And we're going to continue to put safe pipe into the ground to improve the safety and security of our systems.

And customer affordability is obviously top of mind. So we're going to double down on our operating costs and our capital cost efficiencies so that at the end of the day, it's more affordable for our customers.

Rob, going to add us a little bit there on the gas bands. Like if you think about it, PJM is short energy and short energy in a big way. for a county or city to think about limiting the available sources of energy and trying to shift that to the power grid is just nonsensical. -- you're making an energy shortage problem even worse. And then finally, you've seen different outcomes on a legal basis, different district courts in the U.S. This obviously is leading to the Supreme Court, and we just recently seen the DOJ and the DOE really weigh in on these items. So we're very -- we have a real positive lean that this will ultimately get resolved at the Supreme Court in a fashion that makes sense for everybody.

Your next question comes from the line of Jeremy Tonet from JPMorgan.

This is Eli on for Jeremy. Just wanted to touch on MVP quickly. I know that the pipe is flowing and there's some expansions in the works. But if you could just remind us on your broader strategy with that asset? And how should we think about the opportunity for future monetizations there?

Hi, this is Jon. So if we broke it into the 3 pieces, we would agree with your take. The mainline continues to perform very well. And with each passing month, our investment thesis to retain that asset continues to be reiterated. So we're very happy with the investment there. And VP Boost continues to push forward for mid-'28 in-service date. One permitting issue continues to get worked through. And ultimately, we think that's very resolvable and in line with what we've talked about in the past. The build economics on that are very strong around a 3x build multiple.

And then lastly, on South [indiscernible], it's progressing very well. All the regulatory approvals are in place. construction currently taking hold right now welded pipe started going in the ground in July, and you would have seen this out of EQT's disclosures, but they had -- the partnership elected to accelerate capital spending and ultimately try to target a handy year-end service date. So things are progressing along very well there. From a long-term holding perspective, I think you should probably consider it as a perpetual investment. We're very happy with obviously how all those things are going again the EQT team is very strong. And ultimately, we think there is going to be incremental growth opportunities that come over the long term.

Awesome. And then I know there's been a lot of discussion on reef and feature optimization phases, and there is sort of the further expansions bucket on 1 of your slides. So maybe we can just dive into that a little bit and think about the size there and the cadence of sort of future FIDs we might get across other other projects that could kind of fit within your midstream portfolio. Just any color on that bucket would be great.

I think, Eli, if you look at -- I think 1 of the slides we have in the deck, we show that there's significant growth potential coming out of our global export platform. Really, that's on the back of incremental gas egress and the development of data centers in Alberta. So for every incremental BCF a day of gas that's needed or can get to export markets. we see somewhere in the range of 35,000 to 50,000 barrels a day of incremental LPG supply becoming available for export. So if you work that through from 2030 to 2040.

You kind of see that you need about -- you need an incremental phase of read every 2 or 3 years. So -- we're targeting OT2 to be in service by -- in the late 2020. So that would point to an OTI in the early 2030s and then opt in the mid-2030s and so on and so forth. Obviously, ethane is an incremental opportunity on top of that, where the initial phase would be something in the range of 60,000 barrels a day, but that could grow substantively over time. The great news is that the REEF common facilities are able to handle 500,000-plus barrels per day of exports.

So that gives us a tremendous growth platform over the next decade. And as egress comes forward as exports grow, there will be the need for incremental gas processing, fractionation, rail loading and all these great things. and we have irons in the fire across our footprint in Alberta and in Northeast B.C., and we see strong opportunities with further debottlenecking in Northeast B.C. plus a North Pine expansion. And then gas processing opportunities in the Alberta Montney. So we're super excited about the potential growth outlook that we have in our midstream business.

Your next question comes from the line of Ben Pham from BMO.

Just want to go back to the propane export position and you have a bridge there with respect to Optum service, OPI and then ethane Phase I. And I'm just you're thinking about sequencing that those projects, are you able to just think about your manpower and the site and your balance sheet. Are you able to build or start construction on more than 1 of those or you need to sequence it in a way that spread out those projects?

So with OT2, Ben, we have our permits in hand. So we're able to start construction any time now. issue that we want to -- the issues that we want to finalize before we go to FID is, number one, having a firm capital cost estimate at the Class II level. We should have that in the next few months. The second is what we talked a little bit earlier about is making sure that we have sufficiently derisked the cash flows for any expansion, and we're -- we have line of sight very strong line of sight for incremental tolling contracts, again, which we expect to have on hand within the next couple of months. So that would lead, obviously, to an opt with ethane and OPTI and so forth, we would need to make regulatory filings to get the appropriate permits to start building.

But those all can happen. If you ever -- if you have a good look at our replot plan on our website, there's lots of room for all of this to happen. Really the gating items is the timing of the regulatory approvals, -- remember that most of this equipment is -- we don't need to build another war. We don't need to add any loading platforms or things like that. So all the common infrastructure is completed and we're just bringing in extra storage and compression that's predominantly being built off-site and can be transported to root. So we're very well positioned and risk managed about how we continue to expand the export platform, Ben.

Yes. And I think the only other thing, Ben, is I think you had balance sheet in there as well. I mean, we are not concerned on the balance sheet perspective at all. I mean I talked about in my prepared remarks, but we've got the capacity to deploy $1.6 billion to $1.8 billion a year. I mean so we certainly, from a funding capacity perspective, wouldn't have any concerns, and that's 1 of the real benefits of the balanced business model we have between utilities and midstream, and you would have seen that over the last couple of years that if we have attractive projects in the midstream business. We can flex a bit more capital there. And then in periods like this year, when REIT is nearing completion, we flex more in the utilities. So from a financing and balance sheet perspective, not concerned.

Got it. And maybe another one on the utility side of of the business. You mentioned the Maryland case was a constructive outcome. Can you unpack that a bit? Just maybe some of the things you like, some of the things you didn't like maybe just broader relate that 70 basis points looks like a nice improvement from what you've been highlighting before overall. What's been the key driver of the change?

Thanks, Ben. I would say that a key driver for the constructive outcome was our planning process and us working with the commission and the staff to better understand at the beginning of the process, what they were looking for. So as we were prepping and going into it, I think we were just better planned to be blunt. And we have seen positive movements with Maryland PSC. So we're, in general, we're encouraged with what we're seeing for results there.

And I just wanted to check the previous spacing on the ROE was the 100 plus or minus around that and you're doing about 70 basis points you're expecting this year. Is that summer costs reductions that the gap we get any more?

So we're a little bit higher than that this year, Ben. Last year, we exited around 100 basis points -- this year, we'll narrow the gap a bit. You're right, though, on a target basis over the long term. We want to be to that 50 to 75 basis points because factoring in, as you well know, the historical test year lag -- but with optimization, we do have the ability to help fill that gap.

Your next question comes from the line of Maurice Choy from RBC.

Just sticking with the S&T theme here. Can I confirm if ethane is covered under the exclusive right your JV has to export LPGs and -- if not, is there an opportunity to form partnerships locally, particularly if Reef is capped at 500,000 barrels a capacity.

Well, I think I'm just going to kick that over to Randy.

Yes, ethane is included in that exclusivity. As far as we are looking at partnerships for ethane. So we are looking at supply partnerships. We do, as Vern talked about, there is 500,000 barrels a day of ethane being reinjected into the gas stream, and there's the straddle plants that can just cool down and capture those -- that ethane. So we don't think there's a lot of investment or significant investment in upstream and the ethane supply will be available. But we need to look at the railcars and so we are looking at partnerships for that. And also the offtake would likely be a partnership as well.

And I think, Maurice, ultimately, to get to the global export part of it, there is more land that we can acquire on Ridley Island should there be extremely robust demand for both LPGs and ethane. It's great to hear. And if I could just quickly follow up with that. I think you mentioned earlier in the call that you're going to seek a higher level of tolling for these ethane exports. Just wondering what other aspects of commercial or even a return perspective of an ethane infrastructure differ from propane but an infrastructure? Yes, I would think of it more as traditional energy infrastructure where you want to do it under a take-or-pay contract, effectively, Maurice.

The last question comes from Sam Burwell from Jefferies.

Apologies if you had addressed this before, but I wanted to ask about the economics of the Groundbirch rail venture with Tourmaline like there is at least like a minor amount of CapEx that got thrown into the budget this year. So curious what the quantum of CapEx might be? And then like is the EBITDA contribution just simply the barrels a day that's getting told? Or is there other contributions just trying to frame the build multiple around this project.

It's Randy. Yes, it's very minimal capital for us. It's less than $20 million for us to participate in the rail yard. But the benefits of that rail yard is that we see significant savings in the rail costs, both in rail -- our fleet our rail cost getting to the export facility, our storage costs, and so that's why we want to make that investment. We also see that our North client facility and this Grundberg facility, there should be some synergies between the 2, and we do see them additional rail savings. And of course, the export tolling is not a benefit.

It's an extremely lucrative transaction for us on a capital deployed basis just because there's a huge opportunity to -- for us to reduce our operating costs.

Yes. Okay. That makes total sense. And then last one, on shipping costs, like I understand that you guys had locked in the 2026 exposure already. So covered on that. But curious if all of 2027 remains open. And just like as things stand, I mean, is there any risk of upward pressure on costs and downward pressure on margins in the export business from shipping exposure next year?

It's Sean here. I'd say the answer is essentially no. I mean we have 3 time charters right now. We're getting another 1 delivered next year. So we remain very comfortable with the exposure we have from a time charter perspective. So we definitely are not open as we enter next year. We are taking on an additional time charter -- so we'll have 4 next year and are comfortable with our position as we move into '27.

This concludes the Q&A portion of today's call. I will turn the call over to Mr. Swanson. Please go ahead.

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

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.