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Operator: 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.
Aaron Swanson: 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.
Dai-Chung Yu: 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.
D. James Harbilas: 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: [Operator Instructions] Your first question is from Jeremy Tonet from JPMorgan.
Elias Jossen: 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.
Dai-Chung Yu: 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.
Elias Jossen: 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?
Donald Jenkins: 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.
Operator: And your next question is from Rob Hope from Scotiabank.
Robert Hope: 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?
Dai-Chung Yu: 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.
Robert Hope: 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?
Dai-Chung Yu: The actual number is around 69, and we are in active commercial discussions with a whole host of customers right now.
Robert Hope: And can it be done in phases?
Dai-Chung Yu: Yes.
Operator: And your next question is from Sam Burwell from Jefferies.
George Burwell: 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].
Dai-Chung Yu: Sorry, Sam, can you repeat your question? You broke up.
George Burwell: Sorry, can you hear me better now?
Dai-Chung Yu: Yes.
George Burwell: 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.
D. James Harbilas: 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.
George Burwell: 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.
Dai-Chung Yu: 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.
Operator: And your next question is from Maurice Choy from RBC Capital Markets.
Maurice Choy: 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?
Dai-Chung Yu: 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.
D. James Harbilas: 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.
Maurice Choy: 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?
Dai-Chung Yu: 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.
Maurice Choy: 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.
Dai-Chung Yu: 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?
Randy Toone: 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.
Operator: Your next question is from Robert Catellier from CIBC Capital Markets.
Robert Catellier: 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.
Dai-Chung Yu: 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.
D. James Harbilas: 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.
Robert Catellier: Right. So you're not going to have a lot of optimization exposure other than what you need for operational flexibility?
D. James Harbilas: You bet.
Robert Catellier: 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.
D. James Harbilas: 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.
Robert Catellier: 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?
Donald Jenkins: 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.
Operator: Your next question is from Ben Pham from BMO.
Benjamin Pham: 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?
Dai-Chung Yu: 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.
D. James Harbilas: 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.
Benjamin Pham: 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?
Dai-Chung Yu: 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.
Benjamin Pham: 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?
D. James Harbilas: 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.
Benjamin Pham: 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.
D. James Harbilas: 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: [Operator Instructions] And your next question is from Patrick Kenny from National Bank Financial.
Patrick Kenny: 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?
D. James Harbilas: 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.
Patrick Kenny: 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?
D. James Harbilas: 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.
Patrick Kenny: 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?
Dai-Chung Yu: 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.
Operator: There are no further questions at this time. Please proceed with the closing remarks.
Aaron Swanson: 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.
Operator: Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect your lines.