AltaGas Ltd.

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas fourth quarter 2024 financial results conference call. My name is Sylvie and I will be your operator for today's call. All lines have been placed on mute to prevent any background noise. If you have any difficulties hearing the conference, please press star then zero for the operator at any time. After the speaker's 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 over to Aaron Swanson, Vice President, Investor Relations. Please go ahead, Mr. Swanson.

Good morning, and thank you for joining AltaGas's fourth quarter 2024 results conference call. Speaking this morning will be Vern Yu, President and Chief Executive Officer, and James Harbalas, Executive Vice President and Chief Financial Officer. We're also joined here today by Randy Thune, president of our midstream business, Blue Jenkins, president of our utilities business, and John Morrison, senior vice president of corporate development and investor relations. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website. 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 two 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. It's great to be here today to discuss our strong performance for Q4 and 2024 as a whole. I'll share key highlights from the year, provide an update on our two major midstream growth projects, talk about some recent commercial successes, and close by discussing some of the macroeconomic trends that are creating bigger tailwinds for AltaGas's growth. Then I'll turn it over to James, who will provide detailed review of our Q4 financial performance and review our strategic priorities. I want to start by thanking our employees and contractors for our strong results and doing it safely. Safety performance improved by 33% in 2024 over 2023, which gave us our best safety year ever. Delivering strong results and doing it safely is paramount, so thank you. Let's turn to slide four. We delivered 2024 normalized EBITDA of $1.77 billion, which was up 12% year over year. And this was at the top end of our 2024 guidance range. Our 2024 normalized EPS of $2.18 was up 15% year over year and was in the upper half of our guidance range. We continue to execute and advance key growth projects across our business. Within Midstream, we delivered record global export volumes of more than 122,000 barrels per day of LPGs to Asia in the year, with the VLGC leaving our terminals every four to five days. Customer demand to access our terminals was strong. The actions around U.S. tariffs on Canadian energy is creating uncertainty and driving higher demand for West Coast access. This further highlights the long-term advantage of AltaGas's global export platform. With U.S. tariffs, it's even more critical to connect Canada's energy exports to Asian markets, reinforcing the need for our third West Coast export facility, Reef, which commenced construction last August. We also made material progress on Pipestone 2 in 2024, which will add much-needed gas processing and liquids handling capacity to the Alberta Montaney. Our midstream business saw important commercial successes in 2024 with the signing of three long-term integrated gas processing and liquids handling contracts at Townsend and Pipestone One. And we doubled our global export tolling in 2024 over 2023. Turning to our utilities business, we made large investments in 2024. deploying more than $730 million of capital. This allowed us to make our system safer and more reliable while expanding our network by adding more than 12,000 new customers. On the regulatory front, we filed a new rate case in DC in Q3. We also extended our current ARP modernization program in DC to the end of 2025. as we continue to work with the DC Commission to put a new three-year modernization program in place. Corporately, we continue to reduce our leverage, which provides additional financial flexibility to execute on our strategic plan. Let's turn to our major midstream growth projects, where we've made strong progress on construction. Both Pipestone 2 and Reef remain on time and on budget. Let's start with Reef on slide 5. Multiple work streams are currently underway, including uplands work, rail and utilities construction, off-site fabrication, and jetty construction. One of the key risks to the project, the earthwork site preparation is mostly behind us. We are 90% complete on overburden removal and on track to finish by the end of this month. We were able to store all of the overburden on the island, and this is a positive cost savings. Rock blasting is progressing well and on track to be complete in the next few months. Work has begun on site grading and the facility foundations. Off-site fabrication in Asia is progressing nicely with the accumulator and bullets approximately 65% complete. Compression and refrigeration fabrication is also progressing with that work being done off-site in Western Canada. All of this fabrication work is taking place in controlled manufacturing environments on a modular basis. It will then be assembled on-site. which materially reduces project execution risk. Work on the jetty is progressing. We now have 78 piles driven into the seabed. We have seen better efficiency over the past six weeks as bad weather slowed progress in December and January. As we announced in February, we have now met our reef export tolling target, which significantly de-risks our global export business. We now have the option of adding further tolling contracts at our discretion. Turning to Pipestone 2 on slide 6, the project is also progressing well. The acid gas injection wells and the gas gathering system are complete. Principally all project work has either been executed or is under fixed price EPC awards. As you can see in the pictures on the right hand side of the slide, there has been strong progress on facility assembly over the past eight months, with roughly 65% of the facility now complete. Like REEF, a significant portion of the remaining work is taking place in controlled manufacturing environments, and then will be assembled onsite following our standard project execution model. There have been no safety or quality issues experienced onsite and the project remains on track for December 2025 in service date. As a reminder, the facility is 100% backstopped by long-term take-or-pay contracts with marquee producers. Turning to slide 7, I want to discuss a recent agreement with Kiera. We view this as a positive development for both companies. The agreement leverages our respective infrastructure to drive the best industry outcomes. For AltaGas, we secured 12,500 barrels per day of export tolling volumes under a 15-year agreement, which provides our company with stable and predictable export volumes and cash flows. We also gain access to KIRA's extensive rail, storage, and logistics network in Alberta's industrial heartland, which will allow us to efficiently connect LPG volumes to our global exports network. Through this transaction, we also secured long-term capacity at KFS with take-in kind rights. LPGs from our pipestone plants will now be fractionated at KFS and then moved to global markets through our export facilities. Our agreements allowed Kiera to provide its customers increased access to Asian markets, and our committed volumes helped backstop de-bottlenecking and expansion at KFS. Slide 8 highlights our long-term tolling contracts. We expect our tolled export volumes, which have more than doubled since 2023, to remain around today's level for the next couple years. before rising to more than 100,000 barrels per day after a reef comes online. We believe this level of tolling strikes the appropriate balance of having stable and predictable cash flows, while continuing to benefit from the structural merchant spread between Canada and Asia. This results in AltaGas's long-term EBITDA coming from take-or-pay cost of service, or fee for service contracts to reach approximately 90%. Turning to slide nine, the short and long-term demand for energy continues to rise. Natural gas is and will continue to be the most reliable, affordable, and scalable solution to meet this growing energy demand in North America and globally. Natural gas continues to represent two-thirds of household energy consumed in the United States and has a three to four hundred percent cost advantage over electricity for space heating. As such, the long-term demand outlook for natural gas and our utilities is robust. When we layer in the expected increase in gas demand from coal retirements and the addition of data centers, the market is pointing to up to 25% plus increase in gas-fired power demand by 2030. The Canadian midstream outlook was equally strong, as shown on slide 9. AltaGas continues to benefit from two strong macro tailwinds. The first is growing natural gas production volumes from western Canada due to increased egress from LNG Canada. And the second is the rising demand in Asia, where LPG consumption is expected to increase by more than 40% by 2040, which will need to be satisfied with imports from North America and the Middle East. Canadian natural gas production is expected to rise 25% by 2030, which will primarily come from the Montney. This increase will deliver higher NGL volumes, that are already oversupplied in Western Canada. And all of these new NGLs will need to be exported to global markets. These tailwinds in the energy fundamentals will provide additional long-term growth opportunities for AltaGas, which James will discuss, along with providing further details on our fourth quarter performance, our forward outlook, and our strategic priorities.

Thanks, Vern. Within our utilities, which are shown on slide 11, we continue to have strong long-term growth opportunities. We have more than $1.7 billion of ARP modernization capital to be deployed over the next four years. These programs allow us to balance the need of improving the long-term system safety and reliability of our network while ensuring we can deliver timely returns on our capital to our shareholders. We continue to see strong new customer demand that has averaged approximately 1% new meter growth per year, which is approximately 40% above the national average over the last 10 years. We're also working with our regulators in Michigan to advance the Keweenaw connector pipeline and expect to seek regulatory approval in 2025. The project will be similar in size to the Marquette Connector and will improve system reliability and extend service to 14,000 customers in the Keweenaw Peninsula. And finally, the data center opportunity for AltaGas continues to be very encouraging and complements our already robust utilities growth outlook. As you can see on slide 12, PJM is expected to realize capacity shortfalls as early as 2026. This is creating the need for data centers to look at alternative energy solutions. We continue to work with numerous data center developers in Northern Virginia to build pipeline interconnects to provide natural gas for on-site power generation. Business development and engineering work on these opportunities is expected to progress through 2025 with potential construction in 2026 and onwards. We are pursuing these opportunities on a de-risk basis through traditional rate-regulated investments with unique rate structures. Within Midstream, while we are acutely focused on delivering Reef and Pipestone 2, we are also continuing to evaluate other organic growth projects in our development pipeline as a result of strong customer demand, which we highlight on slide 13. At Dimmesdale, which is a Montney natural gas storage facility that we acquired as part of the Pipestone acquisition, we are evaluating a potential two-stage facility expansion based on strong customer interest for additional storage in the area. Current storage capacity asset is 15 BCF, but we can increase capacity to 69 BCF, and the facility can be utilized for LNG balancing needs in the Montney. We are currently evaluating a RIPIT methanol removal project in the near term, which will increase the number of downstream markets that RIPIT can ship LPGs to in Asia and brings price optimization opportunities. We continue to advance work at North Pine, which is our frack in northeastern BC. Although we recently completed an optimization project to increase throughput, volumes at the facility are approaching its nameplate capacity. We are currently working through engineering and commercial to evaluate a substantial increase to capacity to meet our customer needs in the area. We also continue to advance Pipestone 3 to fulfill the additional needs for deep cut gas processing capacity in the Alberta Montane. We continue to see strong demand in the area for gas processing infrastructure. And lastly, we are advancing regulatory and engineering work for additional phases of REEF, given the commercial success we have had on the first phase and the importance of ensuring more Canadian energy reaches global markets at premium prices. We believe having a wide range of projects with different gestation periods will allow us to continue to grow the enterprise on a consistent basis while having the optionality to advance the best projects. As always, we are focused on moving these opportunities forward in a methodical manner as part of our long-term strategic plan and balancing our corporate priorities of growing the enterprise, deleverage the balance sheet, and returning more capital to our shareholders over time. Turning to our financial results in more detail, we are pleased with our fourth quarter and full year 2024 results. Fourth quarter normalized EBITDA of $520 million was up 4% year over year, while full year normalized EBITDA of $1.77 billion was up 12% year over year and was at the top end of our 2024 guidance range. Fourth quarter normalized EPS of $0.76 was in line with the fourth quarter last year, while 2024 normalized EPS of $2.18 was up 15% year-over-year and was in the upper half of our guidance range. Operational execution was strong across the enterprise in the fourth quarter and was reflective of the purposeful steps we have taken to execute on our strategic priorities, including commercial de-risking, de-leveraging, and cost management initiatives. In terms of segmented results, let's start with utilities on slide 15. Utilities normalized EBITDA was $336 million in the fourth quarter of 2024, compared to $311 million in the same quarter of 2023. The largest drivers of the 8% year-over-year growth were cost management, increased contribution from investments in rate base over the past year, and higher revenue from the 2023 D.C. rate case decision. These factors were partially offset by warm weather in D.C. and Michigan, which do not have weather normalization, and lower contributions from the retail business, which had stronger performance in the fourth quarter last year. Utilities' own M costs were down 7% year-over-year in the fourth quarter, as we continue to focus on process efficiencies, centralizing functions, and core operations. As we have shared in the past, we will continue to operate with a high degree of capital costs and regulatory discipline in the years ahead. We deployed $178 million of capital in our utilities during the fourth quarter and $722 million for the full year. This included $85 million of modernization investments in the fourth quarter and $359 million for the full year. These investments are focused on upgrading the network to improve safety and reliability. Over the past five years, these investments have helped contribute to a nearly 50% reduction in leak rates across the WGL network, which demonstrates the importance of these ongoing investments. Asset modernization and system betterment will remain a key focus in 2025 and beyond, which will allow AltaGas to deliver the lowest cost and most reliable form of residential and commercial heating in our jurisdictions. Turning to the midstream segment on slide 16, Normalized EBITDA of $182 million for the fourth quarter was consistent with last year, while full-year midstream EBITDA of $785 million was up 15% year-over-year. Specific to the fourth quarter, stronger global export volumes and higher throughput across the midstream value chain were offset by lower extraction volumes due to ethane reinjection, a material increase in total export volumes, which delivered increased predictability but carried lower margins, and lower contributions from MVP due to the recording of equity earnings relative to AFUDC recorded in 2023 when the pipeline was still being constructed. The first two quarters of operations at MVP showed strong operating performance with no surprises and has run near capacity to start 2025. The global exports business shipped more than 122,000 barrels per day of LPGs to Asia in the fourth quarter, which was up 34% year-over-year. This included approximately 82,000 barrels per day across 13 ships at Ripit and 40,000 barrels per day across seven ships at Ferndale. As we highlighted coming into 2024, one of our major strategic initiatives was commercial de-risking. which we delivered on with tolling volumes on exports approximately double 2023 levels. Despite Canadian natural gas price weakness throughout the fourth quarter, AltaGas's facility volumes were strong with approximately 15% year-over-year growth across our midstream value chain. This speaks to the strategic location of our assets and some of the most prolific resource plays in our commercial relationships with high-quality customers. This included our GNP volumes increasing 12% year-over-year in the fourth quarter, with Townsend showing the strongest growth with volumes up over 20% year-over-year, while our fractionation, extraction, and liquids handling volumes were up 32% year-over-year in the fourth quarter, led by North Pine and Hermann. Currently, we have 87% of AltaGas's expected first half 2025 global export volumes either told or financially hedged, with an average FEI to North American spread of approximately $19 U.S. per barrel for the non-tolled volumes. Given the uncertainty surrounding U.S. tariffs on Canadian LPGs being exported into the U.S., the 2025-2026 NGL recontracting season is much more fluid than normal, with multiple moving pieces. As such, we are taking a measured approach on our market positioning. we will have a more comprehensive update on our procurement and financial hedging activities when we report first quarter results. We continue to be active locking in costs across the export value chain, with substantially all of AltaGas' 2025 Baltic Freight exposure effectively hedged through a combination of time charters, financial hedges, and tolling arrangements. In the corporate and other segment, we reported normalized EBITDA of $2 million compared to $9 million in the fourth quarter of 2023. These results were mainly driven by lower year-over-year contribution from Blythe due to KISO transmission outages temporarily reducing Blythe's generating capacity and merchant opportunities. Turning to our outlook on slide 17, we outlined the 2025 guidance headwinds and tailwinds that we see so far. Overall, the opportunities and risks are fairly balanced, and we are reiterating our 2025 guidance ranges of normalized EPS $2.10 to $2.30, and normalized EBITDA of $1.775 billion to $1.875 billion. Moving to the 2025 capital budget on slide 18, There have been no major shifts in our capital plan, and we expect to deploy $1.4 billion of CapEx in 2025, including ARP programs at the utilities and the reef and Pipestone 2 projects in midstream. As shown on slide 19, we reduced our adjusted net debt by approximately $460 million year-over-year in 2024 and exited the year with 4.4 times adjusted net debt to normalized EBITDA, excluding hybrids, and continue to move towards our four times target metric. We have demonstrated considerable progress on this objective over the last several years, reducing leverage by more than half since 2018. While the journey continues, we expect the potential monetization of MVP to accelerate our path to achieving our targets. We are currently in the price discovery phase for our 10% non-operated stake in the pipeline and expect to provide an update during the first half of 2025. In closing, we are very happy with the fourth quarter and 2024 results. We made considerable progress across all corporate priorities while creating strong shareholder value. As we look ahead on slide 20, we will continue to focus on many of the strategic priorities we had in 2024. which continue to surface shareholder value. Specifically, we are focused on growth, commercial de-risking, and strengthening the enterprise with a focus on long-term compounding per share value, as evidenced by our track record on slide 21 over the past five years. And with that, I will turn it back to Vern for a quick closing comment.

Just before I return to Q&A, I want to take a moment to discuss the potential impact of U.S. tariffs and how the new administration could impact our business. We all know that Trump administration's energy policies are highly supportive of natural gas in our utilities. The administration has already started to unwind space heating electrification policies, which will enhance energy affordability reliability, and security for our utility customers. The administration is highly supportive of energy infrastructure investments. PHMSA has already started highlighting the importance of upgrading aging natural gas infrastructure, and we expect PHMSA to become more active in its support of ARP programs and gas LDCs. In terms of US tariffs on Canadian energy, the situation is obviously dynamic, and the impacts will be ultimately determined by the size and duration of tariffs. With respect to our 2025 capital program, we are well protected and do not expect an impact on our current capital cost estimates or any supply chain challenges. In midstream, tariffs will have a negative impact on the cash flows of our upstream customers. But tariffs will be partially offset by a stronger U.S. dollar. And as a result, we do not expect material changes to natural gas and NGL production volumes. Canadian NGL prices will partially discount to offset the cost of tariffs, while Asian prices will remain unchanged. This will cause a wider Canada to Asia LPG spread. which we expect to be modestly additive to our merchant export margins. In terms of our utilities, we expect only a modest impact on our operations and customer bills. SEMCO will potentially face some higher gas costs, which it will flow through to its customers, as approximately 15% of SEMCO's gas supply comes from Canada. Should tariffs remain in place in the long term, this will drive higher inflation at our utilities and lead to higher customer bills. And with that, we'll open the call up for Q&A.

Thank you. Ladies and gentlemen, we will now conduct the analyst question and answer session. If you would like to ask a question, please press star then number one on your telephone keypad. If you would like to withdraw from the question queue, please press star then number two. There will be a brief pause while we compile the Q&A roster. And your first question will be from Rob Hope at Scotiabank. Please go ahead, Rob.

Morning, everyone. First comment or first question is on the 2025-2026 NGL year. You know, just realizing that it is dynamic, can you maybe add a little bit more color on why you're not giving the full year guidance and potentially holding some back. Is that to reflect the potential that you could see increased margins if tariffs do get enacted or when they get enacted? And I guess secondly on that, are you seeing new customers or increased appetite for tolling from the facility due to diversification of markets?

Hey Rob, it's Vern here. Can you just clarify that first part of your question on what you mean by the NGL year and the guidance?

Yeah, I'm just wondering for the export volumes that you're financially hedging, you're only giving the 87% for H1 and you didn't notice that it is dynamic, the environment. Just wondering if you're holding... if you're willing to take some additional exposure there, just given the fact that the spreads could widen in your favor.

Rob, it's James here. So when we, obviously the recontracting year runs from April 1st to March 30th of the following year, and we're about three weeks away from crystallizing our supply and what split is going to be merchant versus tolling. Obviously with our effort to de-risk supply, our cash flows, we expect a slightly higher tolling percentage. So once that comes into view, then we can actually go ahead and hedge out the remaining merchant barrels. And that's when we'll be providing guidance for the back half of the year. So that's really why the hedging book and the disclosures are focused on the first half of the year. We need the tolling versus merchant split to crystallize in the next three weeks. And then we'll start to layer on financial hedges on our remaining merchant barrels for the balance of the year.

The only thing I'd add to that is obviously with the uncertainty of tariffs, the demand for tolling is extremely high. So we just need to work through with our customers which tolling contracts we're going to accept for this year.

I appreciate that. And then in the prepared remarks, you highlight a number of kind of the next phase of growth for the company, whether it be kind of Dimmesdale or Pipestone 3. How do you think about the pacing of these growth projects, just given the good spend for Reef right now, as well as the desire to move down leverage?

I'll start off and then James and Randy can chime in here. As you know, we're almost done Pipestone 2, so that's a big, significant use of capital in 2025. And we will be, have made very significant progress in, um, reef construction this year as well. So, uh, as we roll forward in time with some of these projects, the bigger, most of these projects take a year or two to build out. So we'll have more capacity, um, once reef is finished, uh, to, um, look at where's the best place for us to deploy our capital. Obviously, we have lots of opportunity in the utility as well, where we can grow rate-based by up to 8% per year for the foreseeable future. So it's an envious position to be in, to be able to have to allocate capital to the best returning projects on a risk-adjusted basis.

And Rob, the only thing I'll add, and we touched on it in our prepared remarks, you know, if you look at the portfolio of projects that we have in front of us from an organic growth standpoint, they all have different gestation periods. And a lot of that is driven by the length of customer discussions to be able to get some commitments to be able to move forward to an FID and obviously different permitting timelines with respect to these projects as well. So that'll help us to be able to fund some of these under our existing investment capacity because we could stage them just given some of those dynamics that would come into play.

Appreciate the color. Thank you.

Thank you. Next question will be from Morris Choi at RBC Capital Markets. Please go ahead, Morris.

Thank you, and good morning, everyone. I'm just going to start off with Reef. I think in your prepared remarks, you mentioned that productivity is increasing on in-water piling. There's been positive cost savings on overburden removal. Will all these positive updates plan or are we trending below budgets? And a quick add-on to that, seeing as you're going through your engineering work for future phases, can you speak to what work you've done or can do to sort of pre-build some of the infrastructure for some of these future phases?

Sure. So, Maurice, as you know, the first phase of REIF does pre-build a whole bunch of infrastructure for the subsequent phases of REIF. The biggest things we're obviously doing is the rail facility and the jetty. The rail facility will be able to accommodate, when it's complete, 3,000 cars, so it's a very sizable rail loop. Future phases would still require incremental rail offloading, but the rail loop is pre-built for multiple phases of expansion. That's similar. For the jetty as well, the jetty will be able to accommodate significantly more NGL loading than we're doing in phase one. So subsequent phases of reef will be materially lower on a capital cost basis per barrel of export. So that's a good tailwind for us. As far as commenting on the reef capital cost, estimate. It's unchanged at this point. I think we talked about in our remarks that we have about 50% of the project either incurred or under fixed price EPC contracts with that rising to about 60% in the next month or two. But there's still a few pieces of work where there is a little bit of risk. So I don't think it's appropriate to change our capital cost estimate at this point. But a couple of the big pieces of risk have been materially de-risked. The biggest, as I think I talked about in the prepared remarks, was the earthworks phase. Given that this is a greenfield site, the geotechnical work of removing the musk egg and the rock blasting were probably the biggest risk we had to a change in capital cost.

That's a great comment. Just to finish off on a question on leverage, I know on slide 19, you've mentioned that the company is on track to reach its long-term targets in 2025. I know you've mentioned in the past that MVP provides the most immediate path to achieving your targets. So given that you've exited the year at 4.4 and you're about, let's call it, 0.4 away from your target, is it all MVP or are there other items that we should be considering for your deleveraging?

Hi, Maurice. It's James here. We've always said that MVP is obviously the quickest way for us to get there. And when we've been asked to triangulate what the deleveraging would be associated with MVP, that 0.4 to 0.5 times was always a number that we cited as us being able to crystallize once that process is complete and it would get us to that target.

And the Fed has said that whilst negotiations are ongoing, that 0.4, 0.5 television remains true based on the outlook.

So in terms of the process, I can definitely comment on where we are in the process, but I'm not going to speculate further other than the data points that I've shared with you in terms of where that's going to land. But I can tell you that it's a very robust process. We're in the middle innings. Obviously, the parties that are interested in the assets are the global players that would be attracted to assets that have these kind of characteristics in the form of strong cash flows, strong growth embedded within the opportunities on the main line and the Southgate expansion, and obviously strong counterparty credits. So our timeline continues to be the first half of 2025. That's what we embedded in our guidance from an MVP contribution standpoint. So we will be in a position when we release Q1 to provide a further update on that process. But we see strong interest in this pipeline. Perfect.

Thank you very much.

Thank you. Next question will be from Robert Coutelier at CIBC Capital Markets. Please go ahead, Robert.

Hey, good morning. Before the call, I was going to ask about Reef, and now that you've met your tolling targets, what's your vision for further developing the site? You touched on methanol and some other opportunities. Can you give us maybe a broad outline of what you see as the pathway for to the next potential FID either at Rippert or Reef. And on Reef and the methanol opportunity, do you see the customer set, the demand side customers as being having some overlap with your existing customers?

Hey, Rob. I think the methanol project is very exciting because that opens up the entire Asian market to us. Right now, with the slightly higher methanol content that Canadian propane has, there is a slightly limited buyer set, which is predominantly in Korea and Japan, whereas if the methanol spec does come down a little bit, for sure we'll be able to access the full Asian market, including China, PDH facilities in China. So the project itself is a modest amount of capital, but it fully opens up that 3 million barrel a day Asian market. So that diversifies our customer mix. And I think it's fair to say we're continuing to look at tolling deals with Asian offtakers who really want to have that lower methanol spec. So the commercial interest on reef has obviously been very strong. And I think that's why in our preparatory remarks, James talked about us kicking off engineering design and permitting work for reef, subsequent phase of reef. Right now, we're just working through what the permitting process is going to look like, as I think we were a little surprised by the strong customer, the very strong customer demand we're seeing. So I think at our next Q1 call, we'll be able to give people more color on what that permitting timeline could look like.

Okay, that's helpful. So there could be customer overlap, but really, do you have an opportunity to broaden your market reach?

Yes, materially broaden.

Yeah, okay. Just on the... the utilities. I know you spent some time over the last number of months plus on some advocacy work with the regulator, et cetera. I'm wondering what progress you feel you'd make towards getting some sort of weather protection specifically for the DC franchise.

So we have in our rate filing, We've requested weather normalization. Maybe I'll just turn it over to Blue and give you some color on the mechanics of what we've got in our rate case ask. Yeah, thanks, Vern.

So as Vern pointed out, in our previous rate case, we did ask for weather normalization. We didn't get that, but we did get a conversation coming out of that rate case that the commission gave us a path to follow to try to bring that forward, which we have done. That included working with our interveners, making sure that they understood what the benefits were to customers and how the process would work. We did file that subsequent weather normalization in the current rate case and the conversations to date, you know, I'll say they're trending positive. I think the cold weather in Q1 helps that conversation in order to let customers plan accordingly for something that looks more like levelized bills based on average weather. So You know, it's always tough to see where that will go, but the conversations with the commission and interveners through the process of both the last rate case and this one have trended positive in my view.

Okay, thank you. I'll get back in the queue.

Thank you. Once again, ladies and gentlemen, a reminder to please press star one should you have any questions. Next will be Ben Pham at BMO. Please go ahead, Ben.

Hi, thank you. Good morning. I'm questioning your balance sheet capacity, capital allocation, the $1.4 billion CapEx this year. Is there room to add more to that before you hit credit rating scrutiny or have any need to tap equity markets?

I think we're in the position, Ben, of spending $1.4 billion per year at our target credit metrics, and obviously we have a little bit of work to do in 2025 to get to those target credit metrics, our investment capacity will rise with Pipestone 2, with Reef, and subsequent rate cases at the utilities. So it's fair to say we're We've allocated capital to the best risk-adjusted rewarding projects for 25, and then we're going to have to wait for a little bit more cash flow growth before we're able to allocate more capital to the business.

Thanks, Brett Byrne. As you think about post-25 cutbacks, even through late decades, what's the thought process between midstream utility. Is it similar to this year, you think, where rate-based growth is below 8%, you push more to midstream, or do you see an area where that rate-based growth can eventually glide back to 8% or more?

Well, it's early days to start speculating about future projects, but I think the good news is we have lots of growth opportunities in front of us. The utility has 8% rate-based growth coming from modernization, customer ads, and that could theoretically grow if we're successful with a number of these data center opportunities in Northern Virginia. In Michigan, in front of us, we have, I'm going to butcher this, the QAnon connector, which is a very low-risk platform. modernization program for relatively large size for semco and that's going through its regulatory process now so there's tons of opportunity in the utility and then similarly there's tons of opportunity uh in midstream where we've talked about reef expansion further reef expansions pipestone expansion another pipestone plant north pine expansion so uh it's it's great to be in a position where we have a very significant competition for the investment capacity we have. And as we continue to work to maximize the value of our existing assets, every time we increase a dollar of cash flow, we increase our investment capacity. So that's why, if you look at our strategic priorities, we're so focused on continuing to narrow that ROE gap at the utility and continuing to try to increase the utilization of our existing assets in midstream.

Okay, great. Thanks, Vern. And just one last cleanup on MVP. I just wanted to check, is that your guidance? I assume that's assuming it's a cash coming in post-Burk approval, and is it just Burke that you would need blessing on?

Sorry, can you just repeat that last part of the question in terms of approvals?

Yeah, is it just, I mean, after you announce a potential sale, beyond that, what's the key milestone? Is it just a first side, approvals, and then your guidance? I just wanted to check, when you say mid-year or whatnot, I'm assuming that's when you get the cash coming in, post-approval?

That's right. Yeah, I mean, obviously, the way we've incorporated MVP contributions into our guidance was for six months of EBITDA and equity pickup from that asset. So we do feel that we can complete our process inclusive of approvals. in that first six months, the way we've laid out the timelines for round two. And if you look as a benchmark to the EQT Blackstone transaction that included some other FERC-regulated assets, we anticipate that those approvals would be very quick to receive. Okay, got it. Thank you.

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

Thanks, Sylvie. Thank you, everyone, for joining the call once again. Have a great Friday.