AltaGas Ltd.

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas first quarter 2024 financial results conference call. My name is Sylvie and I will be your conference 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 operator assistance 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 call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.

Thanks, and good morning, everyone. Thank you for joining us today for AltaGas' first quarter 2024 financial results conference call. Speaking on the call this morning will be Vern Yu, President and Chief Executive Officer, and James Harbalus, Executive Vice President and Chief Financial Officer. We're also joined here this morning by Randy Toon, Executive Vice President and President of our midstream business, Blue Jenkins, Executive Vice President and President of our utilities business, and John Morrison, Senior Vice President, Corporate Development and Investor Relations. We'll proceed on the basis that everyone is taking the opportunity to review the press release and our first quarter results. This call is webcast and we encourage those of you listening on the phone lines to follow along with the supporting slides that can be found on our website. As always, today's prepared remarks will be followed by an analyst question and answer period. As for the structure of the call, we'll start with Vern Yu providing a few of the first quarter highlights. Then he'll discuss the macro outlook for the business, and provide an update on our reef project. This will be followed by James Harbilis discussing our 2024 priorities and our first quarter operating performance in more detail. Then he'll provide an update on MVP and close with our 2024 outlook and guidance. And then we'll leave plenty of time at the end for Q&A. Before we begin, I'll remind everyone that 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. And with that, I'll now turn the call over to Vern Yu.

Thanks, Adam. Good morning, everyone. It's great to be here today to discuss our strong first quarter results. I'll talk about the highlights from the quarter, then touch on the macroeconomic outlook, and provide an update on our reef project before turning it over to James. Let's start on slide four. Our diversified platform continues to deliver strong results as we execute on our strategic plan. This quarter, we delivered normalized EPS of $1.14 and normalized EBITDA of $660 million, an increase of 15% and 13% year-over-year, respectively. We saw results in line with our expectations for our utilities business and stronger-than-expected performance in midstream. which included record first quarter global export volumes and contributions from the newly acquired Pipestone assets. We exported over 115,000 barrels a day of propane and butane to demand markets in Asia, with 12 ships departing from Ripit and seven from Ferndale. Ripit had a record quarter with 77,000 barrels a day of exports due to great operating performance by the team and growing Western Canadian LPG supply. We completed a very successful NGL recontracting season on April 1st, where we'll have 56% of our 2024 export volumes under tolling agreements. This is ahead of our near-term targets and part of our strategy to grow the take or pay or cost of service portion of our business to about 90% of our total EBITDA. We also commissioned our third VLGC time charter, and extended the term of a previous time charter agreement. In the utilities, our number one priority is to safely and reliably deliver affordable energy to our customers. In the quarter, we invested $179 million into our network to make it safer and more reliable while lowering our emissions. On April 1, we filed an application in Michigan to extend SEMCO's modernization programs by an incremental $114 million, which will extend the program out to 2027. This will be used to improve the safety and reliability of our system while reducing long-term operating costs and lowering emissions. Although weather was warmer than usual in Michigan and DC, financial performance was in line with our expectations. due to a better than expected rate case decision in DC, strong retail performance, and continued cost management. Enhanced efficiency will continue to be a focus for the balance of 2024. Turning to slide five, we remain very positive on the fundamentals for natural gas, NGLs, and the outlook for both of our businesses. Natural gas is affordable, reliable, and the fastest growing form of energy in the United States. Moving from coal to natural gas has been the largest driver in reducing emissions globally over the last decade. And the average natural gas-powered home in the U.S. uses 42% less energy and produces 20% less CO2 than an electric-powered home. Last week, we saw the U.S. federal government take further steps to crack down on emissions from coal-fired power generation. These new rules will force the shutdown of many of the U.S.' 's coal power plants, further increasing the need for natural gas. All of this demonstrates why natural gas is critical across our jurisdictions. Slide 6 highlights why we believe we are in a unique inflection point and highlights the importance of natural gas and the longevity of our utilities. A big part of this is rising energy demand for AI and data centers within WGL's service area. Coal plant retirements and data center growth are expected to boost U.S. natural gas demand by 5 to 10 BCF per day by 2030. Turning to Canadian midstream on slide 7, the outlook is equally robust. Gas development activity in Canada is healthy, as producers look beyond current near-term headwinds and are focused on LNG Canada coming online. Gas drilling is at a three-year high. In total, Canadian gas production is set to rise 40% through 2030, and Canadian NGL production is expected to increase by more than 35% over the same period. With limited growth in domestic demand, all of this product needs to be exported globally. Let's move to slide eight. I'm pleased to provide an update on our reef project, where we continue to move towards reaching an FID by the end of Q2. Reef is planned to be developed and constructed in phases. This approach allows for the most capital efficient builder of the project and matches export supply with reef's export capacity. The first phase of the project will include the LPG export facility. which shall have an initial export capacity of 55,000 barrels per day, 600,000 barrels of LPG storage, rail offloading and logistics infrastructure, and the new jetty, which is shown in blue on the slide. The first phase of reef will only use 10% of the dock's capacity. Subsequent phases are shown in yellow and orange on the diagrams. and will provide long-term expansion opportunities for years to come. Slide 9 shows the location of Reef relative to Ripit and the surrounding area. Just like Ripit, Reef has geographic and logistical advantages, and these are highlighted on slide 10. It will benefit from Prince Rupert's deepwater ice-free harbour and its proximity to Asian markets. and the dock will have multi-vessel loading capabilities. At startup, Reef will have 10 dual-sided rail offloading slots and 25 kilometers of rail track, which will eliminate rail congestion and provide enhanced storage options if there are logistical disruptions. As seen on slide 11, progress on Reef continues to be on track with 85% of the site preparation now complete. On slide 12, we update the key gating items to reach FID. Front-end engineering and design is more than 95% complete, and we are ready to commence earthworks and in-water piling, as well as award other major work streams. Reef benefits from being on a single site, having all of its key regulatory approvals in hand, and from our previous experience in building rip-its. We plan to minimize on-site work to reduce capital cost risk, with 90% of the equipment, packaging, and pipes being prefabricated off-site, limiting our exposure. And we expect to have more than 60% of the project's costs fixed before we move into construction of each workstream. On the commercial side, we now have 56% of our global export volumes under tolling agreement, with a diversified mix of over 30 customers, including producers, aggregators, and downstream off-takers. Demand for REAP's initial capacity has been very strong. We are now in negotiations with multiple counterparties for more than 100% of REAP's phase one capacity. Based on the contracts in hand and the status of our negotiations, commercials no longer considered a gating item to a positive FID. We're proud of AltaGas' performance in the first quarter, and we're very excited about the road ahead. With that, I'm going to turn it over to James to get into the details on the quarter, review our 2024 priorities, and provide an outlook for the balance of the year.

Thank you, Vern, and good morning, everyone. We are pleased with our first quarter performance, the strong execution from our operations teams, and the ongoing advancement of our strategic plan. I'll start by reiterating our 2024 priorities. We'll provide a more detailed review of operating performance across the platform, then discuss recent positive developments on the Mountain Valley pipeline, and close with an update on our 2024 outlook. Turning to our near-term priorities on slide 13, we remain committed to an equity self-funding model, continued improvements in our balance sheet by moving towards our four-and-a-half times leverage target, and operating with strong capital discipline by ensuring the best projects continue to be funded. Within our utilities business, we continue to focus on driving returns and closing the remaining ROE gap at WGL. As such, look for us to continue our focus on maintaining capital, cost, and regulatory discipline. On the regulatory front, we are actively preparing a DC rate case to be filed in the third quarter this year and WGL is considering whether we need to file a rate case in Maryland in the latter part of 2024 to ensure our rates reflect the investments we have made in that jurisdiction for the safe and reliable operation of our assets that serve our customers. Within the midstream business, we are advancing Reef and Pipestone II, which are key growth projects for this segment. We continue to use our strategic infrastructure to progress our global exports, tolling, and commercial de-risking targets. We remain on track to deliver these priorities. Moving to our midstream segment, which is shown on slide 14, normalized EBITDA was $247 million for the first quarter, representing a 35% increase year over year. The segment benefited from record first quarter volumes within our global export business, the addition of the newly acquired Pipestone assets, AFUDC being recorded on MVP, and strong cost management. We exported over 115,000 barrels per day of propane and butane across 19 VLGCs in the quarter. This included an all-time record of more than 77,000 barrels per day at Ripit and approximately 38,000 barrels per day at Ferndale. Export volumes were higher than we originally expected, principally due to favorable ship timing, which was supported by strong logistical execution at the terminals and along the entire value chain. increased LPG supply, and robust demand in Asia. As we highlighted last quarter, the first quarter of 2024 was set to benefit from one delayed ship in December 2023 that was loaded at the start of January 2024. In addition, we also benefited from one additional ship that was loaded in late March that was previously expected to be loaded in early April. This latter timing had the impact of shifting profits previously expected in the second quarter to the first quarter, with no net change to our full-year volume expectations. We continued to progress our commercial de-risking initiatives during the quarter. This included completing a successful NGL re-contracting season on April 1st, with AltaGas realizing strong LPG supply commitments for the coming year, while also making considerable progress on medium-term tolling targets in recent months. This includes moving to 56% tolling starting in the second quarter of 2024. These agreements will provide our customers with direct market access to superior netbacks in Asia, while providing AltaGas the benefit of stable and predictable contracted cash flows. As part of this tolling success, UltaGas elected to crystallize certain financial hedges to avoid an imbalance of the financial and physical merchant barrels in the coming quarters. This resulted in a gain on settlements recorded in the first quarter of 2024. This has the effect of shifting profits associated with future quarters into the first quarter. We also commissioned the Boreal Voyager under a seven-year contract during the first quarter and extended an existing time charter for one VLGC with Astimos. These follow our commissioning of the Boreal Pioneer in December 2023, which is also operating under a seven-year agreement. These time charters de-risk, reduce our shipping costs, and when combined with tolling volumes and our financial hedges, we have eliminated our Baltic freight exposure for 2024. Outside of global exports, midstream performance was also strong during the first quarter. Performance across the balance of the midstream platform remained strong and benefited from the addition of the newly acquired Pipestone assets. However, gas processing volumes during the quarter were curtailed slightly versus our expectations due to cold weather and maintenance-related outages at certain facilities. These volumes have since recovered. During the first quarter of 2024, AlteGas realized frac spread averaged approximately $25 per barrel, with most of the company's frac exposed volumes hedged. This was approximately $2 per barrel below realized frac spreads in the first quarter of 2023. Canadian natural gas prices are very soft given the combination of strong production growth that we have seen over the past year and weak winter demand that has been realized across North America for much of the winter heating season. With that said, we are not expecting this to have a material impact on AltaGas's throughput volumes or EBITDA in the coming quarters. Moving on to the utilities on slide 15, we reported first quarter normalized EBITDA of $437 million. This represents a 9% year-over-year increase despite the lost EBITDA and gain on debt defeasance that was recorded with the sale of the Elasti utilities in March 2023. which combined had contributed $29 million in the same quarter last year. Although we saw 15% fewer heating degree days than normal in our two weather-exposed jurisdictions of Michigan and D.C., utilities results were largely in line with our expectations, given strong retail performance, contribution from ARP investments across our network, the positive impact of the D.C. rate case, new customer additions, and strong cost management across the platform. During the quarter, we deployed $179 million of invested capital in the utilities on behalf of our customers. This included $85 million across our various asset modernization programs in the DMV and Michigan. These modernization programs improve the safety and reliability of our system, reduce leaks, and provide long-term productivity improvements. Within the corporate and other segment, normalized EBITDA was a loss of $24 million compared to a $2 million loss in the same quarter last year. This performance was driven by a planned turnaround at Blythe that was extended by 22 days as we elected to do some additional preventative maintenance while the facility was down. Blythe resumed operations towards the end of the first quarter and is expected to deliver results in line with our expectations for the balance of the year. Results in the corporate and other segment were also impacted by higher G&A related to employee incentive plans due to AltaGas' rising stock price. Turning to slide 16, we are pleased with the progress that has been made on the Mountain Valley pipeline. All water body and wetland crossings are now complete, and there is one mile of pipe left to install. We expect to see construction completed and final commissioning activities in the coming weeks. The project has made a FERC application to be placed into service shortly thereafter. Although we have had to be patient with the asset given the various setbacks over the years, we believe our patience will be rewarded. As a reminder, MVP is an interstate natural gas pipeline that spans more than 300 miles from northern West Virginia to southern Virginia, connecting to Transco. It will be a critical infrastructure asset that will connect upstream production in the Marcellus and Utica shale to growing downstream markets in the eastern U.S. The pipeline has 2 BCF per day of capacity and is fully subscribed under 20-year firm contracts. We are excited about the long-term demand for additional capacity on the line. The partnership has the ability to expand the pipeline by an additional 500 million cubic feet per day through additional compression, which was also highlighted by EQT on their earnings call last week. This is something the partners are considering progressing once the pipeline goes into service, given the strong long-term demand associated with power requirements from data centers, growing gas utility customers, and LNG exports. We have always been transparent with regards to MVP being a non-core asset for AltaGas's long-term strategy, and once the project is operational, we would pursue value-maximizing opportunities. As we have said in the past, crystallizing the value of our investment in MVP offers AltaGas the most immediate path to achieving our long-term leverage targets. On slide 17, we share our 2024 outlook. Following a strong first quarter, we are well positioned to achieve our 2024 guidance ranges of normalized EPS of 205 to 225. and normalized EBITDA of 1.675 billion to 1.775 billion. And when we look at the headwinds and tailwinds that we have seen unfold so far, it is a relatively balanced picture. As I mentioned earlier, there were two major timing events that benefited the first quarter results. The first was the ship timing global exports moving from April to March, and the second was the crystallization of certain financial hedges on expected merchant barrels that have been replaced with long-term tolls. The aggregate impact of these two events drove approximately $26 million higher normalized EBITDA on the first quarter of 2024 than would have otherwise taken place with a corresponding decrease expected in the balance of the year. As a result, we have reshaped our quarterly expectations, which are shown on slide 18, including slightly reduced Q2 and Q4 expectations and a modestly higher Q3 contribution. In closing, we are extremely pleased with our first quarter results. We also believe we offer a compelling forward value proposition as outlined on slide 19. We are a low-risk energy infrastructure platform that is positioned to provide stable and growing earnings and cash flows, which should support industry-leading dividend growth. We have visible and industry-leading growth in both our businesses, and we will remain disciplined allocators of capital, as we have shown over the past five years. We believe the execution of our long-term strategic plan should continue to drive outsized shareholder returns in the years ahead. And with that, I will turn it over to the operator for the Q&A session.

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

Good morning, everyone. First question, as you probably expect, would be on Reef. With the success that we're seeing on the tolling for the existing assets, can you just talk about how that is going to mesh with the potential expansion with Reef? Are you moving up tolls in anticipation of a Reef sanctioning so that the volumes will be fungible? And then, I guess more broadly, any updates on cost and returns on Reef as well?

Okay, thanks for the question, Rob. Obviously, we're very positive on the success we've had this year on increasing tolling as a percentage of our total export volumes. I think nothing's changed. We want the portfolio to get to about 60% total when we bring Reef on in the 2027 NGL year. That really helps us drive towards one of our strategic priorities of reducing the overall risk in the business. So today, about 80% of our EBITDA is take-or-pay, cost-of-service, or fixed-fee. Going forward, if we reach that 60% tolling framework for enhanced volume with Reef, we'll get to about 90% of our EBITDA under fixed-fee, take-or-pay, or fixed-fee. A fixed fee. So it's very exciting for us. I think the commercial interest that we've seen, obviously, as we talked about in the prepared remarks, has been extremely strong. The value that we're providing the customer was very good through the last year, and people are seeing that value. So that's why I think you've seen the uptick in the tolling. We're still very bullish on the returns on the project. We think it's going to be a very healthy project for us. And the subsequent phases are obviously going to be even more profitable as we're pre-building a bunch of the infrastructure in phase one. So our expectation is that the first phase is still a six to eight time build multiple, which will be very healthy. And then what we will once reef is up, have the optionality to move barrels around between rip it and reef. So again, that just enhances our operational flexibility. I appreciate that.

And then maybe let's just move over to northeast BC, you know, with LMG Canada around the corner, you know, despite the fact that gas pricing is relatively weak now, volumes seem to be trending in the right direction. So can you remind us, you know, how much white space you have in your assets there? And Of the portfolio of expansion projects that you've previously highlighted, which ones are progressing the quickest?

Yeah, I'll just start and then Randy can answer the rest. I think obviously we have a white space at Townsend and Randy can fill you in on what we have there. We also obviously have fractionation at North Pine, which is in high demand right now. And we're quite bullish about our prospects there. Go ahead, Randy.

Well, yeah, so up in Townsend, we have about 500 million a day of both shallow cut and deep cut processing capacity, and we're roughly about 50 to 60% utilized right now. So we do have white space, but we are progressing discussions with producers in the area that need that infrastructure. And at North Pine, we just did a low-cost de-bottleneck, and we feel we have about 25,000 barrels a day of capacity at North Pine, which gives us a little bit of breathing room before we do a larger expansion. But those discussions with customers are progressing, and we would hope to make an FID on a North Pine expansion closer to the end of the year.

I appreciate that. Thank you.

Thank you. Next question will be from Jeremy Tonnet at JP Morgan. Please go ahead.

Hey, good morning. This is Eli on for Jeremy. Maybe you want to start on just a little bit further capital allocation prioritization. You just touched a little bit on the kind of some of the opportunities, but maybe more broadly thinking past an MVP divestment and balance sheet de-risking. How is the team kind of weighing additional growth projects versus other capital deployment options? you know, if midstream growth was the first call on capital, what types of projects might we see? Yeah, just general thoughts there.

Okay, Eli, that's a great question. So when we get our balance sheet to four and a half times debt to EBITDA, we'll have about a billion and a half dollars per year, what we call investment capacity. So that's the amount of capital that we can reinvest in the business or do other things while maintaining our debt metrics. So the calls on that will be about $400 million per year of maintenance capital and capital that will be used at the utility to offset depreciation. Then we have probably about $400 million per year of accelerated pipe replacement capital. So those two combined come up to about $800 million. That on a run rate basis leaves us about $700 million a year of what we call discretionary capital or discretionary investment capacity. Right now, based on where projects are coming in, we would reinvest that capital in organic growth because that capital would be highly accretive and continue to grow our cash flow streams into the future. So when we do look at that, then we will look at the projects we have in the hopper, whether they're midstream or utility, and we'd stream capital to the projects that provide the biggest spread over their risk adjusted hurdle rates. So right now we're seeing lots of highly accretive transactions in midstream and you've seen us in 2024 increase our allocation towards that part of the business. But the good news is if we defer some capital at the utility, we'll have that opportunity to spend that capital in subsequent years as the amount of modernization and customer growth embedded in the utility continues to look very strong. In other circumstances, If we don't have great organic projects, we do also have the ability to pay down more debt, to create more dry powder, or even buy back shares. But at this point, with our current valuation, organic capital is a much superior investment for us.

Got it. That's great, Cullen. You know, you talked a little bit about the modernization program there and maybe just kind of sticking with the utilities business. You know, we obviously saw the positive rate outcome in D.C., which you touched on as well in the opening remarks. Maybe looking forward, where does the team still see ROE gaps? What jurisdictions are the top priorities there? And, you know, what kind of upside might we expect in that utilities business in the near or medium term?

Yeah, that's a good question. We do obviously have some ROE gaps still. I think the Maryland decision we got in December was a little less than we had hoped for and really on the timing of putting capital under rate base. So I think in James's remarks, we talked about how we were looking at another rate case in Maryland to continue to narrow that gap. We're obviously also doing things on our front to manage our own efficiencies and capital to make sure we narrow that up. But maybe, James, you could talk about the financial levers, and then, Blue, you can talk about the timing of when we're going to get after these things.

I'll just add to what Vern said in terms of some of the other financial levers. The two jurisdictions Vern touched on, one of them where we're anticipating a rate case, that's Maryland, D.C., has always been a jurisdiction that we've said is going to be a multi-year journey in terms of closing that gap, just given some of the rate lag associated with the length of the decision making of the regulators in D.C. So we are planning another rate case in D.C. in 2024 to help us progress to closing that gap. And obviously, some of the other financial levers that we've been pulling is just strong cost management to make sure that our cost structure is what's reflected in rates so that we can also help to close that ROE gap within our utilities. So, Lou, do you want to comment on timing with respect to that?

Yeah, thanks, James. Just a couple of comments. So, in D.C., we got the rate case with new rates effective this year. We will file early in Q3 for our next rate case in D.C., and we've been very open and transparent with our regulators there. about our process, and so that will come. We'll file in early Q3. In Maryland, as both James and Vern pointed out, the rate case decision we got was disappointing compared to our historical precedent. We now understand what that shift was, and we will look to file another rate case in Maryland to bring our capital into base rates and keep that current, and we'll file that sometime in the second half of this year. The other thing I would just point out to remind you, we did extend our accelerated pipeline replacement programs across all our jurisdictions. So that capital, the outlook on that capital is very good and we continue to ensure that we're managing that appropriately. And as Vern alluded to, we're pulling our cost levers, we're managing that closely. We continue to execute around our targets there and made good progress in Q1 and we'll continue in Q2 here. and continue to see that progress continue through the balance of the year.

Awesome. I'll leave it there. Thanks.

Thank you. Next question will be from Patrick Kenney at National Bank. Please go ahead.

Good morning. You guys touched on the rising demand for gas in the U.S. from data centers and other industries. I know you're mainly servicing residential and commercial customers, but just wondering if you could provide a bit more color on some of your more near-term opportunities on the industrial side, either within WGL or SEMCO, and maybe as well perhaps how you're thinking about positioning Blythe to take advantage of this momentum around gas-fired capacity.

Yeah, hey Patrick, this is Blue. I'll answer the questions around the utilities here. So as you are well aware, that demand profile continues to grow in our Washington gas service territories in that particular region. The outlook over the next several years is somewhere in the neighborhood of 5 to 10 BCF a day of potential throughput to manage some of that growth. As you're well aware, the data centers are coming there because of access But what they're finding is they're having trouble accessing green power, but they're also finding they're having trouble just accessing power in a timeframe that makes sense on their expansion profiles. So they have reached out to us. We've had several conversations about potential short builds to provide on-site generation, to provide gas for on-site generation for them. We have a handful of feed studies underway. We do expect that that is an opportunity for us. It's early. And we're trying to balance the opportunity set with the timing to ensure that we can also get infrastructure them in a time that matters. But it's a significant opportunity for us. The throughput is pretty significant. Michigan is a little bit behind based on our service territories, at least on the demand curve we're seeing. But we do have a couple of projects there underway for shorter term quick builds to connect gas supply with some incremental power development. So opportunities in both areas, primarily the opportunity sits in the Washington, D.C. region. James, you want to touch? Yeah, thanks.

So in terms of Blythe, Patrick, obviously with the renewal that happened Jan 1, 2024 for Blythe, we've got a four year contract in place. 50% of the EBITDA associated with that contract is totaled. The other 50% is obviously open to merchant pricing. And obviously, the summer months is where we see the strongest demand for power in California. It's just given the cooling season that we enter into. And if you look at where that demand has been over the last few years, the call on life has been significant. The dispatch rate has been almost twice what it's been historically. So to the extent that you add additional demand from data centers and AI, we would expect some very, very strong pricing and Blythe would benefit from that pricing on the merchant side of the EBITDA.

Okay, that's great. I appreciate the color there. Then maybe just back on Reef, would you have an update on where things are at here with the Trigon litigation process surrounding your LPG exclusivity and I'm curious, is this something that maybe not all, but perhaps certain customers are waiting for more clarity on before they sign on the dotted line?

Well, I'll take that one, Patrick. Really, the dispute between Trigon is with the port authority and Trigon. The port authority has the right to determine what players have exclusivity to do what. Trigon's facilities are effectively permitted to do dry bulk. We with Ripit and Reef have the exclusive rights to do bulk liquids. So Trigon's obviously working that through in the courts with the PRPA. PRPA believes that there is very strong legal precedent for their position. In fact, there's a case in Vancouver that reiterates that. So we're just pushing ahead with our project. We see very strong demand on the customer side from all kinds of customers, producers in Northeast BC, NGL aggregators in Alberta, and then off-takers in Asia. where we, in fact, have active discussions underway right now for more than 100% of the capacity of the first phase of REAP. So we're excited about our prospects, and that's why we're pushing forward on the final engineering and hope to have our capital costs locked down here shortly.

Okay, that's great, Vern. I'll turn it back. Thanks.

Thank you. Next question will be from Robert Kwan at RBC Capital Markets. Please go ahead.

Great. Good morning. If I can just ask around whether it's really for just contracting in general. So since you don't see commercials as a gating item, I guess first, how much should we expect to be locked down under tolls once you get to FID? And then... what type of duration do you have under the current tolling portfolio? And if you can also give us what the average duration of what you've got already locked up under REIF.

So, Robert, we're obviously in sensitive commercial negotiations right now with a whole host of counterparties. What I can tell you is... The term of the tolling agreements we're negotiating right now for the start of the 2027 NGL year are quite long. They would be consistent with what anyone would call a long-term take-or-pay contract. We've obviously been quite successful in 2024 with firming up the amount of tolling we have. The range of term on that is variable, or we do have a little bit of shorter-dated stuff and some longer-term tolling. Again, we don't want to give away too many commercial sensitivities right now as we're working through with a number of counterparties what we're trying to do for 2027. But suffice it to say, when we do shorter-dated deals, we charge higher rates, and our customers are seeing the value proposition uplift in looking at longer terms. So I think it all bodes well for locking this all up, but... It's a bit too early to say right now exactly when that's all going to happen. Got it.

And so I understand you don't want to say what you've got right now for Reef, but I'm just wondering, once you get to the FID, is there a minimum level of how much you do want to have completely in hand before you kind of progress to that 60% target?

Well, Robert, I think we've said very clearly is By 2027, when we start up the project, we want to have 100,000 barrels a day across a portfolio under tolling contracts. And we strongly believe by doing that, we're materially reducing the risk profile of the company as a whole. We really want to get to that 90% number we talked about, where 90% of our consolidated EBITDA is under cost of service or take or pay. So believe us when we say we're highly focused on achieving that.

That's great. Just in your 2024 priorities, you're not showing the equity self-funding is being done, notwithstanding you've done that for something like five years. So just what could unfold or what are the variables that could derail your ability to achieve that?

Sorry, I'm kind of... Robert, you're just referring to the green bars on those charts?

Yeah. Like you guys, you know, integrated pipestone is completely done. So equity self-funding is largely done, but there's kind of this gap there. I'm just wondering, you know, why it's not fully done or what could... Oh, why it's not 100%.

Yeah. I think that was just a miss on our part in how we... communicated that bar. I think we're 100% committed to equity self-financing.

And I mean, I did speak, sorry, Robert, I did speak to that in my prepared comments that that was a continued priority for 2024 and beyond. And Just to provide a little bit more comfort along those lines, when we get to the REIF FID in the second quarter of this year, we do expect that any capital associated with that for the balance of the year to be modest. And as a reminder, we only fund 50% of that. Our JV partner, Volpac, will fund the other 50. So we feel that we can accommodate it within our investment capacity that Vern alluded to earlier and we've alluded to at our investor day within 24 and beyond that. in 2025 and beyond, we've got a very healthy investment capacity that we can accommodate additional reef spend and other incremental growth projects and ensure that we're always directing capital to the best risk-adjusted return. So it does continue to be a priority. Perfect. Great. Thank you very much.

Thank you. And our last question will be from Ben Pham at BMO Capital Markets. Please go ahead, Ben.

Hi. Thanks. Good morning. I know you're highly focused on reef phase one, but can you talk about maybe, just because you laid up some maps here, or a pictorial of phase two A and B, how do you think with the sequencing of phases beyond phase one, and what do you think the key gating items are for those two future phasers?

I'll start, and Randy can fill in. Ben, I think we're very excited about the prospects that Reef brings us. The initial phase is 55,000 barrels a day of LPG for propane and butane exports. Once that's up, we'll have a total of about 170,000 barrels a day of total exports that we can provide out of the western part of North America here. Don't forget that today available to export just out of Canada is about 350,000 barrels a day of propane and butane. That supply is going to increase by the time reef is up and running. And the value of going to Asia is much superior than trying to push those barrels into the US. So once the first phase of reef is up and Once we're up in construction, I'm sure we'll be having incremental conversations with producers for more LPG export because the value proposition is very significant. And then later on, there is the ability for us to export other bulk liquids, whether it's diesel, biodiesel, even ammonia. Those are more later stage development opportunities. Is there anything you wanted to add, Randy?

No, I think Vern covered it, but, you know, the future phases are more capital efficient. And so, you know, our idea is that we'll add LPG or expansions as the fundamentals show that there's an oversupply of LPG in North America. And we feel that the Asian market will demand it. And we also are looking at methanol and other clean petroleum products to export as well, including ammonia in the future.

Would you have to rework the rail agreement to facilitate more volumes beyond phase one?

No. You know, we work quite closely with CN, and they're confident in the corridor can handle the future volumes. And also, Reef has an extensive rail program. and we have a number of different rail slots that we can add products to reef as we expand, so there won't be limitations there.

Okay, thanks. And maybe switching to the question, the Virginia Data Center opportunity, I just wanted to confirm there, so the thought process is to potentially build gas plants on site, And then is there then a benefit from the utility then to build access to gas and you'd roll into the ARP?

So Ben, maybe just to make sure we understand your question properly. So you're talking about at the utility, is there an opportunity for us to provide natural gas for onsite power generation in support of data centers and other industrial opportunities within our franchise?

Yeah, to check on that, but also just to clarify or confirm the earlier comment, the thought process, at least right now, is contracted as planned from the site.

Yeah, we would be doing this obviously all as rate-based, but go ahead, Lou.

Yeah, yeah, we would. So just to be clear, we wouldn't be doing any of, we wouldn't be building any of the generation. What we're doing are building infrastructure to the sites to provide gas supply. The conversations to date have been about, you know, can you get me X by Y date? Can you then help me green that as we move that natural gas to RNG data? and ultimately perhaps to other gaseous fuels in the future. So, yes, the conversation, we would be extending our franchise assets, building interconnects and pipeline to these sites where they would then build or procure, depending on the size of the site, some sort of on-site generation for power.

Okay, I got it. So it's more the utility side of things than the actual gas power plant.

Correct.

Okay, that makes sense.

That's right.

Okay. I got it. Thank you.

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

Just a couple of quick follow-ups here on the utility side. For the data center opportunity, is there any potential for optimization income? And secondly, to the extent that this is all rate-based oriented, are you doing anything to protect yourselves against potential for stranded assets and the risk of overbuilt?

Yeah, Robert, this is Blue.

So the short answer is yes to both of those. So we are absolutely looking at what is the right structure around these opportunities. Most of these structures we would do under some sort of new contract under our existing tariff where we would look to recover the investment profile within a window that made sense to both us and the data center developer. And yes, the opportunity to utilize those assets around our asset optimization program to then generate savings for our broader customer base would exist. But yes, we're being very, very thoughtful to ensure that the recovery of those assets line up in a contract that makes sense, that works for both our asset needs as well as the data center.

Okay, great. And last one for me. I just wondered if there's anything in the Maryland rate case and the amended order that influences how you might approach rate case strategy in that jurisdiction.

Yeah. You know, as I mentioned early in my comments, and you've probably read that, one of the things was just the way they bring rate base into new rates. And so they had a shift on precedent. The other thing we're exploring is is just ensuring that we are clear with the Commission's intent and guidance on how we communicate and bring forward. So we're looking at the cadence in which we file. We have looked across all of our jurisdictions to continue to do an analysis with a multi-year structure in any particular jurisdictions, and Maryland is one of those we have considered and analyzed. Would a multi-year program make more sense for us and for the Commission? to create clarity. So we continue to analyze that. So, you know, from a strategy perspective, we've been very open and transparent with the commission. They understand what we're doing and why we're doing it. And we're trying to ensure that we make that simpler for both them and us.

Yeah, I think, Robert, on this uplift you saw from the Maryland rate case that we booked in the quarter was really, we went back to the commission and said to them, you made some mathematical errors. in your initial order, the commission affirmed that they had made some mistakes and we were able to have those incremental rates added to what we've already booked.

Okay, great. Go on.

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

Thanks, Sylvie. And thank you, everyone, once again for joining our call today and for your interest in AltaGas. That concludes our call this morning. You may now disconnect your phone lines.