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Good morning, ladies and gentlemen. Thank you for standing by. Welcome to AltaGas First Quarter 2023 Financial Results Conference Call. My name is Laura, and I will be your operator for today's call. All lines have been placed on mute to prevent any background noise. [Operator Instructions]. After the speakers' remarks, there will be a question-and-answer session. As a reminder, this conference call is being broadcast live on the Internet and recorded.
I would now like to turn the conference call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.
Thank you, Laura, and thanks, everyone, for joining us this morning for AltaGas' first quarter 2023 financial results conference call.
Speaking on the call this morning will be Randy Crawford, President and Chief Executive Officer; and James Harbilas, Executive Vice President and Chief Financial Officer. We're also joined here this morning by Randy Toone, Executive Vice President and President of our Midstream Business; Blue Jenkins, Executive Vice President and President of our Utilities Business; and Jon Morrison, Senior Vice President, Investor Relations and Corporate Development.
We'll proceed on the basis that everyone has taken the opportunity to review the press release and our financial results. And similar to previous quarters, we have published an earnings summary presentation that you can find on our website. The presentation walks through the quarter and highlight some of the key year-over-year variances and non-recurring items that we assume will be helpful for the market to understand.
As always, today's prepared remarks will be followed by an analyst question-and-answer period. And I'll remind everyone that we will be available after the call for any follow-up or detailed modeling questions that you might have.
As for the structure of the call, we'll start with Randy Crawford, providing some comments on our financial performance and progress on our strategic priorities, followed by James Harbilas, providing a more detailed walk-through of our first quarter financial results, our near-term outlook and 2023 guidance, and then we'll leave plenty of time at the end for Q&A.
Before we begin, I'll also 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 our forward-looking information disclosure on Slide 2 of our investor presentation, which can be found on our website, and more fully within our public disclosure filings on the SEDAR filing system.
And with that, I'll now turn the call over to Randy.
Thank you, Adam, and good morning, everyone.
In the first quarter, the company delivered solid results with normalized EPS of $0.98 and normalized EBITDA of $582 million. These strong results and the continued execution of our strategic priorities have positioned the platform to achieve the company's 2023 guidance ranges, including normalized EPS of $1.85 to $2.05 and normalized EBITDA guidance of $1.5 billion to $1.6 billion.
Our operating results built upon the strong foundation of growth that we delivered in the past four years and is a testament to the quality and strategic value of our two businesses. Through ongoing investment and associated cost reductions, our regulated utilities were able to overcome the impact of warmer weather and the loss contribution from Alaska Utilities in March to deliver solid first quarter earnings results.
We continue to make investments in our network on behalf of our customers and execute our regulatory strategy to update our rates on a timely basis to reflect the current operating cost environment, including cost of capital. We are optimistic in achieving successful resolution in our Virginia rate proceedings over the summer and our DC rate proceedings during the fourth quarter, positioning the utility for continued profitable growth.
In our Midstream business, we continue to capitalize on the tremendous opportunity to export responsibly produce Canadian LPGs to Asia to meet the rising demand for lower carbon-intensive products. We delivered strong results, which included the export of almost 100,000 barrels a day of LPGs to Asia, delivered across 16 VLGCs. As we look forward, having completed our annual LPG supply contracts at pricing levels, reflecting the inflationary impacts on logistics, a lower risk profile from increased tolling levels and a significant hedged portfolio, we are well positioned to achieve our forecasted profitability.
Our newly executed VLGC time charter agreement continues to extend AltaGas value train reach into Asia. We'll reduce maritime shipping costs by approximately 25% relative to current Baltic freight forward pricing and lower pricing volatility on a long-term basis. The incremental time charter builds on the derisking of the two dual fuel VLGCs that AltaGas will be taking delivery of in late 2023 and early '24.
Proactive steps that we have taken during the first quarter have solidified our export platform. We are now positioned to take our export business to the next level. And therefore, we are excited to reach an agreement with Vopak for the potential expansion of our energy export business off Ridley Island, subject to positive FID. Projects has been granted to key federal and provincial permits and is designed to create increased LPG export capacity in measured phases, provide logistics cost synergies to our current export business, product optionality and dedicated access to a newly constructed dock.
In approximately four years since RIPET was first commissioned, we have steadily grown our global LPG export capabilities, which combined with Ferndale, AltaGas now connects more than 12% of Japan's annual propane and 12% of South Korea's annual LPG inputs. The newly Ridley Island energy export facility, partnership and agreement with Vopak positions AltaGas to further expand this business and provide additional access for our valued upstream customers to key downstream markets in Asia.
And of course, in order to fully capitalize on the strategic growth opportunities that surround us, we are fully aware in this higher interest rate environment at the absolute requirement that we possess a solid and investment-grade balance sheet. With the funds available from the closing of the Alaska utility sale at the beginning of March, we were able to pay down debt and are well positioned to achieve our medium-term buyback net debt to normalized EBITDA target.
Now with our balance sheet concerns firmly behind us, we are positioned with the flexibility to opportunistically invest in both organic and inorganic projects surrounding our strategically positioned utilities and midstream assets, such as REEF expansion project upon favorable FID.
So, in closing, this is likely to be my last earnings call as CEO of AltaGas, and I want to take this opportunity to express my gratitude to the dedicated employees of AltaGas for their unwavering support, commitment and hard work during my tenure. Together, we have transformed ourselves from a highly-leveraged low-growth company into a premier integrated West Coast LPG export company and a stand-alone highly efficient utility business.
During this journey, we increased EBITDA by over 50%, doubled earnings per share and EBITDA at both the Utility and Midstream businesses from 2018 to 2022. Even more impressive, in my opinion, is that we were able to achieve these results despite the sale of $7.9 billion of EBITDA producing assets, the reduction of leverage from 11x to 5x, with no equity issuances. This was a monumental transformation and a testament to the enormous intrinsic value of our asset base and the dedication and hard work of our talented employees.
Given the magnitude of our transformation and the enviable strategic positioning of the company, we are well positioned to continue to achieve our 5% to 7% continued annual growth rate through 2026. I'm proud of what we've accomplished together. I'm confident this management team will continue to drive value for our shareholders, and I'm pleased to transition to the next CEO, a company with a solid foundation and bright future.
And with that, I will turn the call over to James to review the financial results in more detail.
Thank you, Randy, and good morning, everyone.
As Randy mentioned, we are very pleased with the operational and financial results that we delivered in the first quarter of 2023 and with the strong progress that we made on our strategic priorities. We achieved normalized EPS of $0.98 per share, normalized EBITDA of $582 million and normalized FFO per share of $1.63 for the first quarter of 2023. These results were slightly above our expectations and leave us well positioned to achieve our 2023 guidance.
Diving into our operating segments. The Utility segment reported normalized EBITDA of $401 million in the first quarter of 2023 as compared to $408 million in the first quarter of 2022. Our utilities continue to deliver stable and predictable results that are in line with expectations. The quarter included AltaGas making strong ongoing asset investments on behalf of our customers across the network, favorable foreign exchange rates, offset by warmer weather impacts in Michigan and the District of Columbia and weaker year-over-year performance at the retail gas business, which was principally driven by warmer weather, higher cost gas inventory and the timing of swaps.
In the first quarter, we deployed $151 million of invested capital in the utilities, including $66 million through our accelerated pipeline replacement programs. These investments continue to be directed towards improving the safety and reliability of our system while bringing long-term operating cost benefits. We continue making these upgrades on behalf of our customers while balancing ongoing customer affordability. This is increasingly important during the current economic environment of higher interest rates and inflation across the broader economy. We remain acutely focused on cost management across the utilities platform and driving the best outcomes for all of our customers and stakeholders.
Washington Gas realized normalized EBITDA of $349 million in the quarter, an increase of 17% over 2022. The strong year-over-year growth was driven by interim rates at Virginia, ongoing capital investments to upgrade our system and lower O&M. This was partially offset by warmer weather in DC and lower asset optimization activities.
SEMCO and ENSTAR combined normalized EBITDA was $81 million in the first quarter, which is down year-over-year due to the Alaska sale at the beginning of March and significantly warmer weather in Michigan and slightly higher O&M costs.
Finally, Utility results benefited from the strengthening of the U.S. dollar in the quarter, which was in line with our previous and current guidance.
Normalized Midstream EBITDA came in at $183 million compared to $174 million in the first quarter of 2022. The quarter included strong operations and year-over-year volume growth across global exports, higher fractionation volumes and realized pricing and the resolution of commercial disputes. These were partially offset by higher logistics costs, modestly lower gas processing volumes, resulting from the sale of Aitken Creek Gas processing facility in the second quarter of 2022, and lower realized Asian to North American butane spreads in the global exports business.
In the first quarter of 2023, we exported approximately 99,444 barrels of propane and butane to Asia spread across 16 VLGCs. This included approximately 58,000 barrels of propane exported from RIPET and 41,500 barrels of combined propane and butane from Ferndale.
During the quarter, we were able to secure additional agreements with an investment-grade counterparty for approximately 6,500 barrels per day of tolling, which contributed to us achieving our target of 40% of 2023 volumes being tolled. For the remaining merchant volumes, we continue to be disciplined with our hedging practices within global exports and are focused on locking in structural pricing differences in subsequent quarters. Inclusive of toll barrels, we were approximately 68% hedged for our expected global export volumes for the remainder of 2023 at an average FEI to North American price of approximately $12 per barrel.
Finally, as a reminder, we expect to take delivery of one new VLGC time charter at the end of 2023 and one new time charter in early 2024. We will add a third time charter for a new 86,700 cubic meter dual-fuel VLGC with expected delivery in the first half of 2026. Each of these time charters are expected to reduce our ocean freight costs by approximately 25% relative to current Baltic freight pricing and lock-in pricing on a long-term basis.
In the corporate and other segment, we reported normalized EBITDA loss of $2 million compared to a loss of $8 million in the first quarter of 2022. The $6 million year-over-year improvement was mainly driven by lower operating expenses.
Turning to our balance sheet and capital recycling. During the quarter, we closed the divestiture of Alaskan Utilities, which allowed us to reduce debt by approximately CAD1.1 billion. This significantly strengthens our balance sheet and provides financial flexibility to advance our strong portfolio of growth opportunities across the Midstream and Utilities platforms over the coming years.
In terms of other developments, last night, we also announced the execution of the definitive agreement for a new 50-50 joint venture with Vopak to further evaluate development of the Ridley Island Energy Export Facility, or REEF, as we refer to it. REEF will have the capability to facilitate the export of LPGs, methanol and other bulk liquids that are vital for everyday life. The project has been granted to key federal and provincial permits to construct storage tanks, a new dedicated jetty and rail and other ancillary infrastructure required to operate a state-of-the-art and highly-efficient facility.
REEF would be developed on a 190 acre site on lands administered by the Prince Rupert Port Authority, which the joint venture has executed a long-term lease that sits adjacent to AltaGas and Vopak's existing RIPET facility. The project is aligned with our corporate strategy of investing in and operating long-life infrastructure assets that connect customers and markets and have the ability to provide durable and compounding value for our stakeholders.
Development of REEF would further bolster AltaGas' first-mover advantage and differentiated LPG value proposition and provide increased operational synergies that allow us to more efficiently connect our North American customers to premium global downstream markets.
Similar to RIPET and Ferndale, REEF will benefit from a significant geographic shipping advantage with 10-day shipping times in Northeastern Asia, which represents a 60% basetime savings over the U.S. Gulf Coast and a 45% time savings from the Arabian Gulf.
I want to take the opportunity to thank our valued partners of Vopak, who we have worked closely with to get to this stage and look forward to expanding our relationship. We also want to thank the Prince Rupert Port Authority for their ongoing support and vision to build a world-class global port, all First Nations right holders and the local communities surrounding Prince Rupert, who have embraced and partnered with us on this journey as well. We look forward to continuing to connect our upstream and downstream customers and for Canada to continue to play a larger role in global energy security.
Looking ahead, we continue to focus on delivering durable and growing EPS and FFO per share, while lowering leverage ratios and increasing margins of safety within the business by moving towards our medium-term goal of reaching 5x net debt to normalized EBITDA. We are maintaining our 2023 guidance ranges, including normalized EPS of $1.85 to $2.05 per share and normalized EBITDA guidance of $1.5 billion to $1.6 billion.
We also continue to target delivering regular sustainable and annual dividend increases that compound in the years ahead with an anticipated 5% to 7% compounded annual growth rate through 2026.
And with that, I will turn it over to the operator for the Q&A session.
Thank you. Ladies and gentlemen, we will now conduct the analyst question-and-answer session. [Operator Instructions] Your first question comes from the line of Linda Ezergailis from TD Securities. Please go ahead. Your line is now live.
I'm wondering if you can provide some more context on the bookends of scale beyond acreage for your REEF initiative, whether it be in terms of capacity or capital expenditures, just to give us a sense of scale?
And also, what would be the runway of completion ultimately to the final phase in terms of calendarizing how quickly or how slowly measured this initiative would be?
Hi, Linda, it's Randy Toone. As far as scale those, and we're still doing the design work on REEF, but it would be similar to the kind of the first phase of RIPET. So I would use that as a metric for scale. [Multiple Speakers] Sorry, go ahead.
No, go ahead.
I think part of your question was also in terms of financing and expected capital costs. I think it's still too early in the process to talk about capital costs. That's what the team is working through in terms of detailed design and the FEED study, and we would be talking about our expected capital costs once we make a final investment decision. But we've always said that we feel that we can build these projects at a CapEx EBITDA multiple of roughly 6 times to 8 times.
And with respect to financing, we feel that we put the balance sheet in strong enough shape and derisk the project given the 50-50 joint venture with Vopak where we can finance our capital through additional borrowings on the facility and maintain our credit ratio. So, we feel comfortable in terms of our ability and the financial capacity that we have to be able to move this project forward when we make the final investment decision.
Thank you. And just a sense of a timeline beyond FID as to when this might actually become operational, recognizing that there might be some parts of the timeline that are outside of your control?
Hi, Linda, it's Randy again. Yes, for timing, we feel that REEF would be built in a three-year window, and that all depends on the in-water work. So this project has a jetty and that will be a critical item for timing. So, I would use three years.
Great. Thank you. I'll jump back in the queue.
Thank you. Your next question comes from the line of Robert Catellier from CIBC Capital Markets. Please go ahead. Your line is now live.
Hey, good morning, everyone. I just wanted to follow up on REEF here, specifically just on the contract. I want to make sure I understand the wording here you have in the press release. When you say AltaGas has executed a long-term commercial agreement with the JV, is AltaGas going to be the customer at the facility, or is there a third party that's coming and taking the capacity?
Hey, Rob, it's Randy Toone. Yes, well, just similar to what we've done at RIPET, we have all the capacity for RIPET and also for the first phase of REEF. However, we have numerous customers that we aggregate on rail and numerous off-takers. So, we might be taking all the capacity for -- through the joint venture, but we have a number of customers with supply and offtake.
Yes, that's what I expected. And then, just as you look to build out this project, can you just give the update on the contracting of the existing RIPET facility? And I guess what I would want to ultimately know is what your vision is for how much capacity to have there? How much spread exposure you'd have in the business pro forma, this new asset coming in into service if it does reach FID?
This is Randy Crawford. I think as we look at that project and Randy can give you the specifics, the reason in strengthening fundamentals in prices, we've seen, as you mentioned, increasing interest in tolling and such, and they reached the 40% target. As we look forward on the project, to meet the FID, we're going to be focused on getting firm multiyear commitments that will earn our minimum cost of capital before we go forward, and we'll scope out what those are. But this will be a long term.
Our construct is to be more of a -- while there will be some merchant overall, we'll continue to provide our customers access to the market. And I fully expect that you'll see a demand pull customers that in long-term tolling as well as producer push. So, we're quite optimistic. But from a risk standpoint, we'll be focused on firming commitments for multiple years before we go forward.
Okay. Last question for me on the subject is, what are the implications for developing the land near Ferndale? And related to that, is the Inflation Reduction Act gets further detailed, are there any positive implications for developing the site near Ferndale? Thank you.
Hi, Robert, it's Randy Toone. Yes, the -- we feel that Ferndale is an existing infrastructure on the West Coast is very valuable, and we did acquire a significant land around the terminal. And we are looking at new -- fuels of the future to be utilized around that land on that terminal. And definitely, the Inflationary Reduction Act does provide some benefits, which we are currently exploring.
Okay, thank you.
Thank you. Your next question comes from the line of Robert Kwan from RBC Capital Markets. Please go ahead. Your line is now live.
Good morning. If I can just come back to the contracting discussion, and if we just first think about your existing business and 40% of it is tolled. Is that where you would want that business to be long term? And if not, what percentage do you think is optimal? And then is it fair to assume when you think about adding REEF that you would want at least 40% of it tolled or frankly, probably whenever this pro forma number, which would be your goal for the existing business?
Hey, Robert, it's James here. It's a good question. I mean we've obviously talked about the fact that we've been actively trying to derisk our export platform over the years, and we've seen progress this year relative to last year, obviously, being at 40%. We've always thrown a range out there of 40% to 60% of the volumes coming from those facilities to be told on an aggregate basis, and that's what we would be targeting as we look at REEF and an expansion there. So that's the positive progress and momentum we've made. And Randy Crawford touched on the fact that we're starting to see a demand pull for these type of agreements as well and hope to build on the contract that we announced this quarter from Asia.
Got it. So, just to be clear, you're at kind of that minimum level then on the existing facilities. So for this to get a positive FID, you'd need to find 40% of REEF's capacity under a long-term toll kind of -- and develop that or get those signed, call it, over the next year or so?
Well, we would factor that into the FID, the percentage of offtake that we can contract would be factored into the FID. When I throw the 40% to 60% target out there, it is on an aggregate basis, so we would be looking at it through that lens.
Okay. And then just coming back to the funding on that. You've talked about your current plan being self-funded. You've got the 5 times medium-term target, and you've been talking about moving leverage kind of progressively lower. Does all of that hold or continue to hold if you go forward with REEF, or would we see leverage tick higher kind of during the construction?
Yes. I mean, look, we've talked about operating a diversified platform that has both Utilities and Midstream. And we've also talked openly in the past about the fact that the CapEx profile of the Utilities tends to be much more linear and we get a little more lumpiness in the buildout of the Midstream platform. So, we would be looking to wind -- to ratchet up or down our capital between those two platforms on a risk-adjusted basis from a return standpoint, and we would look at leverage through that lens as well.
So, if we have a big build-out on the Midstream platform, we can always allocate more capital there and be a little more conservative in terms of our Utility spend and try to manage our leverage that way. And we've also, obviously, got the non-core assets that we continue to advance, although some of those are in different stages of evaluation as well with MVP and Blythe and other assets. So we would look at those opportunities from a capital recycling standpoint as well to manage our leverage ratios.
Got it. But I can just finish with a bit of a housekeeping item, just understand some of the onetime items that were included in normalized EBITDA. So, I think the Goleta gain has been excluded, but the defeasance gain for SEMCO is included. And then the last is there's a reference to Midstream favorable settlement of contingencies and it looks like that has been included. And I'm just wondering how much that amount was in the quarter.
Yes. So, let me deal with those individually because you touched on three different items. You're correct that the Goleta gain on sale, which was a gain on the sale of an asset, we'll always normalize those, and we normalized it again this quarter. The defeasance was basically us retiring roughly $153 million of debt related to ENSTAR and CINGSA, and we were able to do that through buying treasuries that we're able to satisfy the principal and any remaining interest payments over the remaining term of that debt. We didn't normalize that gain because we basically legally defeased a debt with those cash savings, we accelerated the recognition of those cash savings that are going to accrue over the remaining term of the debt. So that's why we didn't normalize that amount. That's not something that we -- that is in our normalization policy.
On the commercial disputes that you referenced, I mean, this was something that we flagged in Q3 of 2022. It was related to the Petrogas transaction. These were contingent liabilities and commercial disputes that we set up in the purchase price allocation. And during Q3 of 2022, we flagged that, that could positively contribute to future quarters, and that's how it's played out in Q3, a little bit in Q4 and then obviously into Q1 of 2023. And we don't expect any significant contributions from here on out from these items, but we don't want to disclose it because there is some commercial sensitivity around these discussions.
Okay. Understood. That's it for me. And Randy, all the best in retirement.
Thank you so much, Rob. Appreciate it. Thank you.
Your next question comes from the line of Dariusz Lozny from Bank of America. Please go ahead. Your line is now live.
Hi, good morning, and thank you for taking my questions. Maybe just starting out on the latest announcement on adding a third VLGC. Can you maybe just kind of help frame once all three of those vessels are operating, how much -- on a quarterly basis, how much of your actual volumes do you think those would be able to absorb? And correspondingly, what is the additional opportunity to add more vessels and reduce your shipping costs?
And related to that, obviously, the VLGC effort is a very tangible way that you guys have demonstrated making that part of the business more efficient. So I was wondering if you could comment on any other opportunities that you see to further vertically integrate and build in efficiencies into that export business?
Well, it's Randy Toone. So those time charters, you could -- they're in constant our operation is in -- they're servicing both Ferndale and RIPET and you can use a roughly like a 20,000 barrel a day is what their capacity is. And so with three of them, that will be roughly 60,000 barrels a day of our total portfolio. And so those are definitely locking in freight. And as you saw through '22, freight can be very expensive, and we see that as a benefit and taking some volatility out of the export business.
Okay. Great. Appreciate that color. And sorry, if you could just touch on the other part of my question or maybe anybody on the team. Other opportunities to either further vertically integrate or otherwise add efficiencies into the export business?
So Randy, you can comment on this. It's Randy Crawford. But clearly, the team has done a remarkable job about building scale overall. And in terms of all of the integrated activities, maybe the team are focused on unit trains, right, to continue to improve our logistics, which also increases capacity and our cost. And so there's a lot of effort there in that and certainly looking at any other opportunities to be able to control additional shipping or VLGCs is a possibility.
But I did want to remark that one of the other aspects of the VLGC is our ability to reach into the market. And owning that control, to able to reach back with a solid logistics strategy and operation to reach these valuable markets, I think it's really, in the long run, going to increase our -- not only our efficiency and cost, but extend our reach into growing markets.
I can also add that the other things that we're looking at is technology. And so investing in OT, or operational technology, to have real-time data from both our export facilities, rail for our supply sources and even from the VLGCs. This keeps us on top of our business better. So we have less demerged cost, storage costs and those types of things. And so that's another way we're trying to reduce costs.
Randy did great job, best in most valued market for the product and the opportunity to continue to drive efficiencies and costs and to bring those benefits to our customers, I think, is something I'm really looking forward as we continue that progress.
Okay. Great. Thank you. I appreciate that color. If I could move over to the utility side of the business now. I just wanted to ask about the specifically WGL, Washington, D.C. Can you comment on what the earned ROE has been -- or at least ballpark what the earned ROE has been at that business maybe on -- just in Q1 or on a trailing on basis?
And then, obviously, there's the rate case and the ARP application that are both in process right now. Specific to the ARP application, I think last time around, you guys asked for five years, you've got three years. So maybe any comments on how, if at all, you're approaching this application differently? And if you were to get three years as opposed to five, how that might affect the medium-term capital plan at that utility specifically? Thank you.
Hey, Darius, it's James Harbilas. I'll tackle part of your question here with respect to ROE, and I'll kick it over to Blue to talk about ARP filing, the pipes 3 filing and that part of your question. So, in terms of ROE, we've never broken it down by jurisdiction within WGL. We've obviously said that we continue to make strides in terms of closing that ROE gap. And right now, we -- and we've also said that D.C. is the jurisdiction where that gap is probably the biggest. That's why we've been active in the rate hearing room trying to have our current rates reflect the sizable capital investments that we've made in that jurisdiction to improve safety and reliability on the system. So that's the rate case that we're working through right now.
Upon resolution of that rate case, we hope to get -- to close that gap within D.C., which is the one jurisdiction where we said we've got a lot of wood to chop. So once we get resolution of that rate case, we'll take a step back and see if there's additional rate cases that are required to be able to continue the journey to close that gap and have our rates reflect the considerable capital investment that we've made within D.C. to service our customers and provide safe and reliable service.
So with that, I'll turn it over to Blue to comment on ARP.
Yeah, thanks, James. In reference to your ARP question, yes, we did file our request late last year. You can see those details, it's the public document. And as you pointed out correctly, we filed five years last time, and got three. Each one of these cases are unique, right? There's a conversation on what's occurring in the market and balance of what we're trying to achieve on modernizing the system for the future as well as accelerating the safety component and modernizing that system at the same time.
So, we still got several months in that particular case. So, I think we're too far out to give an educated guess on how many years and what the dollars might be. But you can see the range of the ask. And when you -- if you kind of straight-line that out against last time, you'll perhaps that puts a reasonable expectation in there.
And the only thing I'll add to Blue's question is if you look at these programs and what they're directed towards cast iron and bare steel pipe, there's still a lot of that that pipe within our jurisdiction, especially within D.C. So there's obviously a need for these capital programs. But obviously, once we get clarity around term and dollars, we'll update the markets at that time.
Okay. Great. Thank you very much. I'll leave it there.
Thank you. Your next question comes from the line of Ben Pham from BMO. Please go ahead. Your line is now live.
Okay. Thanks. Good morning. Maybe just start off on REEF. As you think about deploying capital through the various phases, Phase I, II and maybe beyond, is it going to be more of a piecemeal basis? Or is it going to be like RIPET? Will you size it up and going from Phase 1 and 2, there wasn't much CapEx on top of it?
Hi, Ben, it's Randy Toone. Given that the first phase is LPG, and we think the future phases are potentially other bulk liquids, we'd have to build additional tankage. And so, we do see the future expansions or future phases being more costly, say, than what happened at RIPET because we did prebuild more around this extra compression and pumping capacity. So yes, the future phases will have more capital.
Each one -- sorry, Ben, it's James here. I was just going to add that each one of those phases is obviously going to be evaluated on a stand-alone basis and will be subject to individual FID. So, we will have to get comfortable on construction costs of those additional phases for those additional products and obviously, commercial terms before we move forward with any additional CapEx.
Okay. And I know there's a question around CapEx and you refine it as you get through feed. I mean you look at some of the public filings on the project through Vopak, I mean, we can at least get a sense of what the CapEx is. And so my question, is that CapEx number -- how outdated is that CapEx number? And then is that just for the LPG Phase 1 portion, or is that envisioned the entire project?
Hey, Ben, it's Randy. The numbers you probably see in the public filings were -- is for the full build-out with LPG and future bulk liquids. But -- and so we're building this in phases. But that number is also before any kind of inflationary pressures of comp came in to -- so that's why AltaGas is taking over the project from Vopak. We are looking at design and we're looking at what those capital costs are in today's dollars. And so that's why we're not prepared to give you a number yet. But by over the next, say, six to nine months, we're hoping to fine-tune that number.
Okay. So the directional above that, but we got to also break up the phases from that. Okay. And maybe last one on interest expense. When we look at that year-over-year, you had the hybrid impact in there. On the remaining increase, is there a good rule of thumb of how much of that is passed through the regulatory side?
Well, I mean, we can get back to you with that split. I don't have that at my fingertips. But what I want to caution people about is that the interest rate for Q1 and the year-over-year increase shouldn't be seen as a run rate interest expense. You already touched on one of the components, the fact that we've got hybrid interest in that number, which the offset is sitting below the line in pref dividends, because we use those hybrid notes to basically refinance prefs that we didn't want to reset and they continue to be EPS accretive.
But if you look at the other factors that led to the higher year-over-year interest rate, we were carrying roughly -- we've got $1.5 billion of debt that's come down from year-end to the end of Q1 with the repayment of that debt with the ENSTAR proceeds and the unwinding of working capital. So there's -- on a quarterly basis, that probably accounts for a $20 million to $22 million lower interest rate number as you look out towards the remaining quarters of this year, just given the lower debt balance that we're covering -- carrying. And we don't expect working capital to build as dramatically as it did into the back half of 2022 because we've seen gas prices come down. So, as we get into reinjection season with respect to our utilities and the gas that we've got to put back into storage, we're doing it at prices that are probably 50% below where they were last year.
Okay. Got it. And Randy C., all the best as well.
Thank you, Ben. Appreciate it.
Thank you. Your next question comes from the line of Matthew Weekes from iA Capital Markets. Please go ahead. Your line is now live.
Good morning. Thanks for taking my questions. The first one for me, just on 2023 and looking at the guidance, obviously, Q1 was quite a strong quarter, kind of multiple tailwinds, some of them a little bit kind of one-time, but maintain the guidance for the full year. I'm just wondering what -- if you can comment on the kind of puts and takes you're seeing for the remainder of the year going forward? And directionally, is the guidance kind of more on track to be towards the higher end at this point would be your expectation? Or just any comments around that? Thanks.
Hi, Matthew, it's James Harbilas here. So obviously, you're right, we have had a pretty strong start to the year with Q1 results, but it is Q1, there's still three quarters to go. But when we look at some of the headwinds that we've obviously been experiencing warmer weather than anticipated in both D.C. and Michigan had an impact to the quarter. We also believe that new rates that we were looking to be in effect a little earlier in D.C. are now being pushed into late 2023, maybe early 2024, so we consider that a headwind. And then asset optimization revenue because of the milder weather and lower gas prices is tracking lower than where our expectations were and obviously lower than where last year was just given some of the volatility that was experienced.
In terms of tailwinds, though, we do see obviously stronger FX relative to what we had embedded in our guidance. And we are seeing some strength to butane spreads, and we expect that to continue out into the balance of the year that we feel is tracking a little bit above where we were from a guidance standpoint. So that's why we feel comfortable reiterating the $1.5 billion to $1.6 billion, but we don't want to guide to where we're going to end up in that range, just given the fact that we still have a lot of the year to go here with three quarters in front of us.
Okay. Thank you. I appreciate it. And just on the REEF [indiscernible] expansion, you mentioned that sort of not just increasing scale but also some sort of potential synergies exporting LPGs off the island. I'm wondering if you can just sort of talk about some of those synergies and what you might be able to kind of extract as you look at that project? Thanks.
Hi. It's Randy Toone. Most of the synergies are going to be around rail. There's -- with the new project we do have access to a bigger rail terminal. And so we see more synergies with RIPET on the rail side.
Okay. Thanks. I appreciate it. And just one more for me, sort of beyond the big expansion you look about through efficiencies and capacity with the existing RIPET and Ferndale facilities, would you say you still see similar kind of potential to optimize those volumes that you kind of highlighted back a couple of years ago at the 2021 Investor Day? There were kind of some growth targets involved in the existing export capacity. Thanks.
Hello, it's Randy again. Yeah, so RIPET was built to do 80,000 barrels a day, and it all comes down to logistics efficiency. And so with the synergy with, say, REEF with that extra rail efficiency, we do think that we can potentially get closer to that target -- that design capacity. Currently, the most we've really gotten out of RIPET is the high 60 -- between 65,000 and 70,000 barrels a day. So we do think we can get up to closer to 75,000 barrels a day. And in Ferndale, we do feel that, again, it's all logistics efficiency. So we have a number of projects that we're trying to do there that will help on the efficiency of the facility, which will increase capacity. So, we still think that we can get closer to that number that we talked about at Investor Day.
Okay. Thanks. I appreciate the commentary, and Randy all the best in retirement. I'll leave it there. Thanks.
Thank you, Matthew.
Thank you. And your last question comes from the line of Patrick Kenny from National Bank Financial. Please go ahead, sir. Your line is now live.
Thank you. Good morning. Just back to the synergies, just wanted to clarify, as you lock down rail and other logistics agreements for REEF, are you looking to dovetail longer term, more favorable contracts for RIPET as well? Or is RIPET completely separate negotiation process with the rail and other shipping providers? Just I guess, just a general update on how those negotiations are progressing would be great.
Hi, Patrick. Yes, it will be the same for RIPET. So the -- our rail service providers will -- there's a synergy to have them service both RIPET and REEF. And so, we are working with them to come up with a long-term agreement that both the lowest cost for the service levels that we require. And so yes, they'll be connected.
Perfect. Okay. Great. And then, just on the LPG supply contracting process here in April, it sounds like that puts you on track to meet your 10% growth target in volumes for 2023. But I guess just from a longer-term supply perspective, now that you're seeing the uptick in the number of well licenses, curious how you're thinking about your strategy to secure future barrels, either beefing up your [indiscernible] capacity in the field, either organically or through acquisition versus, say, sticking with the strategy to lock in commercial supply agreements with the other NGL gatekeepers in Western Canada?
I think it's going to be a combination of both. We do -- we had a lot of supply coming out of our Northeast BC asset, and we see an expansion of that facility because our North Pine frac is full. And so, we see additional LPG and supply from there, and that's considered long-term LPG supply. And we are working with a number of customers in Fort Saskatchewan for long-term tolling arrangements. And we do think the fundamentals work. LPG is going to grow in Western Canada, and there is no market. And so we feel that the Asian market is the best market for those LPGs.
And also, as we talked, we have this -- just because RIPET has been such a reliable, secure source of LPG, we are seeing our Asian customers wanting to do tolling deals as well. So we've got -- we have one in place for this year, and we're looking at future -- a number of different longer-term deals for the future.
Okay. Great. And maybe last housekeeping question here for James. So now that you're [25%] (ph) to 90% hedged through the summer, just curious when we might expect to see your Q4 or Q1, say, your winter hedge program ramped up as well?
Hi, Patrick. Yeah. So, we've -- I mean, if you look at our hedging program right now, we do have some hedges layered into Q4. We -- that has started to ramp up here as subsequent to the quarter, and we are moving higher. So, we do like where the curve is with respect to some of the propane and butane pricing we're seeing, and you can expect to see that creep up as we work our way through Q2, and it will be at a much higher rate when we report Q2 in July.
Okay. Great. I'll leave it there. Thanks guys.
Thank you.
Thank you. This concludes the Q&A portion for today's call. I will now turn the call back to Mr. McKnight.
Thanks, Laura. And thank you once again, everyone, for joining our call today and for your interest in AltaGas. That concludes our call this morning, and I hope you all enjoy the rest of your day. You may now disconnect your phone lines.