Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Second Quarter 2023 Financial Results Conference Call. My name is Sergio, 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 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 over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.
Thanks, good morning, everyone. Thank you for joining us today for AltaGas's Second Quarter 2023 Financial Results conference call. Speaking on the call this morning will be Vern Yu, 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, Donald Jenkins, Executive Vice President and President of our Utilities business, and Jon Morrison, Senior Vice President, Corporate Development and Investor Relations. We'll proceed on the basis that everyone has taken the opportunity to review the press release and our second quarter results. Similar to previous quarters, we've published an earnings summary presentation that you can find on our website.
The presentation walks through the quarter and highlights some of the key year-over-year variances and non-recurring items that we thought would be helpful for the market to understand. As always, today's prepared remarks will be followed by an analyst question and answer period. 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 Vern Yu providing some comments on our financial performance and progress on our strategic priorities, followed by James Harbilas providing a more detailed walkthrough of our second quarter financial results, near-term outlook, and 2023 guidance, and then we'll provide lots of opportunity 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 of our investor presentation, which can be found on our website and more fully within our public disclosure filings on SEDAR. With that, I'll now turn the call over to Vern.
Thanks, Adam, and good morning, everyone. It's great to be here today to discuss our Q2 results and update you on our operations and other corporate developments. Before we do that, let's spend a few minutes on why I think AltaGas's future is very bright. I've already had the opportunity to take a deep dive into the business, visiting our offices and operations, and have connected with our employees, customers, partners, and shareholders. This has enhanced my already bullish view of AltaGas, and I'm excited to leverage the company's exceptional assets in the months and years ahead. I came to AltaGas because I saw an opportunity to create a highly sustainable and growing infrastructure platform with a robust investment proposition.
We are positioned to deliver industry-leading dividend growth through stable and growing cash flows. We will be able to improve our risk profile as we recontract commercial agreements in midstream, file timely rate cases, continue to optimize our capital spend while managing our cost in our utilities segment. In utilities, we're modernizing the network with our accelerated pipe replacement program and adding new customers across the DMV. In midstream, we continue to see growth in volumes for global exports and value chain optimization opportunities. I believe the long-term fundamentals for AltaGas's businesses are strong. Western Canada will deliver significant growth in both natural gas and NGL production as industry ramps up production to feed LNG Canada and other export facilities. These growing NGL volumes will need additional West Coast egress to maximize value for our customers.
The good news is Ripon and Ferndale can deliver this today, and our REEF project will provide even more egress when it's up and running in late 2026. The future of our utilities segment is also very bright. Natural gas remains the largest energy source for homes in the DMV, and the electrical substitution costs for this energy are more than 3x that of natural gas. As we continue our conversation on the energy transition, we need to be mindful and balance the critical needs of energy affordability and energy reliability with our regional and national climate goals. All of this cements the fact that natural gas is a key part of today's energy mix and will be part of that energy mix for decades to come. Q2 was impacted both financially and operationally by the devastating wildfires across Alberta and BC.
Our thoughts are with the people and the communities affected by these fires. I want to thank our dedicated employees who were involved in wildfire relief and helped with the recovery efforts across the communities where we operate. Their actions reflect the values of our company. Let's talk about the quarter. AltaGas continued to execute on its long-term strategy during Q2. The wildfire and the timing of some of our hedges had a negative impact financially in Q2. Despite these results, the first half of 2023 was in line with our expectations, today, going to reiterate our 2023 full year guidance, with normalized EPS in the range of $1.85-$2.05, and normalized EBITDA in the range of $1.5 billion-$1.6 billion.
The company continues to show steady progress in our long-term deleveraging plan, where we're now approaching our near-term target of being less than 5 times on a debt-to-EBITDA basis, and we have line of sight to get to 4.5. We're pleased with the progress shown on removing the milestones remaining to complete the Mountain Valley project, including the receipt of all remaining permits to finish construction and start operation of the pipeline. This was reinforced by the U.S. Supreme Court ruling yesterday to vacate the stays that were placed on the pipeline by the Fourth Circuit. The partners now have a clear path to the pipeline being completed by the end of the year.
In the second quarter, we've delivered normalized EBITDA of $239 million, and EPS of $0.06 per share, compared to $276 million of normalized EBITDA and $0.14 per share of EPS in the second quarter of 2022. Midstream results were inclusive of $7 million from negative wildfire impacts, and another $12 million due to hedge and ship timing impacts, which will reverse the next couple quarters. This should increase second half EBITDA by $12 million, normalized EPS by $0.03 per share, and normalized FFO by $0.04 per share in the second half of 2023. In the utilities segment, operating performance was relatively in line with expectations, but did include another $4 million of negative weather impacts stemming from hot, warmer-than-normal weather in Michigan and D.C. Midstream delivered strong volume performance in the quarter.
Total gas inlet volumes grew by 11%, fractionation volumes increased by 32%, and global exports were 4% higher, all on a year-over-year basis. Some of these volumes were impacted by the wildfires, where we saw a backup in global exports and outages at our North Pine fractionator. We're very excited about the long-term opportunity associated with growing our global exports business and providing Canada with more global connectivity for LPGs as we increase throughput at Ripon and Ferndale. REEF will add to that. It's a very exciting project for us. It will further bolster our leading LPG export business by adding even more U.S. for the basin. We continue to refine the engineering and construction plans for the projects. We're hoping to have a positive FID for the project, either at the end of this year or early next year.
With that, I'll turn the call over to James.
Thank you, Vern. Good morning, everyone. I'm pleased to provide a more detailed overview of the quarter. As Vern mentioned, we obviously had some headwinds and timing issues that impacted financial results during the second quarter. We did show operational strength across a number of areas, while we continue to remain positive on the long-term outlook for the platform. We achieved normalized EPS of CAD 0.06, normalized EBITDA of CAD 239 million, and normalized FFO per share of CAD 0.53. Results were slightly below our expectations and were inclusive of approximately CAD 7 million of wildfire impacts and approximately CAD 12 million of hedge and ship timing impacts. Despite the second quarter being modestly behind our expectations, we are pleased with where we sit on a year-to-date basis through the first two quarters. We are reiterating our 2023 guidance.
Together, the wildfire, hedge, and ship timing impacts reduced normalized EPS by an approximately $0.05 in the quarter, with the hedge and ship timing impacts representing approximately $0.03 of this impact, which we expect to reverse in the second half of 2023. Turning to the operating segments, the utility segment reported normalized EBITDA of $102 million in the second quarter of 2023, as compared to $116 million in the second quarter of 2022. The largest driver of the year-over-year variance was the divestiture of the Alaska Utilities, which closed in the first quarter of 2023. The Alaskan utilities had contributed $15 million in the second quarter of 2022. Washington Gas delivered normalized EBITDA of $69 million in the quarter, an increase of 6% on a year-over-year basis.
This growth was driven by the combination of interim rates at Virginia, ongoing capital asset modernization investments into ARP programs that are focused on upgrading our system, and favorable foreign exchange. This was partially offset by warmer weather in the District of Columbia, which had a $2 million negative year-over-year impact in the quarter, and unfavorable O&M expenses driven by employee benefits and incentive costs. SEMCO delivered normalized EBITDA of $19 million in the quarter, which is down $2 million year-over-year, as continued customer growth was offset by warmer weather in Michigan, which had a $2 million negative year-over-year impact in the quarter, and slightly higher O&M costs related to pension benefits. The retail platform was down year-over-year, which was principally driven by the timing of swaps and higher-cost gas in inventory.
During the second quarter, we deployed $198 million of invested capital at the utilities on behalf of our customers, including $125 million through our various ARP modernization programs. These investments are focused on upgrading the network to improve safety and reliability of our system, while also bringing ancillary benefits of long-term productivity improvements. As such, we will continue to make these upgrades on behalf of our customers, while balancing ongoing customer affordability needs during this environment of high interest rates and inflation. Turning to the Midstream segment, normalized EBITDA came in at $134 million, compared to $163 million in the second quarter of 2022. The quarter included strong operations and year-over-year volume growth across the platform, including global exports, but financial performance was impacted by a number of factors.
This included the wildfires and evacuation of the North Pine facility for a little more than 12 days, which had an approximately $7 million impact across the platform. Most importantly, we did not have any safety incidents associated with the wildfires, and there was no damage to the facility. We were able to return to normal operations once the evacuation orders were lifted, thanks to the dedication and hard work of all of our employees. During a period like this, we were also reminded of the great customers and partners we have across our operations, as everyone came together and had open and regular communication to ensure the safety of our employees and all our stakeholders in the communities surrounding the facility.
We also had a $7 million impact due to ship timing in the quarter, which will positively impact the third quarter. A $5 million impact due to hedge timing, which is expected to positively impact the fourth quarter results. The quarter was impacted by lower marketing contribution, lower Asian to North American butane margins as a result of higher-cost butane and inventory from the previous contracting season, and lower realized pricing on fractionation volumes. In the second quarter, we exported approximately 116,000 barrels per day of propane and butane to Asia, spread across 19 VLGCs, as well as 1 port partially loaded ship. This included over 70,000 barrels of propane exported from RIPET and 45,000 barrels per day of combined propane and butane from Ferndale. The quarter included 36% of global exported volumes tolled.
Tolled volumes do generate lower EBITDA per barrel of LPG exported, continue to advance our lower-risk business model. We continue to be well hedged in our global exports business for the remainder of 2023, with approximately 77% through a combination of toll and financial hedges, with the financial volumes hedged at an average FEI to North American spread of $15.32 US per barrel. As a result, we expect a strong contribution from the global export business in the second half of the year, and particularly in the fourth quarter, once we move through the remaining impact of higher-cost butane inventory from the last NGL contract year.
As a reminder, we expect to take delivery of 1 new VLGC time charter at the end of 2023, a new time charter in early 2024, as well as a third in the first half of 2026. Each of these time charters are expected to reduce our ocean freight costs by approximately 25% relative to normal Baltic freight pricing and lock in pricing on a long-term basis. In the corporate and other segment, we reported normalized EBITDA of $3 million, compared to a loss of $3 million in the second quarter of 2022. The $6 million year-over-year improvement was mainly driven by lower operating expenses associated with employee incentive plans.
In terms of other developments, while there was 2 stays placed on the Mountain Valley Pipeline by the Virginia Fourth Circuit of Appeals, those have now been vacated by the Supreme Court of the United States yesterday. The project can now move ahead with a targeted completion date of 2023 year-end. We've always believed in the fundamentals of MVP and the benefit of being able to bring Marcellus Utica gas down into East Coast utilities and consumption markets. The pipeline's initial 2 BCF per day capacity is fully subscribed, principally with investment-grade counterparties and strong demand-pull shippers, and it is further expandable through incremental compression, including firm and interruptible service.
We have always been transparent with regards to MVP being a non-core asset to our strategy, once the project is de-risked, it would be considered for monetization to reduce leverage and bring us closer to our long-term leverage goals. We have made significant progress towards lowering our leverage ratios and increasing the margins of safety within the business over time, including lower-risk commercial constructs, as we continue to focus on delivering durable and growing EPS and FFO per share growth. Within the utilities, there were a number of regulatory events during the quarter. In April, Washington Gas, SCC of Virginia staff, and the Office of the Attorney General, filed a proposed stipulation for a settlement that includes a revenue increase of $73 million and return on equity of 9.65%.
Washington Gas also filed a rate application in Maryland to increase rates by $28 million during the quarter, net of costs currently collected through the STRIDE ARP programs. We expect the Maryland PSC to make a decision on that application in mid-December. We also filed an application in Maryland for the third phase of the STRIDE ARP program for approximately $495 million of spending between 2024 through 2028, which will continue to provide runway to modernize the system and drive better long-term outcomes for our customers in the jurisdiction. Finally, in the District of Columbia, the PSC amended the schedule on our active rate case in that jurisdiction, and a hearing is tentatively scheduled for mid-September, with a final decision on that case now expected in early 2024.
At the halfway point of the year, we are sitting in line with where we expected to be when we issued our 2023 guidance back in December, and our overall outlook for the year hasn't changed, including our expectations of normalized EPS guidance of $1.85-$2.05 per share, and normalized EBITDA guidance of $1.5 billion-$1.6 billion. With that, I will turn it over to the operator for the Q&A session.
Thank you. Ladies and gentlemen, we'll now begin the question and answer session. If you have a question, please press star one. If you want to withdraw your question, please press star two. Your questions will be pulled in the order they are received. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Rob Hope, from Scotiabank. Please go ahead.
Good morning, everyone. Thanks for taking my question. Question for Vern. With being in the seat, a couple of weeks now, can you add some initial impressions of, kind of what you think as the key strengths of the AltaGas story, where the key opportunities are? Then longer term, how do you envision, you know, a company with Northeast BC Midstream and kind of Northeast, U.S., gas distribution assets, you know, do you think on a longer-term basis, those two make sense together?
Hi, Rob. Thanks for the question. I think that's probably the top-of-mind question I get from everyone I talk to, whether it's employees, the board of directors, or investors. Really, what attracted me to coming over to AltaGas is, number 1, I think the fundamentals of both businesses are quite strong. If we start with WGL, gas, for sure, remains the lowest cost energy source to provide space heating in the DMV, that's a pretty substantive margin. I think it's like by 300% or in that range. Also, if space heating in the DMV by gas is actually more GHG friendly than electrifying that part of the energy value chain, I think it's a pretty substantive GHG benefit as well.
There will be opportunities for us to lower that gas footprint, and, you know, I think you've seen things that my prior company did, and I think we can bring those experiences over here. With Midstream, obviously, there's very strong tailwinds for liquids growth in the WCSB on the back of natural gas development for LNG exports out of Western Canada. That, that is one of the key factors, there's strong energy fundamentals. There's great embedded growth opportunities here in the business. You're seeing visible capital that's available to be deployed for modernization of the utility. The utility continues to add meters and grow its customer base each and every year. The, the demand for natural gas is actually on the rise in our, in our franchise areas.
Within Midstream, I think the export story is really unique for Canadian Midstream companies. There's more opportunities to expand exports, there's more opportunities to grow the value chain in Midstream, to take advantage of our unique value proposition. We've got a great growth project underway right now with REEF. Its initial incremental capacity will be in the range of 50,000 barrels a day, but that only uses up a very small portion of the dock that we're gonna build there. As you mentioned, the company is not without challenges. I think it's fair to say that we're not quite firing on all cylinders at this time, and if we can make progress in optimizing both businesses, I think we're gonna create some shareholder value.
Obviously, at the utility, we've got to narrow the ROE gap. We've got to improve some of our regulatory relationships with regulators, particularly in D.C. We need to create better alignment on the energy dialogue, where energy affordability, energy reliability, and climate are all taken into account in the various regulatory frameworks we have. We're gonna make efforts to improve the risk profile in Midstream. We know we need to do more tolling, we know we need longer duration contracts, and we need to make sure we're very tightly managing any residual commodity risk that we have. We're on our journey on deleveraging the balance sheet, and you can see that we've made good progress after the last couple of years, and we have line of sight now on how we get to our target debt-to-EBITDA metrics.
That still remains to be done. At the outset, I think my focus with the team is to maximize all of these priorities, where we take advantage of our opportunities, work on our challenges, and then, that will create optionality for us on what the company looks like in the future. That's job one. As you know, we're always keenly focused on maximizing shareholder value, and that's what we'll be doing.
All right, I appreciate that color. Maybe just as a follow-up, just in terms of the risk profile in the business as well as, you know, increasing the interactiveness. When you take a look at the global export business overall, how do you balance additional growth opportunities, versus just terming up the existing, base business in a, in a longer-term manner? You know, is it first fully contract and extend the contract at the base business before any additional capital could get, sanctioned? I guess, would you look at any capital be fully backed up by contracts?
Well, I, I think there's gonna be some timing lags in making that happen, Rob. I think we, we understand long term, once the capital is fully deployed, that the, the cash flows need to be highly, highly contracted. It's probably debatable to what percentage at this particular point in time. I think the team here has talked about getting this at least 60% tolled over time on all of the volumes that we have. If we're able to go higher than that, I think that is an opportunity to de-decrease the volatility in that business, which should be positive for us overall.
All right. That's great. Good to hear from you, and congratulations on the new role. Thank you.
Thanks, Rob.
Thank you. Your next question comes from Jeremy Tonet, from JP Morgan. Please go ahead.
Hi, good morning.
Hi, Jeremy.
Hi. Just wanted to follow up a bit more with the LPG export business, if we could. Just, I guess, vision for how much, you know, risk can be taken off the table, how much tolling hedging, how far out do you see it going at this point, or strategic views on where that stands? Also, I guess, on the back of that, as, as it relates to 2023 open exposure, how do you feel that leaves AltaGas position within the guide? Is there a bias towards the low end or the high end of the guidance at this point?
Maybe I'll take the first part, then I'll turn it over to James to get into some of the details. If, I think what we're aiming for is more tolling. What we've seen is, over time, that tolling that we're able to get from the customer base is, is gradually going up. I think, when the facility came on stream, there was strong customer interest. During COVID, there was a decline in customer interest, this year, we're starting to see some demand pull customers from Asia who've now seen that the barrels are there ratably, the barrels are there consistently, and that there's a price advantage for them to source their barrels from Western Canada. We'll have a combination over time of demand pull volume and a supply push volume. We should...
Which should be beneficial to both sets of customers, where producers are gonna maximize their net backs by going to Asia, and buyers from Asian buyers are gonna maximize their profitability by accessing cheaper Western Canadian barrels. That's gonna take some time to firm up longer-term tolls, and I think it's very consistent with the answer that I provided to Rob, that we, we wanna get that number up, and we wanna lengthen the duration. It's not something that's gonna happen overnight, but the team's keenly focused on both of those objectives.
Jeremy, it's James here. With respect to your question on forecast, obviously, we're reiterating the range of CAD 1.5 billion-CAD 1.6 billion, and no different this year than any year. Halfway through the year, we've obviously experienced both headwinds and tailwinds relative to the initial guidance when we rolled that out in late 2022. In terms of some of the headwinds that we can give you some color on, obviously, weather has been a constant theme in terms of headwinds with the utilities, and that continued into the first month of the second quarter as we entered shoulder season. That's been a headwind all year. We've obviously had retail that's been impacted by milder weather and timing of some swaps.
We've also had the timing of some of our rate cases slip, potentially even into early 2024, in the case of our rate case in front of the D.C. regulators right now, that have been, that have been, headwinds at the utilities. With respect to midstream, obviously, the wildfires was something that impacted the quarter to the tune of CAD 7 million. We expect a little bit of a residual impact into the second half as we, we're still running on gen-sets at North Pine, as BC Hydro works to get high-line power back to facilities in the area. We touched on some of the continued drag on C4 margins as a result of last contracting year and the fact that we were a little higher from a tolling % standpoint.
We're moving slightly less merchant barrels, which hasn't dropped the weighted average cost of, of butane as quickly as we had anticipated when we rolled out our guidance. In terms of tailwinds, I mean, some of the positives are gonna be AFUDC. As MVP is making forward progress, the consortium is now booking AFUDC on that project again, and Q2 benefited slightly from that, and we expect that the second half of the year will benefit from continued AFUDC. Another tailwind is obviously stronger C3 margins.
... as the curve starts to set up for the winter season in Q4.
Got it. That's helpful. Thank you for that. Just I meant to ask as well on the LPG export, how much of the propane export at RIPET is sourced from AltaGas versus third parties? Are you guys able to share that?
Hi, it's Randy Toone. Approximately 10,000 barrels a day are sourced from our AltaGas barrels, and the remainder, let's say another 60,000, are sourced from customers.
That's helpful. Thank you. Vern, I realize it's only been a month on the sea, but just curious, I guess, your thoughts on, on the WGL side, getting out and meeting the, you know, the commissioners across your jurisdictions there. Thoughts on, you know, if you do that, when you do that, you know, how you think about building those relationships to narrow the underearning, a-as you said there, and curious specifically on Maryland, given shifts in the commission there, any thoughts that you're able to provide on that?
Well, I'll start, and I'll turn it over to Blue for some more color, Jeremy. Obviously, you hit the nail on the head. I think it's very important for us to file timely rate cases, but we also need to control the narrative, and have others advocate on our behalf as well. Obviously, we're very committed that natural gas is the most affordable energy for our customers. It's the most reliable energy for our customers, and in the DMV, it's actually the lowest carbon energy for our customers to heat their homes. We have to push that narrative hard, with all of the regulators that we deal with in the DMV. My plan is to work with Blue, to be there and be there regularly to actively help with that engagement.
We also want to build a coalition of energy users to also provide that message to the regulator, because I think it's important to get the public more dialed in on this particular topic.
Yeah. This is Blue, Jeremy. I agree with everything Vern said. The process, as you know, in our particular jurisdictions, while we're active in rate cases, it limits our ability to be in active discussions, unless it's focused on the rate case, of course, with the regulators. We have a good relationship. As you noted, you know, the Maryland PSC is turning over. We're working our way through, through those new relationships. I would say that our working relationship across all our jurisdictions are very good. As Vern points out, we constantly have a discussion through our customers on what they need and what they want, and how we're able to help them manage that affordability and reliability while progressing climate goals. We want to ensure that those voices are heard. We're pushing all of those forward, collectively.
I agree with the outline that, that Vern said, and we'll continue to work that process.
Got it. That's very helpful. I'll, I'll leave it there. Thanks.
Thank you. Your next question comes from Andrew Kuske, from Credit Suisse. Please go ahead.
Good morning. Maybe if we just focus on your Western Canadian midstream business and just your customer conversations. I guess it's sort of twofold. It's 1, their expectations on volumetric growth on a longer-term basis, given all the trends you talked about earlier on, and then their desire to have an integrated service, and in particular, more integrated service from AltaGas.
I think we'll let Randy tackle that one.
Hi, Andrew. So, for the discussions with our customers as far as tolling goes, you know, from the producer side, the producers in Western Canada, they are looking at market diversification, for their natural gas and also for their LPGs. You know, we're providing them with a new premium market. A lot of our sophisticated producers are looking at additional tolling and long-term tolling, for both propane and butane. Then our offtake customers, our Asian customers, they see us as a reliable, secure, source of LPG, and we're seeing that, that accelerate. A lot of more customers are wanting to do, you know, take the Western Canadian price and get that advantage. We are seeing that, a pull and push from both sides on products.
Andrew, I think this is a great opportunity for us because having the premium market allows you, over time, to extend your value chain reach all through the NGL midstream infrastructure process, where if you're, if you've got the, the best market to get to, you will then be able to offer more services on a more bundled basis, which ultimately will provide investment opportunities for us and just enhance the returns on our existing midstream assets. Over time, that's what we think the benefit of having the docks are, and I think we're gonna work very hard on extracting as much value as we can.
Appreciate that, and then, and maybe just expanding and then building upon that, what kind of return improvement do you think you can achieve, you know, especially on a risk-adjusted basis, if you get the volume growth, you know, greater stability with a higher percentage of tolls and maybe locked in on duration, and then corporate-wide, you know, you're deleveraging, which should result in better financing costs also, just collectively, how do you think about that opportunity on, on a BEPS basis and then the multiplier effect as you build out more infrastructure?
Well, that's a great question, Andrew. Well, it's gonna be very imperative for us to earn a premium above the hurdle rate on the capital that we invest, whether it's in midstream or whether it's in utility. We have a limited amount of capital that's available to us each and every year. We're obviously deleveraging. We're operating on an equity self-finance model, so we're gonna invest the capital into the, the highest return businesses or highest return projects, subject to making sure that the, our systems are safe and reliable. I think, maybe James can comment on the typical hurdle rates that we have, in each of the businesses, and obviously, we're shooting for a premium over those hurdle rates.
The only thing I'll add, Andrew, to Vern's commentary is, obviously, when we're looking at final investment decisions, we are looking at it on a risk-adjusted return basis. Vern talked about the fact that we want to get to a, as high degree, a percentage of tolling as possible. The higher the tolling percentage and the more stability in those cash flows and the longer duration of the contracts themselves, then that hurdle rate would be lower. That's how we're basically looking at those risk-adjusted returns. In terms of to REEF, we've talked about it in the past. You know, we feel that we can probably build that project at a 6 to 8 times build multiple, which would generate some strong returns.
We've talked about some of our, our hedging targets, sorry, our, our tolling targets with respect to that, that facility that would underpin the, the type of return that, that we could potentially be looking at with respect to REEF when it moves forward.
Okay. Thank you very much.
Thank you. Your next question comes from Robert Kwan from RBC Capital. Please go ahead.
Great, good morning. Vern, you, you talked earlier about some of the opportunities, and I'm just wondering, you know, it's still early, so are there things, though, that you're thinking about for AltaGas to do differently? I guess specifically, you know, where do you see, you know, the business mix? How are you thinking about leverage, whether it's the targets themselves or at least the timing to get there, and then, just the overall kind of structure of, of the company?
I think, Robert, what you're getting to is a commentary on the disciplined capital allocation. As you know, from my past experience, that's something that's been very important to me, and I think in the long term, that's how we optimize shareholder value. You're right, the starting place for disciplined capital allocation is a strong balance sheet. The team here has done a great job on deleveraging the company. We've got the target credit, credit metric, we have line of sight to that now.
I think with a combination of embedded EBITDA growth, that's gonna happen from the capital that the company's invested over the last couple of years, and select asset sales of non-core assets, we should make significant progress, hopefully sooner rather than later, to get us to that 4.5 times medium-term target. Once we're there, we'll reevaluate where we wanna be, but at that time right now, the main goal is to get from 5.1 to, to 5, 4.5, sorry, as quick as we can.
Then when we're there, we're gonna have $1 billion plus per year of annual investment capacity, where we don't need to issue any equity. That investment capacity will then go to the best capital allocation investment that we can make, which will grow EBITDA. Then we'll be in kind of that virtuous circle of deploying capital, growing our EBITDA, growing our dividend, and then having that cycle repeat. Hopefully that answers your question, Robert.
Yeah, that's great. You mentioned earlier in the call just optionality on what the company looks like in the future. Can you just elaborate on what you were getting at there?
Yeah, I think, there's lots of energy infrastructure companies out there. Some of them are pure play, some of them are diversified. We've seen diversified companies trade at premiums, we've seen them trade at discounts. We will continue to evaluate what is the best and most optimal structure for this, this company. Right now, we, we are what we are. As I mentioned earlier, we've got to we've got to get both of our businesses as close to optimal as we can, as job one, because that, that creates optionality.
I don't know if I can put words in your mouth. Effectively, as you think about wherever, you know, decisions you're, you're gonna make here, whether that's financial, operational, asset-wise, are you looking to basically just continue to position the company, get it into a position where as many of these options for value creation are on the table? Is that fair?
For sure. That's management's job, is to continuously look at how do we maximize shareholder value, for our shareholders.
Okay. Specifically, you talked about just the interplay between pure plays and diversify, that seems to be kind of important to have that optionality to go either way.
I think, any company always needs to be looking at that, regardless of what space they're in.
Okay, that's great. Thank you very much.
Thank you. Your next question comes from Robert Catellier from CIBC Capital Markets. Please go ahead.
Hi, at this point, I just have 2 follow-ups. Maybe I'll follow up Rob's question there on, on how you're looking at the business differently. You have the existing debt targets that are in place that exclude the hybrids. Do you have a view on what the leverage should be if you were to include the hybrids in that calculation? How does that change your look on the metrics?
You know, Rob, the metric that we've always cited did exclude pref and hybrids from it, and that's the relative progress we made, and it's been significant. When Vern touched on some of those targets in the context of our desired ratings as well, that's always factored in from a ratings calculation standpoint, right? I don't think it changes the overall metric on a gap basis that we want to get to at 4.5. Obviously, hybrids and pref are included in the rating agency calcs, and for us to get to BBB with Fitch, we've got to get to a 5.5x FFO to debt.
Obviously, with respect to S&P, to get to BBB, we need that 14%-15% on a regular basis with respect to FFO to debt percentage. It doesn't really change the overall 4.5, though. I think we're, we're still pushing towards that, and we've always consistently benchmarked ourselves against that, excluding pref and hybrids.
Okay. And then, just, a clarification here on the impact of the wildfires extending into the third quarter. Is that really limited just to the impact on the power costs from having to run on the gen-sets, or is there anything else? I'm thinking accumulation of barrels or, you know, just logistics and things like that.
No, it's the form-- Sorry.
Former, and quantify it. Is there, is less than the Q2 impact?
It's, it's significantly less than the Q2 impact. It's, it's $2 million, and it is very much limited to the fact that, that we still got to run on gen-sets. Operationally, the facility started to run pretty much at nameplate capacity when, when the evacuation order was lifted, and people able to get into the facility, inspect it, and make sure that there was no damage, and, and we were able to ramp up.
Okay, thanks, everyone.
Thank you. Your next question comes from Dariusz Lozny, from Bank of America. Please go ahead.
Hey, guys. Good morning. Thank you for taking my question. On the utilities business, just maybe more of a, a broad, strategic type question, how do you think about how the retail business factors into the overall risk profile, stability/predictability of earnings? Or asked another way, are the synergies that you get from that business and the incremental EBITDA, do they make the slightly enhanced risk profile and less predictability in earnings worth it, as you think about the trade-off between the two? Thank you.
I think the ener- the retail business has historically generated reasonable profitability for the company over time. There is obviously more volatility that comes from that business because, and particularly here, because we-- the company hasn't been employing hedge accounting, and that has changed. Going forward, you're gonna see less volatility out of that business. When there's a firm fixed-price gas sale, obviously the team locks in a fixed-price gas purchase. There will be some volume variability due to weather, but that is actively tracked and tightly managed. I think if we have the right systems, procedures, and people in place, this is a profitable business for us. As you'll see, starting next year, there'll be less volatility out of this segment.
I, I just want to add something that Vern touched on, which I think is an important distinction. Like, when it comes to the business itself, it's been very resilient and performed well through COVID. It obviously performed well through Winter Storm Uri as well, because the team does a great job at managing volatility from an economic basis. They're able to lock in profitability with a very active hedging program. Really, the volatility that we're seeing here is more to what Vern touched on, and that's the accounting or the lack of hedge accounting, and that's something that we implemented May of 2023. 2024 will be the first year that we've got full hedge accounting for the entire year, and that accounting volatility or reporting volatility will go away.
The underlying economics of the business are solid.
Awesome. Thank you guys very much. Really appreciate that additional color. One more, if I can, and this is just more clarification on the quarter. You guys called out positive contribution from AFUDC after the MVP restart in June, so I imagine that was just a stub period. Is there any way you could quantify what that contribution was in Q2, what you see it for the balance of the year, and whether there's anything embedded in your current year guidance around that?
Yeah. It, so I'll start with the last part of your question. With respect to the guidance, it was one of the, the tailwinds that I touched on, that, that's helped to offset some of the, the headwinds, and, and that's why we feel very, very comfortable with, with the range. In terms of the overall contribution to the, the quarter, that is in our financial statements under the equity note, it's about $6 million for June. We expect it to average about $5 million-$6 million per month for the balance of the year as we make forward progress as a consortium on that pipeline and get closer to the in-service date. That's the overall contribution there is.
Great. Thank you, guys, very much. Really appreciate it.
Thanks.
Thank you. Your next question comes from Patrick Kenny, from National Bank Financial. Please go ahead.
Oh, hey, guys. Just wanted to confirm, assuming MVP gets done now, and you're able to monetize your 10% stake by, say, early next year, would those proceeds go towards debt repayment on a permanent basis? I.e., you know, take down the, the leverage by 0.5 turn or so, or would you view it more as, say, dry powder to potentially accelerate organic growth or fund tuck-in acquisition opportunities?
Hey, Patrick, it's James here. No, we've always been pretty consistent that MVP was going to be an asset, that, when we were ready to monetize it, was gonna go straight to permanent debt reduction. It was obviously the quickest path for us to get to 4.5 times. You know, Vern touched on us being able to get there organically as well through EBITDA growth, but that was gonna take some more time. MVP is definitely the lever that we wanna pull to be able to permanently reduce our debt and get to that 4.5x target that we set for ourselves, way back in 2019.
Okay, perfect. Thanks for clarifying that. Maybe just from a corporate priority perspective, you know, clearly firming up the cash flow quality profile of the midstream business and maximizing utility ROEs is, is top of the list. Vern, given your experience at, you know, looking at all kinds of opportunities in the power sector, how are you thinking about maybe positioning the company over the medium term to potentially get back to developing large-scale renewables again, or potentially owning other mid-merit natural gas power plants? Maybe if you can comment on if there's any regional power markets out there that might be of particular interest to you, say, over a 5-year horizon.
Well, thanks for the question, Patrick. Right now, there's no plans to get into the power business. It's not even on the radar. We, we do have some energy transition investment opportunities in front of us. Obviously, we're working on carbon capture and sequestration hub here in Alberta and associated CO2 pipeline network. I think we've got, we've got clearance from the Alberta government to continue to work on that. We've got strong customer demand for that CO2 storage, so that's in front of us. We're working on a couple hydrogen hubs, one in Washington state and one in the DMV. Both of those play well into what we do here at AltaGas, which is transport liquid, gaseous and liquid energy. Right now, that's the focus because I think that's what we're good at.
Got it. Okay, appreciate that color. I'll leave it there, guys. Thanks.
Thank you. Ladies and gentlemen, as a reminder, should you have a question, please press star 1. Your next question comes from Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I don't want to belabor the point of the theory of a firm, but it is topical, as you can appreciate. Beyond the strategic and capital market access and cost considerations, are there any tax considerations when you're looking at and assessing the merits of a diversified, consolidated company versus a pure play? How do you factor in considerations around the scale of a pure play versus the potential dyssynergies of additional corporate costs? You know, have you discussed this at any point with the credit rating agencies?
You know, those are great points, Linda. There's obviously some funding and tax synergies with the structure we have today, and there are relatively minor cost synergies by having a corporate function here that provides services to both of the businesses. Those factors for sure will have to be looked at as part of any analysis that we do longer term on what do we look like. You're right, if we would split up the company, both remaining entities would be relatively small.
Thank you.
Thank you. There are no further questions at this time. You may proceed.
Thanks. Thank you, everyone, once again for joining our call today and for your interest in AltaGas. That concludes our call this morning. I hope you enjoy the rest of your day, and you may now disconnect your phone lines.