AltaGas Ltd.

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Third Quarter 2023 Financial Results Conference Call. My name is Sarah 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 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' third quarter 2023 financial results conference call. Speaking on the call this morning will be Vern Yu, President and Chief Executive Officer and James Harbalis, 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, Lou 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 everybody has taken the opportunity to review the press release and our third quarter results, This call is being webcast, so I 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, 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 Bernu providing some comments on our financial performance and progress on our strategic priorities, followed by James Harbalis, providing a more detailed walkthrough of our third quarter financial results, our near-term outlook, and our 2023 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 in today's call. This information is subject to certain risks and uncertainties as outlined in our forward-looking information disclosure on slide two of our presentation, which can be found on our website, and more fully within our public disclosure filings on CDAR. And with that, I'll now turn the call over to Vern.

Thanks, Adam. Good morning, everyone. It's great to be here today to discuss Altagas's third quarter financial results and to provide you with an update on our operations and our corporate priorities. During the quarter, Altagas made significant progress on a number of these strategic priorities that will create long-term value And I'll touch on these in my remarks. In Q3, we also demonstrated strong financial performance and stability. Management was focused on operational excellence and proactive risk management. Let's start with slide four. Here we show AltaGas continued to execute on its long-term business strategy, and we delivered strong results across the board. Q3 came in with normalized EBITDA of $252 million and normalized EPS of $0.10 per share, which were both above our internal expectations for the quarter. With the completion of Q3, coupled with our prior results for the first half of the year, we're well positioned relative to our 2023 guidance. And in fact, we now expect to come in in the upper half of the range. Let's move to slide 5, which shows that midstream performance in Q3 was robust. Operating results reflect record export volumes and strong global demand for LPGs. And these results highlight Canada's West Coast advantage for LPGs. Global LPG demand has been robust this year, growing by 3% over 2022. We expect similar growth in 2024, which will continue for many years to come, primarily on the back of growing long term demand for LPGs in Asia. In Q3, global export volumes were up 7% year over year. Fractionation and liquids handling was up 12% year over year. Our gas processing volumes were down modestly in the quarter due to maintenance. However, volumes have already recovered from these planned outages. We had 93% of global exports told or financially hedged in the third quarter, protecting our structural West Coast advantage. For the balance of 2023, 87% of our global export volumes are told or financially hedged. We have also been active in hedging our 2024 exposure. where 76% of Q1 is now hedged, and we are more than 50% hedged in Q2. This reflects our ongoing commitment to reduce the volatility in our midstream segment. Let's move on to our Pipestone acquisition that we announced in August. Since the announcement, we have received all material regulatory approvals, including Canadian Competition Act approval. We are currently working on finalizing commercial agreements with our customers and locking in fixed price EPC contracts for Pipestone 2, which will allow us to FID and close the transaction, which we expect to occur prior to year end. As a reminder, the acquisition is a strong strategic fit for AltaGas. It will be risk accretive through long-term take-or-pay commercial contracts, and the deal reduces our overall commodity exposure. The transaction was also purposely structured to reduce our leverage. And it will draw a 5% earnings accretion once Pipestone 2 comes online. We're excited to close the transaction and integrate the assets into AltaGas's midstream value chain. Our reef LPG export expansion continues to make good progress. The project is in the feed stage with an FID expected in the first half of 2024. We have plans to start site clearing work before the end of the year. And finally, we continue to make strong advancements on long-term commercial agreements that will de-risk the expansion. Just as a reminder, we're proud to have strong local partners for the projects. This includes First Nations, local communities and the Prince Rupert Port Authority. Slide 6 shows that our utility segment performed in line with our expectations in the quarter. I believe that gas utilities are irreplaceable and are a key part of the ongoing energy evolution. Natural gas accounts for nearly 70% of U.S. household energy demand, yet only represents a third of home energy costs. As such, natural gas is the most cost-efficient home energy source. In fact, switching to electricity would increase home energy costs by roughly 350% for the average homeowner in our franchise area. It's also the most reliable source of energy for homeowners. as we all know about the declining reliability of the power grid. As such, we believe our utilities will be critical in the years ahead. We remained active on the regulatory front in all of our jurisdictions in the quarter. In August, we received a positive settlement on our Virginia rate case, which calls for $41 million U.S. of increases in rate-based rates. as well as the $32 million US increase in modernization riders. In October, we received a proposed system modernization extension in Maryland, which will run through the end of 2028. The proposal will provide WGI with another five years of visible growth. The administrative law judge has recommended that the commission approve $330 million US of capital to upgrade our system, improving safety and reliability. This builds on our accelerated pipe replacement program in Virginia that was recently extended to the end of 2027. Our rate cases in DC and Maryland remain ongoing. We expect a decision in Maryland before the end of this year and a decision in DC in the first quarter of 2024. As we have messaged in the past, we expect to show a high degree of regulatory, capital, and cost discipline across all of our jurisdictions. That will include being active with our regulators as we push for the most pragmatic approach to drive the best outcomes for all of our customers and stakeholders. Now let's spend a minute on WGL's first large-scale RNG initiative. In October, WGL executed a definitive agreement with Opal Fuels to support an RNG project at the Prince William County landfill in Virginia. Here, WGL will become a RNG offtaker for the RNG production that comes from the landfill. The RNG will be blended into our gas stream, which will reduce the carbon intensity of our energy. As part of the agreement, WGL will purchase interconnect infrastructure from Opal for around $25 million US. The interconnection will be put into rate base and it will be eligible to earn 100 basis point ROE premium. This is a great little deal for us. It reduces the emissions of our customers. It adds to our rate base and then we're actually able to earn an ROE premium. The more time I spend here at AltaGas, the more excited I could become about our long term investment proposition. James will cover this off in more detail in his section. With that, I'm going to turn it over to James to provide a more fulsome review of our third quarter results and update you on our financial priorities.

Thank you Vern and good morning everyone. As Vern discussed, we are very pleased with the operational financial results we delivered in the third quarter of 2023 and the progress we have made across our strategic priorities. We achieved normalized EPS of $0.10, normalized EBITDA of $252 million, and normalized FFO per share of $0.50. These results were slightly above our expectations and leave us well positioned to achieve our 2023 guidance. Within the midstream segment, normalized EBITDA was at $185 million compared to $108 million in the third quarter of 2022. The quarter included strong operational performance across the platform, including record global export volumes, strong year-over-year increases to fractionation and extraction volumes, and strong Asian to North American LPG margins. We exported more than 118,000 barrels of propane and butane to Asia across 20 built VLGCs and one partially loaded ship. This included more than 70,000 barrels per day at Ripit and approximately 48,000 barrels per day at Ferndale. Global exports across all industries witnessed higher maritime shipping costs due to challenges at the Panama Canal materially increasing rates globally. However, this was significantly mitigated from our existing time charters active baltic freight hedges and higher tolling levels relative to last year the third quarter also benefited from afudc related to mvp construction activities as forward progress continued on the pipeline as well as higher ngl and crude marketing contributions we continue to be well hedged in our global exports business for the remainder of 2023 with approximately 87 percent told or financially hedged in the fourth quarter with the merchant volumes hedged at an average FEI to North American spread of $18.13 US per barrel. This, combined with the improvement in propane FEI to North American spreads, as well as us having worked through the higher cost butane inventory from the prior NGL contracting year, we expect strong contribution from the global export business in the fourth quarter of 2023. We have also begun actively hedging for 2024 as part of our systematic risk management practices and currently sit at 76% hedged for the first quarter of 2024, with the merchant volumes hedged at an average FEI to North American spread of approximately $17 US per barrel and sit at more than 50% hedged for the second and third quarter of 2024. We had a number of positive de-risking initiatives advance within our global export business over the past couple of months. The first was that we entered a five-year transportation agreement with CN in October. The agreement provides AltaGas and our customers with cost and service predictability to support our growing LPG exports to Asia. The agreement will provide predictability for our existing business and future volume growth, including the reef expansion. The second was progress on final commissioning on two of AltaGas' new VLGCs over the third quarter, with the Boreal Pioneer expected to have its maiden voyage in December of 2023 and the Boreal Voyager expected to have its first passage in March 2024. These two seven-year time charters with optional extensions will reduce our total shipping cost to Asia by approximately 25% compared to a standard VLGC and normal shipping. The vessel's deployments will also remove pricing volatility and de-risk maritime shipping costs on a long-term basis, consistent with our plan to commercially de-risk our midstream business over the long term. In total, we will have three time charters operating in 2024, with a fourth currently under construction and set to be commissioned in the first half of 2026. Turning to the operating segments, the utility segment reported normalized EBITDA of $71 million in the third quarter of 2023, as compared to $115 million in the third quarter of 2022. Financial results were in line with our expectations, with the year-over-year decline principally driven by the large Q3 2022 asset optimization contribution at WGL, which we share with our customers, and the lost contribution of the Alaskan utilities, which were divested on March 1st, 2023, and had contributed $13 million normalized EBITDA in Q3 of 2022. During the third quarter, we deployed $204 million of invested capital at the utilities on behalf of our customers, including $130 million through our various 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. These programs also provide an immediate return on investment through rate riders and are not challenged from regulatory lag. As such, we will continue to make these upgrades on behalf of our customers while balancing ongoing customer affordability needs during the current environment of high interest rates and inflation. In the corporate and other segment, we reported normalized EBITDA loss of $4 million compared to normalized EBITDA of $10 million in the third quarter of 2022. The decrease was mainly driven by lower contribution from Blythe due to turnaround activity in 2023 and higher expenses associated with employee incentive plans due to AltaGas' rising stock price. AltaGas has made tremendous progress on restructuring the platform over the past four years, including de-risking the balance sheet. This includes significant leverage reduction with approximately 90% of the company's debt now being fixed under a properly staggered maturity ladder while also having optionality for additional debt repayments. These moves have strongly positioned AltaGas for the current operating environment and protected the company from the material increases in interest rates over the past 18 months. Looking ahead, we are focused on continued commercial de-risking as outlined on slide seven. This includes higher tolling and global exports, active and systematic hedging for residual commodity exposure, a strong focus on take-or-pay and fee-for-service contracting, customer and resource play diversification, and long-term cost contracting like the five-year CN agreement and VLGC time charters. Within the utilities, we are focused on utilizing ARP modernization programs for upgrade assets to improve safety and reliability, active and systematic hedging in the retail business, advocating for weather and usage normalization across jurisdictions, which are currently in place in Virginia and Maryland, as well as for prescribed timelines for rate cases across all jurisdictions. Turning to capital allocation on slide eight, we are focused on balancing our three pillars of balance sheet capacity, shareholder returns, and organic growth. On the balance sheet, we continue to target reducing leverage to our four and a half times net debt to normalized EBITDA target over the coming period as we complete our multi-year deleveraging journey. Along that vein, we were excited about the strong progress that has been made on construction activity at the Mountain Valley Pipeline over the past three months. The pipeline is expected to be placed into service during the first quarter of 2024 and will provide critical energy security to utilities in the eastern U.S. The updated aggregate capital cost of the pipeline is $7.2 billion with AltaGas' cash contribution contractually capped at its original $352 million investment for 10% equity interest. This cap was hit in 2019 with no additional cash contributions impacting us as a result of this structure. As previously disclosed, AltaGas does not consider its equity stake as core and will consider a monetization of our stake as one of the most immediate paths to moving towards our four and a half times leverage target. For shareholder returns, we target a payout ratio of 50 to 60% of earnings per share, which is consistent with our payout ratio over the past three years. And finally, on capital spending, we continue to take a prudent approach to our investments. Our first bucket of capital is also allocated to utility system betterment, utilities customer growth, and midstream maintenance spending, which collectively ensures that we have safe and reliable assets for existing operations. After that, we allocate our discretionary growth capex to our utilities modernization programs and core midstream growth projects. This capital is always deployed in line with our individual risk-adjusted hurdle rates and ranked against the various opportunities in front of us, including all organic growth projects, repayment of debt, M&A, and potentially share buybacks, post us reaching our leverage targets on the ladder. Turning to our value proposition on slide nine, we are excited about the road ahead. We are positioned to deliver industry-leading dividend growth through stable and increasing cash flows. We will be able to improve our risk profile through commercial constructs and our ongoing balance sheet deleveraging. The long-term fundamentals for AltaGas are strong. The Canadian upstream industry will deliver significant growth in natural gas and NGL production. Growing NGL volumes will need additional West Coast egress to maximize value for our customers and provide critical energy security to Asia. Our utilities have a bright future, with natural gas being a critical fuel that will be required to balance the needs of energy affordability and energy reliability with our climate goals. As Vern highlighted, on the back of the strong third quarter and year-to-date results, we are well positioned to achieve our 2023 guidance figures of normalized EPS of 185 to 205 and normalized EBITDA of 1.5 to 1.6 billion and expect to be in the upper half of the guidance range. We look forward to hosting our investor day on December 5th, where we'll release our 2024 guidance and provide an update on our corporate strategy and provide our near and long-term corporate priorities. 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 question and answer session. If you would like to ask a question, please press star, then the number one on your telephone keypad. If you would like to withdraw your questions, please press star one again. There will be a brief pause while we compile the Q&A roster. Your first question comes from the line of Jeremy Tonnet with JP Morgan. Your line is open.

Hi. Good morning.

Hi, Jeremy. How are you?

Good. Good. Thanks. Just wanted to start off with LPG export economics here. Clearly, things are looking pretty good right now, but just wondering how you guys think about the sustainability of export economics at this point, and also how you think about a bit more color and how you think about leveraging that into potentially tolling or firming up in general. Just any thoughts along those lines would be helpful.

Great. That's a great question, Jeremy. Well, maybe let's just start with the fundamentals. The Asian market is obviously the best market for North America LPGs. And in fact, Asia today imports about 3 million barrels a day of propane and butane. About 2 million barrels of that comes from the U.S. Gulf Coast, and about a million comes from the Middle East. We're continuing to see, obviously, in the Permian, increased NGL production. And every incremental barrel there is looking to go offshore. So for the Canadian producer, I think there's less and less incentive to take your NGL barrel to the U.S. and more and more incentive to go west. Since Ripit's been up and running, on average, if you look at the positive net back that you can get by going to Asia as opposed to going into Conway or Bellevue, um over the last six years it's averaged about three dollars per barrel uh u.s after taking into account all of the costs that's rail costs shipping costs and our capital charges uh at our export facility so if you were a told customer you'd be seeing that three dollars a barrel over the last six years um as we look today that's that's well over five dollars a barrel so i think the long-term and immediate positive contributions that this will make to our customers are obviously very strong. So right now, we're in active dialogue with producers in Western Canada to improve their netbacks. Obviously, we're talking to Asian buyers on a reverse toll basis for them to access cheap Canadian barrels. And we're talking to NGL aggregators to see if we can lock up long-term tolling deals. I think we've talked about in the past of getting to 50% next year and then higher over time to that 60 plus percent range as we look to FID, our reef project. So I think we're very bullish on the structural West Coast advantage. And we see that only getting better as the fundamentals are big tailwind for us right now, Jeremy.

Got it. That certainly makes sense. And just wanted to pivot to Pipestone, if I could, if it might be able to provide a little bit of incremental color with regards to synergy potential and along the lines of LPG export, I guess, having greater supply, I guess. Do you see that kind of aiding your efforts on your prior points you made there?

Sure. I'm going to make just a couple initial observations and I'll turn it over to James to talk about the accretion and maybe Randy can talk about how many barrels we see here for incremental exports. Obviously, we feel the transaction was highly strategic for us. It's risk-accretive as it increases the amount of take-or-pay contracts we have in our portfolio. It decreases our overall commodity exposure. It was done where we've issued a bunch of equity to the vendors. So it is actually leverage accretive. And I think we paid a very fair price. So it checks all the boxes, but I'll turn it over to James to talk about how accretive we see the transaction. Then Randy will talk about the export positions.

Yeah, thanks, Vern. So in terms of accretion, Jeremy, when we announced the deal, we said that it was going to be about 4% to 5% accretive to EPS once Pipestone 2 has been built and online. And we would expect that to be 24 months after FID is accomplished. In terms of advancing the Pipestone transaction to close, obviously, we've received regulatory approvals, and Vern touched on that in our prepared remarks. But we are advancing commercial discussions with customers in the area. We're very encouraged by the level of demand. for processing and liquids handling capacity in the area. So we see those moving ahead positively. We're also obviously trying to lock down our EPC contracts on the engineering front so that we can be in a position to declare FID by the end of the year and potentially close the transaction by the end of the year. And the demand for the liquids handling capacity, it really goes to the heart of your question around additional barrels being available for export, which both of these facilities bring. So I'll turn it over to Randy.

Thanks, James. Yeah, the Pipestone gas plant is located in a great part of the Montney, very liquid rich. They have deep cut capabilities. So Pipestone 1 produces about 4,000 barrels a day of LPG that with the gas processing arrangements, we market those barrels for our customers. And those will be, they have good egress to Port Saskatchewan. And then we have access to those barrels to move to exports from there. Pipestone 2 will double those, so 8,000 plus barrels, and we plan on exporting those as well. So all the customers we're talking to about gas processing are looking forward to being able to export those barrels to Asian markets.

Very helpful. Thank you for that. And if I could just pivot real quick here to capital allocation, it seems like MVP might just be hitting the finish line here, and that could potentially unlock a lot of new flexibility for AltaGas upon a successful sale after MVP completion. Just wondering if you could update us on capital allocation in light of this dynamic and how you see things progressing going forward.

Well, I'll start off and I'll let James on if I miss anything here. Obviously, we've talked about getting to four and a half times debt-to-EBITDA, MVP is obviously the catalyst that gets us there in a material fashion. So it's great to see good progress on the construction of the pipeline. And we're hopeful that the proponent will be able to finish construction in Q1 of next year. And as James mentioned in his prepared remarks, obviously, we're actively looking to sell our interest in the pipeline once there's clarity on operations. I think when we get to that four and a half times target, we'll have about $1.4 billion per year of investment capacity. And as James mentioned, we'll be balancing that investment capacity with managing the balance sheet, making sure we take care of safety and critical maintenance capital that we have in our systems, and then continuing to grow our company with organic growth projects, and we've talked about a few already today. And over time, if we're at a strong balance sheet position, that'll unlock the possibility of doing share buybacks as well. Over to you, James, if you want to add anything. I thought that was pretty thorough.

Great. Thank you for that. One quick last one, the analyst day. Anything we should be expecting there?

I think we're going to provide a lot of color on why we're very bullish on the business. I think the fundamentals for the West Coast businesses we've talked about are extremely strong. I think that the fundamentals for gas utilities in the eastern part of the United States is improving each and every day. I think the energy evolution is going to take a lot longer And it's going to be more challenging than perhaps policymakers have thought of. And I think some of the developments with the U.S. Northeast offshore wind really hit home on energy reliability, energy affordability, and energy security, and how we need to balance that off against our climate goals. So I think we'll have a great opportunity to deep dive into the fundamentals of both of our businesses and how We're very excited about the growth prospects for the company, as James mentioned in his prepared remarks, that we believe we have an industry-leading investment proposition, Jeremy. Wonderful. Thank you very much.

Your next question comes from the line of Darius Losney with Bank of America. Your line is open.

Hey, guys. Good morning. Thanks for taking the question. Maybe just Sticking into the new agreement that you announced with CN Rail on transport to Ripit, can you maybe discuss a little bit about how that's expected to impact costs in the near term and over the term of the contract? Also, maybe any additional color that you can add as far as does it include escalators or any other terms that we should be aware of? Thank you.

Yeah, it's James here. I can touch on some of the cost aspects and have turned it over to Randy if he wants to add anything. But I mean, in terms of the contract itself, it does give us long-term certainty over rates. Obviously, those rates are lower than manifest rates, so we would expect to see a positive impact to margins based on what we were paying under the expiring contract. All contracts have CPI escalators to them, and this one is no different. But the fact that we were able to lock in rates for a five-year period below manifest rates was an important initiative for us that will improve margins.

Yeah, I can just add to that. All rail agreements have escalation clauses. I can't get into the details of the contract due to confidentiality, but we feel that we've got a very strong contract that gives us certainty, especially when we're trying to de-risk reef and trying to get long-term towing arrangements for our customers. So we feel it's a very strong contract, and it's not just out to Ripit, but it's also to Ferndale and up to northeast BC.

Thank you for that. And one more, if I could, and this is on the utility side of the business. The RNG deal that you announced with WGL, as you mentioned in the opening remarks, obviously seems like a pretty favorable deal with the 100 basis points premium. Just curious what the potential runway might be for any additional deal similar to that to acquire some infrastructure and potentially get an ROE premium.

I think it's a great question. We're excited about RNG. We think it has a big place in our overall portfolio. I think we're starting that journey, but maybe Blue can comment on the transaction we're looking at right now.

Yeah, thanks, Vern. Yeah, we are excited about the transaction. As you are well aware, Virginia passed what is known as the Virginia Energy Innovation Act. That law came into effect which opened up the opportunity to bring some of these alternative or lower carbon impact fuels into the regulated process. This is our first large transaction under that particular law. There are certainly other transaction opportunities in our footprint. We continue to work multiple opportunities across our geography, and we're balancing those opportunities with the work that we're also doing around ensuring that policymakers understand the opportunity and the benefit to customers for this. So we like this project. We will take 49% of the physical gas supply on the project. We'll take 10% of the green attributes on that. And so our customers will benefit by flowing 100% of the molecules across our system. And we'll blend that in, which helps our targeted emissions and also helps those customers who have specific needs and requests on their particular climate target. So we're really excited about the opportunity. I think there's more to come for us across the portfolio.

Great. Well, thank you guys for the color. I'll pass it along here.

Your next question comes from the line of Patrick Kenney with National Bank Financial. Your line is open.

Yeah. Hey, guys. You touched on the reef expansion opportunity. Maybe just an update on the feed study. how cost estimates might be tracking relative to your initial expectations, any comments around customer demand for offtake, and then just to clarify the timing for a potential FID decision.

Thanks. Okay, I'll kick it off and then turn it over to Randy if I miss anything. So we're well into feed. We're obviously looking to materially de-risk our capital cost exposure here. What we want to do is do as much modular construction as we can and limit the amount of site construction that's being done. So, in fact, we're modifying the design a little bit to allow us to do that. I think the capital, I don't think we're well enough along to give you an estimate what the capital might be. But suffice it to say, it's going to be more than what Ripit cost, but it'll still be quite manageable. And obviously, we have a 50-50 partner with Bopac to share the overall capital commitment. Customer interest for the expansion is quite strong. We're seeing interest from producers, Asian buyers, and NGL aggregators. So on that front, it's very exciting. I think our hope is to take FID sometime in the first half of next year. And I think we have all the milestones in front of us to allow that to happen. And obviously, we're bullish on the project because we're starting with site clearing later this month. So I think the project's shaping up well. And once the dock is up, it'll give us more growth opportunities as we go forward. Just as a reminder, the initial phase of reef only uses up 10% of the dog space. Anything you want to add, Randy?

No, I'll just reiterate, we're very positive about the project, so much so that we are going ahead with tree clearing. And that just gives us more confidence in the earthworks for the project. And and our goal is just to really get a better understanding of capital costs before we pull the trigger. But we know, we're quite confident that that will happen.

Okay, that's a great update, guys. Thank you. And then maybe just a quick cleanup question on the lower contribution from Blythe in the quarter. Was that just a normalization of performance year over year, or has there been any structural decline in

margins for some reason um and then maybe just an update on you know how you're thinking about maximizing the value of the asset either through you know further contract extensions from here or potentially monetization over the near term yeah hey pat it's it's james here so look in terms of blithe obviously it's under an existing uh three-year tolling arrangement that that uh expires at the end of uh 2023 so uh the variability in the cash flows wasn't as a result of that it was a small turnaround that needed to be done at the facility and and that's why we we saw a little bit of a pullback in q3 that's already uh on on track to recover uh in q4 so it's not really uh any kind of margin erosion with respect to the facility itself um obviously the the actual the plant is very important to california's power grid and as a result of that we've been successful extending the contract by another four years that takes us out to 2027 And we've always said that that is an asset that is our sole remaining power asset and isn't core. So if we see a valuation that reflects the extrinsic value of that asset, then we would transact. We have seen some positive developments along those lines with precedent transactions in the California power markets. So that's what we'll continue to track. And if we see the appropriate value for that asset, then we would see that as another path to accelerate our debt leveraging along with the Mountain Valley pipeline.

Okay, great. Thanks for that clarity, James. I'll leave it there.

Your next question comes from the line of Robert Kwan with RBC Capital Markets. Your line is open.

Great. Good morning. If I could start with the utilities business, you've highlighted the pretty significant ROE improvement that you've had to date, but it's still lagging quite a bit in terms of the allowed ROE. So can you just talk about, you've talked, I guess, generally about how you want to get that up, but just how much of a lag do you think is structural, just as you think about the regulatory frameworks and your recoveries versus where you're allowed with SET? Essentially, what's the bogey here?

Well, I think the way we have to look at it, Robert, is jurisdiction by jurisdiction. I think we're pretty much bang on or allowed in Virginia. We're very modestly below in Maryland. This year, because of weather, we're going to be behind in Michigan. But over the history of the company, we've been at or above the allowed there most of the time. So systemically, the problem is D.C., and that's been the problem for many years now, where we're subject to weather risk as well as a very slow regulator. So in the current rate case that we have in front of the D.C. regulator, we're asking for weather normalization. And in fact, another positive step that we've seen of the jurisdiction is The commission has been asking for commentary on mandatory timelines to deliver rate cases. So I think once we get the existing decision in from D.C. that will materially help close the gap in that jurisdiction, our plan is to file another rate case right after that to even try to get closer. So, and then hopefully we'll be successful on weather normalization, which in this year would be two or 300 basis points of return mismatch. So, Blue, did you want to add anything?

No, I think you hit the highlights. I think it's positive that the commission is asking for regulatory constructs or structures that would facilitate a speedier response. We, of course, replied to that, so we take that as a positive sign that they are recognizing how long that process takes in some cases, and we're optimistic that that will be beneficial.

Robert, James here. I just want to, sorry, no, it's James. I just wanted to add one more thing, and I think it goes to Vern's comment around the subsequent rate case that we were planning on filing. The important part there is that once we file that, the historical test year would be 2023. So whatever gets embedded in rates as a result of that rate case would reflect costs that we've incurred and capital investments that we've made up to the end of 2023. Okay, that's very color.

If I can just finish here on Reef. So obviously you're kind of showing your sign of confidence at the site clearing. Can you just talk about the contracting strategy and what needs to be done to get to, you know, first half of next year FID? You're still short on RIFID, I think, where you want to be on tolling. And then you've got all the Reef capacity that you probably want to lock up a very significant portion of that. So just given how difficult it's been to get, rippet tolling higher. You know, what do we need to see on reef to get to the FID?

So do you, are you primarily concerned about the commercial side or the capital side, Robert?

Yeah, sorry, the commercial side.

Okay, thanks. So if you look at our overall export book now, it's something in the range of 125,000 barrels a day. We, this year, had about 40% tolling. Next year, we're on track to get 50% tolling for that book. Obviously, Reef adds another 50,000 barrels a day, so we'd be up to total export capacity in the range of 175,000 barrels a day, not taking into account some debottlenecking that may or may not happen at Ferndale. So, ideally, we'd like to be in that range of 100 or more than 100,000 barrels a day of told exports on a long-term basis. What's really been positive for us is obviously LNG Canada is coming into service here in the near future. Our producing customers up in northeast BC have been very active now in developing their drilling plans to fill that natural gas to get to LNG Canada. And obviously the most attractive place to drill is in the Montney, and with that comes NGLs. So we're in deep commercial discussions with incremental producers who are very much looking at long-term production uh export tolling arrangements with us so um i think before uh fid will have clear line of sight uh that um that we're going to be successful in signing these guys up so i think uh it's quite exciting can't give you more than that right now because of the act of commercial agreements but uh the the tailwinds are really behind us right now robert

Okay, so to be clear, if you do go to the FID in the first half of next year, you're either going to have the $100,000 in hand or basically be at the negotiating stage where you're highly confident you'll convert those shortly after FID?

Yeah, obviously some of these will ramp up over time, Robert. Totally. Because, yeah, REIF's not going to come into service until – end of 2026, and then which is going to be a ramp up. So we will have to have very high visibility into tolling before we're going to put that much capital at risk. Right.

Just to be clear, you would have the executed agreements that may not take effect until 2026 or maybe even 2027, but you'll have those agreements in hand versus the we FID, we think we're going to have them in 2026. Is that fair?

That's the plan.

Okay.

Thank you. Your final question comes from the line of Ben Pham of BMO. Your line is open.

Hi. Thanks. A couple of cleanup questions. First on the dividend growth language in the deck you're mentioning, growing a dividend up to the EPS growth rate. replaced that previous guidance range. So you've noted that 5% to 7%?

Well, Ben, I think what we're trying to make clear is that we feel like our cash flow and our earnings are going to grow at a very healthy clip, no different than what we had previously indicated. What I wanted to clarify is we'll grow the dividend rate up to that growth rate subject to the investment community wanting that dividend increase. I think from my past experience, promising the full dividend growth to match the earnings or cash flow growth didn't always make sense every year because there are times when the company's yield is dislocated. So it will be an annual decision, but there's no change in the financial outlook at the company.

Okay. Let me just parse a bit more. So if you have a year that you're growing EPS at 2%, not to suggest that you will, then that's a perceived 5% to 7% that you had previously?

Well, obviously, we're going to grow our dividend based on our view of the long-term growth profile of the company, not a single point year change in earnings or cash flow. If we believe that the company is sustainably growing at 5% to 7% per year and the investment community is receptive to our current dividend profile, we will grow the dividend 5% to 7% per year.

And then also, I'm not sure this tweak to the, just your journey on the leverage reduction, is it purposeful leaving out the five times you've had in the past that your sites are much quicker now, four and a half times, is that purposeful?

Ben, it's James here. I mean, we've always set a target of five times in the medium term and four and a half times in the long term, dating as far back as 2019. What we've said is that obviously we can get to four and a half times through organic growth, but that would take us longer to get there. The four and a half times is somewhere we can get to on a more immediate basis through the monetization of MVP and potentially blight. So that is the slight clarification in the messaging here.

Okay, great. I just want to square that. And maybe lastly, you think about monetizing MVP. I know you've been talking about that for... for some time as non-core, but I guess you got somewhat choppy markets the last 12 months and monetization prices being quite wide. How do you balance that dynamic with that four and a half times leverage target?

I mean, from our standpoint, we still think that MVP has certain characteristics as a pipeline that are going to make it very valuable. Obviously, it's going to be free cash flow positive from the time it comes into service when COD is accomplished. It's a pipeline that could experience organic growth through additional compression on the main line. And obviously, Southgate is an ability for an investor to expand as well with the Southgate expansion potentially moving into an open season here as they decide to make forward progress. So we think those characteristics are going to be important ones that will attract significant attention for MVP and fetch a strong valuation for us. And the last thing I'll leave on MVP is it does have 20-year history. offtake agreements with strongly rated utilities and obviously a strongly rated shipper that is very, very active in the Marcellus. So we're very confident that we can get a strong price for this asset.

Okay. All right. Thank you.

There are no further questions.

Thanks, Sarah. Thank you, everyone, once again for joining our call today and for your interest in Ulta Gas. That concludes our call this morning. I hope you all enjoy the rest of your day. You may now disconnect your phone lines.