AltaGas Ltd

TSX:ALA

Earnings Call Transcript

[Operator]

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Third Quarter 2022 Financial Results Conference Call. My name is Jeff, and I'll be your operator for today's call. [Operator Instructions] As a reminder, this conference call is being broadcast live on the Internet and is recorded.

I would now like to turn the conference call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.

[Adam McKnight, executive]

Thanks, Jeff, and Good morning, everyone. Thank you for joining us today for AltaGas' Third Quarter 2022 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 is taking the opportunity to review the press release and our third 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 highlight some of the key year-over-year variances and non-recurring items that we would assume that would be helpful to 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.

As for the structure of the call, we'll start with Randy Crawford, providing some comments on the financial performance and progress on our strategic priorities followed by James Harbilas, providing a more detailed walk-through of our third quarter financial results, our near-term outlook and 2022 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 and EDGAR filing systems. And with that, I'll now turn the call over to Randy.

[Randall Crawford, executive]

Thank you, Adam, and good morning, everyone. We are pleased to have another opportunity to connect with the investment community and provide an update on our company, our strategy and our third quarter performance. The third quarter highlighted our continued strong operational execution across the platform. Our Utilities business achieved a robust performance, while our midstream business achieved record third quarter global export volumes. Quarter exemplified the advantages of our diversified business model, which delivered stable operating results despite some inflationary and other pressures that challenged midstream performance in the quarter, and we continue to expect to achieve our earnings guidance range for the year.

Our Utilities delivered strong results in the third quarter with normalized EBITDA increasing by $53 million on a year-over-year basis. The performance reflected the benefit of strong asset optimization activities at Washington Gas, solid performance at the retail marketing business and continued capital investments in infrastructure upgrades, including our various accelerated pipe replacement programs across the utility network. Strong asset optimization results were driven by the distinctive contractual asset position of WGL and our team's ability to execute on the ongoing demand for pipeline capacity and storage, which also help facilitate LNG exports to Europe during the quarter. These activities produce considerable positive impacts for both our customers and all the gas as approximately half of the benefit created through this activity is flowed back to customers in the form of rate really.

Our efforts related to this activity is providing strong financial benefits to our customers and therefore, helping to reduce absolute utility bills during this period of higher energy costs. Our regulated utilities continue to demonstrate stable and predictable results, delivering the critical energy that our customers need as we approach the winter demand season. Our strong multi-year growth is supported by the continued investment across our networks to improve the safety and reliability of our system, reduce long-term operating costs and deliver improved environmental outcomes, all of which better outcomes for all our stakeholders.

Our operational excellence transformation is resulting in real wins. The deployment of our pipeline replacement model in 2020 has significantly increased the effectiveness of our capital replacement program. The investments have lowered leak rates and leak backlog by 55% compared to 2020, reduced methane emissions and significantly reduced operating costs, allowing us to help offset inflationary cost pressures. We remain dedicated to upgrading our utility asset base and building resilient infrastructure focused on driving better outcomes for our customers. With the recent extension of our SAVE ARP program by the Virginia regulator who approved a USD 880 million investment through 2027, along with the significant need for pipe upgrades across our network, we'll continue to maintain the safety and reliability of our system and deliver strong rate base growth.

I am also pleased with our ongoing efforts related to the energy transition. Recently, WGL signed an MOU or an RNG development project in Virginia, which we look forward to providing additional detail in the coming period. The newly introduced legislation in Virginia for these investments will provide an ROE incentive for this type of project. Throughout this transition, we will continue to advocate for our customers to provide energy affordability. Our work is always focused on our customers' access to safe, reliable and affordable energy, which is especially important during these periods of rising energy prices like we're experiencing today.

Our Midstream business continued to deliver strong operational performance, including exporting approximately 110,000 barrels a day of combined propane and butane to Asia from our 2 export terminals during the quarter. We continue to focus on our ability to connect rising North American LPG production to premium global markets. The strong operational performance during the quarter was, however, impacted by a combination of factors, including lower realization to Canadian butane spreads and higher rail and ocean freight costs, which we believe will alleviate in the coming period. Our midstream assets have an excellent footprint in the prolific Montney Basin. And our strategy remains focused on the fact that the marginal molecule of natural gas and natural gas liquids will most profitably be exported to the key demand markets.

The growing demand for energy in Asia will be the driving force behind the midstream platform, leveraging our first-mover advantage as the first and only company with the capability to export LPGs off the West Coast to Asia through VLGCs. And we are also constructive on the medium-term development across the basin. Increasing activity by our producing customers is providing encouraging visibility to future volume growth. As a result, we expect our distinctive export platform to continue to move record volumes at LPGs to Asia. The improving forward spreads for LPGs and the opportunity to mitigate some inflationary logistics costs will support the advancement of our corporate strategy as a leading North American energy infrastructure company.

We also see numerous opportunities to use our existing infrastructure system and competencies to contribute toward reducing global carbon emissions. Our ongoing investment in capital projects will further North American energy security while also providing reliable energy transport products like Liquefied Petroleum Gas that has the potential to further human development, lower emissions and drive better societal outcomes. The AltaGas terminals off the West Coast of North America position us as the largest exporter of Canadian LPG. In addition, our midstream energy transition team has made tremendous progress this past year to evaluate opportunities to both expand our existing platform and reduce our missions while also assisting our customers in managing their carbon footprint.

We are excited to participate as these concepts materialize. In early October, AltaGas and White Cap were selected by the government of Alberta to enter into an agreement for continued evaluation on the Rolling Hills Carbon Sequestration Hub, Northwest of Calgary. Rolling Hills Hub is a prospective open access project that would be strategically located near our Harmattan Gas Plant and is surrounded by Whitecap's extensive production and geological leadership in Central Alberta. The agreement will permit AltaGas and White Cap to commence a technical evaluation in the area. And if successful, we could be awarded long-term leasing rights with the government of Alberta for the project with a potential in-service date of 2026. Rolling Hills and other proposed carbon hubs have the potential to further reduce carbon emissions in Alberta and continues Canadian Energy's industry's long-standing global leadership for environmental stewardship that we are proud to be part of.

On another strategic note, as was disclosed in late May, AltaGas announced an agreement to sell its Alaska utilities to TriSummit utilities for USD 800 million or approximately CAD 1.1 billion. Cash proceeds will be used to fund long-term growth opportunities and continue to strengthen the company's balance sheet while concentrating AltaGas utilities platform in the high-growth Eastern U.S. region. This is another example of AltaGas' proactive approach to recycle capital to fund our growth projects. We continue to maintain a strong balance sheet and financial flexibility to fund attractive return projects across our platform. Looking ahead, we remain very positive on the road ahead for AltaGas.

At the utility, we will continue to invest to reduce cost and improve the customer experience. The focus will remain on the innovation and digitization work and continuing to improve the productivity and effectiveness of the pipeline replacement capital. We continue to remain positive on the macro outlook for our Midstream platform. Given the improving forward outlook for Asia to North American LPG, the opportunity to mitigate some inflationary logistics costs and the structural growth we see in the basin over a multiyear perspective in Canada. We also remain constructive on the long-term role that Canada can play in providing global energy security. We remain committed to focusing on our execution of our long-term corporate strategy of building a diversified platform that operates long-lived energy infrastructure assets and connects customers and markets and is positioned to provide resilient and durable value for the company's stakeholders. And with that, I will turn the call over to James to review the financial results in more detail.

[D. James Harbilas, executive]

Thank you, Randy, and good morning, everyone. We achieved normalized EPS of $0.10 in the third quarter of 2022 compared to $0.01 in the same quarter last year. Normalized FFO per share was $0.60 compared to $0.59 in the third quarter of 2021, a normalized EBITDA of $233 million in the quarter compared to $239 million in the third quarter of 2021. Overall, the quarter was characterized by strong utilities results being offset by softer contribution from the midstream segment. Turning to the operating segments in more detail.

The Utilities reported normalized EBITDA of $115 million in the third quarter compared to $62 million in the same quarter last year. As Randy mentioned, utilities growth was driven by strong asset optimization activities, solid performance within the retail marketing business and continued capital investments across the network, the latter of which has been part of a multi-year asset upgrading and investment programs across our utilities. This was partially offset by higher operating costs to improve customer service levels. We continue to upgrade our critical infrastructure with the deployment of $234 million of invested capital during the third quarter that was focused on driving better long-term outcomes for our customers. This included $123 million being deployed on our various accelerated replacement programs. These programs are focused on improving the safety and reliability of the system while also delivering long-term operating cost and environmental benefits.

The level of capital deployment was in line with expectations for the third quarter, and we are well positioned to deliver on planned network upgrades, which will result in an approximate 8% year-over-year increase in rate base in 2022. Washington Gas realized normal EBITDA of $60 million in the quarter, which was materially ahead of performance last year during what is the seasonal low for gas demand across the DMV region. This was driven by the combination of asset optimization activity as well as continued ARP investments, customer growth and higher base usage, which was partially offset by increased O&M costs. SEMCO and ENSTAR combined normalized EBITDA was $25 million in the third quarter, which was relatively unchanged from the same period last year. Higher customer usage and growth was offset by higher O&M costs, while colder weather in Michigan was offset by warmer weather in Alaska.

And finally, the retail business generated $31 million in normalized EBITDA, an $8 million year-over-year increase, which included higher gas margins and favorable timing of gas was, which was partially offset by higher PJM costs. The Midstream segment reported normalized EBITDA of $108 million in the third quarter of 2022 compared to $181 million in the same quarter last year. The quarter was reflective of strong liquids and global export volumes across the platform, but was more than offset by other factors, including lower realized Asian to Canadian butane spreads, high commodity price volatility and higher rail and ocean freight costs, which included fuel charges based on the rising cost of diesel throughout the quarter and year-to-date.

Our processing facilities were positively impacted by the recovery of turnaround costs at Townsend and Gordondale, while performance at the extraction and frac facilities was very strong. Overall, throughput volumes were modestly down year-over-year due to the lost contribution from the Akin Creek facility that was sold earlier in the year. AltaGas exported a third quarter record of more than 110,000 barrels per day of cleaner burning LPGs to Asia, which was fed across 19 full and 1 partially loaded VLGC. This included approximately 63,000 barrels per day of propane being exported at RIPET and 47,000 barrels per day of combined butane and propane being exported at Ferndale. Given the strong year-to-date export volumes, AltaGas now expects to export slightly more than 100,000 barrels per day from the 2 terminals in 2022 compared to previous expectations of approximately 97,000 barrels per day.

Despite the strong volumes in the quarter, the financial results for the midstream segment fell short of our expectations, and I wanted to address the factors underpinning these results and more importantly, the actions we are taking to mitigate them in a little more detail. There were 2 major contributors to the lower profitability, lower realized Asian Canadian butane spreads and higher rail and ocean freight costs. In regard to the lower realized Asian to Canadian butane spreads as we've disclosed in the past, we came into the quarter less hedged on butane than we have been in the past. During the quarter, a few things happened. Demand for butane within Asia was softer than expected due to the lockdowns and reduced economic activity in China. That caused some cascading impacts into our traditional export markets in South Korea and Japan.

We also saw some oversupply of naphtha, which caused some substitution into certain butane demand markets. This collectively squeezed Asian Canadian butane margins. The key thing I would like to share is that we do not view these as structural headwinds, but more timing related, and we continue to have a very positive outlook for the structural advantage for LPGs off the West Coast going forward and that Asia will remain the premium global market for LPGs. We will proactively lock in that structural advantage as volumes and prices become firm for our merchant barrels heading into the 2023 contracting season. Shorter term, we will also shift our product mix to propane versus butane in Q4 as we have seen continued strength in propane pricing in 2022 and into 2023.

Finally, in terms of the ocean freight and rail, we are working through these headwinds and believe they will subside over the coming quarters. Baltic freight remains at higher levels year-over-year given increased shipping demand. We continue to take active steps to lower our costs with short-term charters like Maple Gas. We are also excited about the 2 dual fuel VLGCs to be delivered in late 2023 and early 2024 that are expected to reduce total shipping costs on select export volumes to Asia by 25% compared to a standard VLGC and reduced pricing volatility for AltaGas and its customers over the 7-year contract terms. On the rail side, we continue to work with our valued partners of CN, CP and BNSF to improve efficiencies and drive down costs, and that will be an acute focus for the team in the next couple of quarters.

In terms of hedging, approximately 57% of our global export volumes are total or hedged for the balance of the year. This includes an average FEI to North American financial hedge price of $11.91 per barrel. We also have 74% of our expected frac exposed volumes hedged for the remainder of 2022 at $37.85 per barrel. Now turning to the corporate and other segment. We reported normalized EBITDA of $10 million in the third quarter, which was a $14 million year-over-year increase driven by lower corporate expenses and lower employee incentive plan costs this year. On the corporate development front, as Randy mentioned, we continue to work closely with TriSummit to close the divestiture of our lasting utilities, which remains on track for the first quarter of 2023. We received approvals under the Hart-Scott-Rodino Act and from the committee on foreign investment in the United States.

We also continue to advance work on other required regulatory approvals, including the change of control application with the regulatory commission of Alaska. TriSummit has been an excellent partner to work with, and we are very focused on delivering the best outcomes for all our stakeholders involved when we close the transaction. As Randy mentioned, we also announced the close -- that we closed the remaining 26% equity ownership of Petro Gas from Items in the quarter, and we now own 100% of the platform. Transaction was principally funded with recycled capital from the recent sale of our non-operated interest in the Eaten Creek gas processing facility as well as modest draws of short-term debt from the company's existing credit facilities.

While Idemitsu is no longer an equity investor in Petrogas, they remain a valued partner to our company. They're an important global exports offtake customer through the Astomos Energy joint venture. We and Idemitsu are also continuing to evaluate future opportunities and collaborate on prospective energy transition projects as both of our organizations pursue various lower carbon initiatives over the long term. We look forward to continuing to work alongside of Mitsu and remaining long-term partners as we have been for nearly a decade. Despite a softer third quarter, we continue to expect to achieve guidance ranges that were previously disclosed at our Investor Day in December 2021 and our 2022 invested capital and of approximately $955 million is unchanged. And with that, I will turn it over to the operator to open the call for questions.

[Operator]

[Operator Instructions] Your first question comes from Dariusz Lozny from the Bank of America.

[Dariusz Lozny, analyst]

So the first one, I just wanted to talk about export volumes a little bit. You guys came in higher than your annualized guidance for the quarter, albeit in the context of softer market conditions. Can you maybe just talk about what kind of flex do you have in the ability to perhaps if you're seeing softer conditions export maybe more towards the -- your original target, which was, I think, 97,000 barrels per day or basically just kind of turn that lever to respond to market conditions on the export side, if you could.

[Randall Crawford, executive]

Thank you, Dariusz. This is Randy. I appreciate the question. And James alluded to this in his comments in terms of the flexibility and optionality to move between products that we have as we build this core competency. And I think that is something that the team is always focused on to generate real value going forward. James, Randy, do you want to go ahead and more.

[Randy Toone, executive]

It's Randy Toone. At Ferndale, we do have the ability to push more propane and butane and that's our plan for Q4, as James mentioned. So propane margins are very strong still. So we are going to move less barrels in Q4 than, say, Q2 and Q3, and we're going to move more propane and butane because it's a better spread. And I'll just add, Dariusz, obviously, if you look historically, our strongest volumes typically come in Q2 and Q3 as we take delivery of butane from some of the refineries in and around Ferndale. And then Randy touched on it and we've disclosed it in our press release under the hedging table. We expect to be at about 98,000 barrels for Q4, and that will be heavily weighted to propane as opposed to butane. So we're only expecting about 8,000 barrels a day of merchant butane during the quarter versus those volumes...

[D. James Harbilas, executive]

And I'll just add, Dariusz, obviously, if you look historically, our strongest volumes typically come in Q2 and Q3 as we take delivery of butane from some of the refineries in and around Ferndale. And then Randy touched on it and we've disclosed it in our press release under the hedging table. We expect to be at about 98,000 barrels for Q4, and that will be heavily weighted to propane as opposed to butane. So we're only expecting about 8,000 barrels a day of merchant butane during the quarter versus those volumes...

[Dariusz Lozny, analyst]

Got it. Appreciate that. Thank you for the color. One more, maybe more high level. Can you discuss that we're obviously in a higher interest rate environment here. Can you discuss, number one, just at the ALA level sensitivity to moves in interest rates relative to your interest expense. Any significant refinancings coming up? And whether the current high interest rate environment maybe changes your thinking about monetizing some noncore assets, perhaps accelerating some of those that might be in the plant in order to delever faster and reduce that interest expense burden.

[D. James Harbilas, executive]

It's James here, again, Dariusz. So, I mean, when we look at our maturity profile, we want to stress that we've got a lot of liquidity that's available on our short-term credit facilities. We've pretty much exited the quarter with $3.1 billion of available liquidity. In terms of near-term maturities, we've got only at the ALA level about $500 million that's coming due December 22 -- sorry, December of 2022, and then we've got another $300 million that comes due in June of 2023. We can easily accommodate those maturities on the line. And then obviously, with the ENSTAR sale expected to close in Q1, we can basically extinguish those liabilities and not have to access the MTN market in this higher interest rate environment.

So I think the team has done a great job to give us some of that flexibility to reduce our refinancing risk during a period of high interest rates. And we've also been pretty active in setting up some term loans, 2-year term loans that are something that we can draw below our credit facilities currently, which gives us some additional flexibility. So we can sit on the sidelines here and wait out a higher interest rate environment and have some flexibility and optionality in terms of when we access those markets.

[Operator]

Next question comes from Jeremy Tonet from JPMorgan.

[Jeremy Tonet, analyst]

I just wanted to dive in a little bit more on, I guess, the pressures on export margin and kind of where rail and shipping rates are now versus where they were in the second quarter and I guess, expectations for 2023, how that shakes out? And just how much of 2023, I guess, is locked in at this point versus open exposure to changing rates there?

[D. James Harbilas, executive]

Jeremy, it's James here. So I mean, if you look at the prompt for Baltic freight in 2022, we're at about $7.50 a barrel. If you look at the forward curve, that drops down to about $4.79 for 2023, and we've been pretty active in trying to hedge that and lock it in. So we're about 83% hedged heading into 2023 on Baltic freight with respect to our expected volumes. So I think we're very well protected versus the prom. So we do -- we have taken proactive measures to mitigate that impact heading into future quarters.

[Jeremy Tonet, analyst]

Got it. And then just as we think forward about kind of the growth projects, as you talked about there, like RIPET expansion, just wondering if you could expand a bit on financing strategy there going forward as we have higher rates.

[Randall Crawford, executive]

I'll let James comment on the financing strategy. But we are optimistic, as you can see with the amount of volumes that we're moving and the demand in Asia, and we have some robust discussions going on with the demand pull market. So as we look toward expanding those assets and rip it into the future, the key to that is going to be locking in some of those commitments as well and we're optimistic about that. James?

[D. James Harbilas, executive]

Yes. I mean in terms of financing that, we mentioned the ENSTAR sale that is going to generate roughly $1.1 billion of proceeds. As Randy mentioned, some of that will be allocated to debt repayment, and we'll take our pro forma leverage down to under 5x when that closes. So we've created some balance sheet capacity to be able to fund our portion of any kind of RIPET expansion during the construction period. And obviously, once it's operational, to bring on incremental EBITDA that will keep our leverage ratios manageable. But we're also obviously partnering with Vopak on this potential expansion. So we -- that's how we're derisking some of the financing as well. So we feel that we've done a lot of work with the balance sheet to give us dry powder to be able to finance any kind of expansion once we're ready to go forward with it.

[Jeremy Tonet, analyst]

Got it. And just one last one, circling back to the first question. Thank you for the data points on shipping, but with regards to rail, just any thoughts, I guess, on the shape of the cost going forward if that's coming in or expanding and what's locked in for 2023 at this point?

[Randall Crawford, executive]

I'll let Randy tune comment on that. I'd say, overall, we continue to work with our partners, CN and others. And there's a lot of this that is focused on really optimizing on both sides in terms of making sure that we're as efficient as possible as we move our rail going forward. Randy, I'll let you go ahead...

[Randy Toone, executive]

Yes. I think Randy said, we continue to work with our third-party service providers on rates. And we always optimize our fleet to minimize our lease costs for railcars. And for us to go ahead and say, with a bigger expansion, we definitely need to see lower rates from our service providers. So we are working hard to get those in mind.

[Randall Crawford, executive]

And I think, Jeremy, in terms of scale here in the quantities that we're moving, that's going to do as we work with our partners, there's a good bit of scale here as we drive down costs and move more volumes. And so working with our partners, having flexibility on 2 rail networks as well is going to be critical in the future in through 2023. So we're working very diligently in that regard.

[Operator]

Your next question comes from Linda Ezergailis from TD Securities.

[Linda Ezergailis, analyst]

I'm wondering if you can update us on your path to achieving your allowed ROE. Where do you see the gap being, when do you expect to achieve it? And then looking forward, as interest beating elevated, how do you see your allowed ROE shifting over time? If you can provide any context to that, that would be appreciated.

[D. James Harbilas, executive]

Linda, it's James here. I'll start with your last question first. I mean, obviously, we've been -- before this current inflection point in interest rates going up, we were in a period where interest rates had been declining, and we saw ROEs be relatively sticky despite that and consistently above the 9% range. So we wouldn't expect a high degree of correlation with respect to allowed ROEs now in a rising interest rate environment. We do expect them to stay fairly sticky. In terms of your broader point on ROEs, obviously, the teams down in the utilities have done a great job trying to close that gap. I mean, at SEMCO and ENSTAR, we've been consistently at our allowed ROEs at WGL. We've taken active strides to invest in the system with respect to ARP to drive that down, and we've been very, very active on the rate case front, and this year is no different.

So obviously, the DC rate case that's been filed as well as the Virginia rate case that's been filed is going to update rates with respect to our current structure, and we'll to continue to close that gap. But there's still some work to do there, especially in D.C. where we've been out of the hearing room since 2016 and have had to file 2 rate case filings just to try to catch up on test years here, right? So in D.C., we're still in a 2-year 2019 test year. So there could be additional filings to try to reflect the investments we've made in that system to service our customers and the ability for us to fully earn our allowed return.

[Randall Crawford, executive]

And it I'll just add to James, this is -- these 2 rate cases, the Virginia rates will go into effect subject to refund in this quarter. And the DC rates once result will be going into effect in 2023. So those are key drivers, right. As we put those in, plus the efficiencies in what Blue's team is working on overall. So I think those are going to help us progress as we've been continuing to do over the last few years is driving and covering our allowed return on the current investments and continuing to move up the base as we progress going forward. So thank you for the question.

[Linda Ezergailis, analyst]

And on a separate note, maybe you can help us understand a little bit more your opportunity with Whitecap for the Rolling Hills Carbon Sequestration Hub. What sort of milestones at what pace needs to be achieved to get to an FID to be in service by 2026? And maybe you can also comment on the bookends of magnitude of investments and your view on what you and your current partner bring to the table and would potentially another partner bring anything incremental to the table as well to bolster the value proposition for this project.

[Randy Toone, executive]

It's Randy Toone here. It's early days for this project and -- but we are quite proud to team up with White Cap who have -- they're the expert in this field. They already have an existing CCUS asset, and they've been awarded other projects along the way. So we are going to focus on the geotechnical work, and that's what we've been awarded right now is to derisk the poor space. And we do believe that the port space near Harmattan is ideal for carbon, and that's what we're going to be working on over the next 6 to 12 months is just making sure that the port space is capable. And it is really close to Harmattan, which is our largest emitting source. So it is -- it will be helpful for us to reduce our carbon footprint for Harmattan as well...

[Operator]

Your next question comes from Rob Hope from Scotia Bank.

[Robert Hope, analyst]

I want to circle back on the global export margins. Just want to get a sense of how you're thinking about the risk profile of the business. We saw you entered Q3 with about 75% of volumes hedged there, but margins were weak. Can you give us a better understanding of whether or not you had shipping locked in for Q3 or the hedging in 2023 is a new phenomenon? And then I guess, secondly, as you move forward, could you see more emphasis on locking in kind of the transport as well as the margins?

[Randall Crawford, executive]

I'll let James give in some of the specifics. But yes, certainly, the increasing spreads in the fundamentals are such that we continue to lock in those margins as we move forward. I'll just make a comment on generally, like derisking the Midstream and the export is a top priority to us. And I talked a bit about the demand market and the producers and tolling. So in the long term, we'll be heading there in terms of the derisking all of the aspects of the cost structures, we're active in that role, and I'll let James talk a little bit about that.

[D. James Harbilas, executive]

Yes, Rob, look, I mean in terms of going forward, the proactive steps that we're taking to improve margins are product mix and shifting that product mix. If you look at where we've been year-to-date at the end of September in terms of product mix, we've been 27% of our exports have been butane versus 73% propane, right? And the fact that we've seen pressure year-over-year on those butane margins in Q4, we're going to shift that and drop that percentage, inclusive of butane tolls down to about 12% to 13% and prioritize propane. So that's how we're going to improve the margin profile going forward, and we can potentially do that into Q1 of 2023 as well. In terms of freight, we had hedged some of that in the past. We're being much more proactive and much more aggressive on hedging that going forward and locking in lower rates that we see in the curve out into 2023 relative to where the prompt month is right now.

[Robert Hope, analyst]

I appreciate that. And then maybe just a follow-up question on tolling. How are discussions going with customers there? Are they more willing to come up the curve and understand the benefits of shipping to Asia? Or are they more focused on kind of commodity pricing and the overall challenges in that market?

[Randall Crawford, executive]

Rob, I think -- Randy. Thanks for the question. I think the discussions are going reasonably well. There's increased interest producers, aggregators. But I think they want to participate on the upside and the direct access to Asian pricing. In the demand market as well is looking at that. So I think you'll see going forward a model where we partner in terms of sharing some of those upsides as well as putting in the tolling rate. So I think those discussions are active and we're anticipating progress as we move forward in the coming months.

[Operator]

Your next question comes from Matthew Weekes from iA Capital Markets.

[Matthew Weekes, analyst]

You talked about kind of an improving outlook for export margins based on the forward curve. And I'm just wondering whether that's more driven by sort of higher agent prices on the demand side or whether it's more coming on the supply side? And sort of if there's cascading effects from China and intermittent lockdowns therapy, if you see that kind of continue and more lockdowns, how would you see that impacting the forward outlook for export margins?

[Randy Toone, executive]

Yes, Randy Toone here. We've already seen like the effects of winter in Asia, and so that's where we're seeing a lot of demand in the pickup. And so you can see that with the FEI propane spreads right now. And we see that continuing right through Q1 in -- starting in Q2 is the new supply year for propane and butane here in Western Canada, and we do see a significant amount of LPG being produced without demand. So we do see there'll be a strong case for getting those barrels exported with our customers.

[Operator]

Your next question comes from Andrew Kuske from Crédit Suisse.

[Andrew Kuske, analyst]

It's probably a Randy question. And I guess just on the Canadian Midstream business, putting the export business for the moment, if you look at your value chain, what do you think is missing in the portfolio? And do you think there's some opportunities to really expand by way of partnerships into maybe greater frac capacity, enhancing the logistics efforts or storage. Any color along that line would be appreciated.

[Randall Crawford, executive]

Thanks, Andrew. I'll go ahead and start and let Randy add to that. But yes, we see significant opportunities with our logistics partners to continue to control costs, optimize rail schedules, debottlenecking capacity -- and so yes, I think there's a tremendous amount of opportunity for us to continue to work together going forward. And I think you'll see the team doing that because at the end of the day, when you move in this quantity of product, logistics is going to be the key driver for optimizing capacity as well as reducing costs. So being the least cost operator and using our scale is going to be a key driver going forward.

[Randy Toone, executive]

It's Randy Toone here. On the frac, we do -- right now, our Northeast BC fractionator is full, and so we are looking at a potential small expansion on that frac. And as Randy mentioned, we are looking at partnering with -- on the logistics side to lower our long-term logistics costs. And like James mentioned, we have partnered with Vopak to continue to look at LPG exports. So we are partnering on a number of fronts, but largely focused on frac, logistics and exports.

[Andrew Kuske, analyst]

Maybe when you look at all those things in combination, do you see greater opportunities to bulk up and partner at the Ford itself because you've got the relationship with ATCO. There's another player in the market who's looking for some strategic capital or partner out of potential frac expansion. Just how do you think of the Ford specifically?

[Randall Crawford, executive]

Yes, I think that's -- it's a good point. We see that is really creating a hub out of the corp LPGs and working together as the frac capacity gets expanded because it's going to be necessary. We believe in the long run in the most valued market is clearly going to move the LPGs to Asia. So yes, we think the Ford is going to be a big part of our continued expansion to our long-term goal of 200,000-plus barrels a day out of the basin.

[Andrew Kuske, analyst]

And then finally, if I can just squeeze one more in, it's probably for James, is just how do you think about the hedging program on a go-forward basis? Any changes? Or are you keeping it basically the same?

[D. James Harbilas, executive]

No, I touched on that. Thanks, Andrew. I touched on it in our prepared remarks. Obviously, we've been much more active in terms of hedging out into 2023 on Baltic freight, but we've also got about 42% of our merchant barrels and tolling barrels locked in for 2023 already heavily weighted to Q2 and Q3 in terms of those hedges, which is where we see some softness in FEI to Mont Belvieu pricing. So we have been very, very proactive and will continue to be here as we continue to get closer to the recontracting year that Randy Toone mentioned on April 1.

[Operator]

Your next question comes from Robert Kwan from RBC Capital Markets.

[Robert Kwan, analyst]

First, I just wanted to dig into the numbers and on the global exports and the $43 million net that you highlighted there. Can you quantify what the -- the impact, though, was for rail on one hand and then ocean freight on the second side of things. How you see that improving what magnitude, whether it's this quarter and into 2023. And then just taking a step back, as you think about 2023, I know that you've got formal guidance coming up. But can you just talk about the headwinds and tailwinds outside of those factors, FX would be a tailwind in interest rates, probably a headwind. But are there other things to be thinking about into 2023?

[D. James Harbilas, executive]

Robert, it's James here. I'll start with your Baltic freight and rail question. I mean if we look at it in terms of the quarter, Baltic Freight was -- year-over-year was probably around $10 million to $11 million higher net of our hedges that were in place and rail was about $10 million to $11 million higher inclusive of the fuel surcharge. I touched on it in terms of our prepared remarks and some of the earlier answers that we've been very, very active trying to lock in the lower rates that we're seeing on Baltic freight already into 2023 relative to 2022. So we do expect that to improve quite dramatically as we head into the new year. Just to put it into perspective, the prop month on Baltic freight is about 750 for 2022 and into 2023, it's 4.79.

So we do see some considerable improvement there. And in terms of headwinds and tailwinds, I mean, you touched on FX, but -- if I look out to the balance of the year, and we expect to be in our guidance range, obviously, the headwinds that we have been experiencing all year has been compressed butane pricing, which we've taken active steps now to mitigate for Q4 by reducing our export volumes on butane considerably. We're cutting them in half relative to where they've been year-to-date in terms of our overall volumes. And then on the tailwind side, we're going to take advantage of stronger C3 pricing in Q4 and obviously into Q1 of 2023 and the balance of that year. And then we expect FX to be a material tailwind at 135 versus where we set our guidance when we did that, we were at $1.26. So that's going to be a material tailwind as well. And then we do see some continued strength within the utilities on the AO book early in Q4 and some strong results within retail. So when we take all the puts and takes, that's why we feel comfortable that we're going to achieve our guidance range and improve results in Q4.

[Robert Kwan, analyst]

Got it. So just tapping with ENSTAR, which is still outstanding, you've done a lot of work both highlighting value of assets and getting that debt down. I guess as we look forward here, particularly just with the way the share prices performed, can you just refresh how you're thinking about other value-maximizing options, other monetizations of size as well as what are the current thoughts on a larger structural change?

[Randall Crawford, executive]

Robert, this is Randy. So we can -- as we said in the past, and we continue to believe that our diversified utilities and midstream strategy is the right one and it continues to deliver value to our shareholders. And you know our primary focus is always about creating and generating shareholder value and our management team has think has done an excellent job of demonstrating that. So at this point, we think we're at the right on it, but we're operating from a position of strength, and we'll continue to look forward and maximize value for shareholders. But at this point, we're very comfortable with the approach in our diversified model.

[D. James Harbilas, executive]

Sorry, I was just going to add to Randy's comments, I mean, in terms of what we can possibly do in terms of other capital recycling opportunities. We've been pretty consistent with that. I mean look, -- the work that we did with ENSTAR and the anticipated close in Q1 has given us some additional flexibility and optionality, and we can continue to be patient with MVP. And once that we get a clear line of sight in terms of in-service and completion date there, we can try to maximize value. So there are still additional levers to pull, but we're not dependent on MVP to be able to fund the organic growth that we see on the platform. And we do have the ability to be patient with MVP to maximize value.

[Robert Kwan, analyst]

Got it. Just to finish here on guidance. You have an accounting change in the quarter. It's relatively meaningful. And so would you have been able to reiterate your guidance ranges, absent of the accounting adjustment?

[D. James Harbilas, executive]

Well, I don't -- we shouldn't characterize it as an accounting adjustment. This is obviously with respect to our normalization policy. So just to provide a little bit of color around that. When we bought Petro Gas, we obviously had to revalue the assets and liabilities with respect to that acquisition. And we had to set up some contingent liabilities for commercial disputes and some commercial matters that we had to work through, and we've been successful in mitigating some of those throughout 2022, and they're related to operations. So they're recorded in our GAAP numbers, and we feel it makes sense to leave them in our normalizations or to leave them in our normalized EBITDA. And it is something that will recur. So we do expect some additional mitigation to take place in the balance of this year and into 2023 as we continue to work through some of these liabilities and extinguish them and put them to bed.

[Robert Kwan, analyst]

Okay. But if I'm interpreting it right, it's lifted year-to-date EBITDA by $30 million and about $0.06 on earnings. So are you saying that, that actually reverses out and pushes down in Q4 by an equal amount? Or again, coming back to the original question, could you reiterate guidance without that change?

[D. James Harbilas, executive]

So the amount that it impacted EBITDA was about $26 million year-to-date, and we would be able to reiterate guidance without that amount, yes. And just to clarify, it doesn't reverse in Q4. That's not what I'm messaging. I'm saying that there's additional liabilities and commercial disputes that we can settle that will give rise to additional EBITDA going forward.

[Operator]

Your next question comes from Robert Catellier from CIBC Capital Markets.

[Robert Catellier, analyst]

You've answered the majority of my questions at this point. But I wondered just on the transportation cost breakdown you gave there, James, that how much of the higher costs were related to things you can control? Or -- and then how much was related to things you can't control like fuel surcharges? And if you don't have it handy, we could take that offline, but I'm just...

[D. James Harbilas, executive]

I do. I do, Robert. I mean I can give you an order of magnitude here for the quarter, right? I mean for the quarter, the fuel surcharges were related to increasing cost of diesel about $6 million to $7 million of the rail increases that I talked about. I mean going forward, we are going to take active steps to control that as well by basically putting in hedges in place as an attempt to control that cost. For the year that just the fuel surcharge was roughly about $12 million to $13 million, but the team could break that down a little further after the call.

[Robert Catellier, analyst]

Yes. That's helpful color. And then my last question has to do with the Rolling Hills carbon sequestration hub. I'm just wondering if you can describe what you think the company's relative advantages in developing a hub look that, specifically, what opportunities there to leverage some of your assets or those of your partner what the interplay might be with Petro Gas. I asked the question because, obviously, there's considerable other activity trying to develop similar hubs. So I'd just like to know how you -- where you see having a relative advantage. And then how much you might have to spend to that evaluation process?

[Randy Toone, executive]

Robert, it's Randy Toone here. We feel that Harmattan is advantaged because it is a large emitter. We've teamed up with White Cap who are experts in this field to evaluate the port space. And when we've looked at this port space, it looks very ideal for carbon. So proximity to a mission source and the idea of the port space looking attractive and also the partnering with Whitecap. We feel that is this is a very advantaged project. To do the valuation process go forward, it's not material dollars and some of it's internal folks on both sides. So it's -- we don't see it as a significant amount of money.

[Operator]

Thank you. The last question comes from Patrick Kenny from National Bank.

[Patrick Kenny, analyst]

I just wanted to ask on the 5% to 7% dividend growth guidance. And I know you've reiterated full year cash flow guidance. But as you work through the logistical cost pressures here on the midstream side, can you just remind us how much of the decision to come in at the low end versus the high end of the dividend growth range really depends on Midstream performance?

[D. James Harbilas, executive]

Patrick, it's James here. Look, obviously, we revisit our dividend and where we're going to set that every year kind of in line with our annual business plan and guidance for the following year. But when we rolled out the 5% to 7% guidance range with the midpoint being 6%, obviously, we clearly articulated that we can fund that dividend just through rate base growth and keep our payout ratio constant, right. So if midstream continues to grow, then we would get a declining payout ratio if you use a 6% midpoint in the dividend, and we still feel comfortable with that narrative around the dividend. So we will obviously provide any views that we have on the dividend in line with when we roll out 2023 guidance, but just wanted to reiterate some of the philosophy that went into setting that range given the growth that we see on both platforms.

[Randall Crawford, executive]

And Patrick, this is Randy. And always so that's a board's decision. But I mean, from our standpoint, continuing to affirm guidance, the strong performance of the utility and the short-term nature of these Midstream short-term challenges, we're still confident in our long-term business strategy and the Board will make that decision here shortly.

[Patrick Kenny, analyst]

Got it. And then just to come back to the various levers that you can pull on the balance sheet. You mentioned MVP, James. But any update on how you guys are thinking about life now with, I think, just over a year left on the contract. Are you looking at extension opportunities there or perhaps looking to explore price discovery process sometime in the new year.

[D. James Harbilas, executive]

No. Look, I mean, I'll go back to the comments I made earlier. I think we've done some great work with the balance sheet, and we've put ourselves in a position where we can be patient. You're right that we are now going to be moving into a period of trying to extend that contract. And we feel confident, just given the performance of life and how important it is to California's power needs that there's a continued need for -- to dispatch that asset, and it's performed extremely well here over the last 3 years to help them through some crucial times from an energy demand standpoint. So I think that the construct or the macro is setting up well for constructive discussions on an extension of that. So we're in no rush to sell it. Like I said, we can -- generate some very, very stable EBITDA for us. And we've got other non-core assets that we can potentially monetize to meet our funding needs going forward.

[Operator]

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

[Adam McKnight, executive]

Thanks, Jeff, and thank you, everyone, once again for joining our call today and for your interest in AltaGas. That concludes our call this morning. I hope everyone enjoys the rest of their day. And you may now disconnect your phone lines.