Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the AltaGas Second Quarter 2022 Financial Results Conference Call. My name is Pam, and I will be your conference operator today. 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 the operator.
After the speaker's remarks, there will be a question-and-answer session. As a reminder, this call is being broadcast live on the Internet and recorded. I would now like to turn the conference call over to Jon Morrison, Senior Vice President, Investor Relations and Corporate Development. Please go ahead, Mr. Morrison.
Thanks, Pam, and good morning everyone. Thanks for joining us for AltaGas's second 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 Operations, and Blue Jenkins, Executive Vice President and President of our Utilities business.
We'll proceed on the basis that everyone's taken the opportunity to review the press release and our second quarter results. Similar to previous quarters, we've published an earnings summary presentation that you can find on our website. The presentation walks through the quarter and highlights some of the key year-over-year variances and non-recurring items that we thought would be useful for the market to understand.
As always, today's prepared remarks will be followed by an analyst question-and-answer period. As for the structure of the call, we'll start with Randy Crawford providing some comments on our financial performance and progress on key strategic initiatives, followed by James Harbilas, providing a more detailed walkthrough of our second quarter results, our near-term outlook in 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 be referring to forward-looking information on today's call. The information is subject to certain risks and uncertainties, as outlined in the forward-looking information disclosures 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. With that, I'll turn it over to Randy.
Thank you, Jon, and good morning, everyone. We are pleased to announce that AltaGas delivered solid second quarter results with normalized EBITDA up 7% year-over-year in the quarter, while we continue to execute on our strategic plan. The acquisition of the remaining equity ownership of Petrogas and our agreement to divest our Alaskan utilities enhances our energy infrastructure platform and positions AltaGas for continued long-term value creation.
Our ability to recycle capital into strategic growth opportunities and further improve our balance sheet will ensure that AltaGas is well-positioned to deliver sustainable future value for our stakeholders. Second quarter results were underpinned by strong operations in both our midstream and utility segments. Utilities normalized EBITDA was up 17% year-over-year, and we continued to benefit from the robust capital investments we are making in our network through our various ARP programs.
We remain dedicated to upgrading our asset base to build resilient infrastructure that is focused on improving safety and reliability, reducing emissions, and lowering operating costs, which are all focused on driving better outcomes for our customers. Our Virginia regulator approved a five year extension to our SAVE ARP plan, which provides nearly $880 million of accelerated investments through 2027. This is our most recent example of this commitment.
When coupled with our approved ARP programs in our D.C., Maryland, and Michigan jurisdictions, AltaGas has regulatory approval of $1.05 billion of ARP investments into our utilities through the next five years to ensure we continue to provide safe and reliable service. We contemplate future extensions of the ARP programs in these jurisdictions and will increase the spending commitment. We remain committed to operate with a high degree of capital and cost discipline.
That has been our focus in the past three years. While we remain active in keeping our rates up to date and reflective of the current operating environment, to that end, in June, we filed a rate case in Virginia seeking a $48 million increase in annual revenues to reflect the impact of increasing cost of capital and plant investments above depreciation, not included in the SAVE ARP.
This filing, along with our D.C. rate case filed in April and the new rates in Maryland that became effective earlier this year, will ensure that our rates reflect the appropriate return on our investment in our critical infrastructure. By investing in our system and ensuring our rates remain current, we are well-positioned to navigate the current inflationary environment through a modern and efficient platform while driving the best customer and stakeholder outcomes.
As we execute this strategy, we believe that we will continue to deliver steady earnings per share and FFO per share growth for our shareholders. In our midstream segment, we continue to capitalize on the tremendous opportunity to export cleaner burning LPGs to Asia from Western Canada and the Northwestern U.S. to meet the rising demand for lower carbon LPGs. In the second quarter, we shipped approximately 111,000 barrels a day of propane and butane to Asia, representing a 26% increase compared to last quarter and another record for our company.
In a span of just over three years, we have taken our global export business from zero to exporting over 100,000 barrels of North American LPGs to premium markets in Asia, which now represent more than 10% of Japan's annual propane and South Korea's total LPG imports. Well, operationally, we excelled in the quarter.
The financial performance of the global export platform was slightly behind our expectations due to hedging timing, certain inflationary pressures, and other headwinds. The good news here is that our push to significantly increase volumes has helped us identify areas of manageable improvement in our value chain, such as the rail and ocean logistics, and our supply acquisition and hedging strategies.
Sustainable improvements in these areas, coupled with our demonstrated ability to increase volumes from our export platform, provide AltaGas the opportunity to further enhance our financial results as we continue to connect our upstream and downstream customers for the best industry outcomes. I'm pleased with our achievements this quarter, particularly in the context of global energy crisis as the world comes to terms with the energy shortage and the importance of securing access to reliable, safe, affordable, and responsible produced energy to power everyday life.
Looking forward, the strategic initiatives we accomplished in the first half of 2022 have positioned AltaGas with the enviable ability to simultaneously advance the significant pipeline of growth opportunities in front of us while reducing our leverage ratios and providing steady and consistent dividend growth for our shareholders. I'm proud of the role AltaGas plays in providing access to affordable and diverse energy sources, both domestically, within North America, and to global markets. I will turn the call over to James to review the financial results in more detail.
Thank you, Randy, and good morning, everyone. During the second quarter of 2022, AltaGas achieved normalized EBITDA of CAD 246 million compared to CAD 230 million in the same quarter last year, representing a 7% year-over-year increase. Normalized FFO per share of CAD 0.60 in the second quarter of 2022 compared to CAD 0.56 in the second quarter of 2021, representing an 8% year-over-year increase and continues to provide the foundation to fund organic growth and returns of capital to shareholders.
Normalized EPS of CAD 0.08 in the second quarter of 2022 was consistent with the same quarter of last year. Digging into our segmented results for the quarter, normalized EBITDA in the midstream segment was CAD 133 million compared to CAD 142 million in the second quarter of 2021. Our global export platform achieved record volumes during the second quarter, shipping approximately 111,000 barrels per day of combined propane and butane to Asia, spread across 18 ships and one partially loaded ship.
This represented a 23% year-over-year increase in volumes relative to the second quarter of 2021, with RIPET exporting approximately 64,000 barrels of propane on 10 full and one partially loaded ship, while Ferndale exported approximately 47,000 barrels of combined butane and propane on eight ships. Record export volumes continue to be driven by strong offtake demand in Asia.
Strong global export volume growth was offset by a number of factors, including a CAD 20 million negative impact from hedge timing on global export volumes that were loaded at the end of the first quarter, with the corresponding hedge loss not recognized until delivery in the second quarter of 2022.
Lower margins on tighter North American to Far East spreads, particularly butane volumes, and increased logistic costs due to higher rail and ocean freight. Of note, the tighter butane spreads in the second quarter was principally a function of North American pricing for butane rising along with crude prices, while Far East butane prices didn't lift to the same extent as we were in the shoulder season for LPG demand in Asia in the spring.
As we move towards the fall, we would expect Far East and North American spreads to widen in order for the Far East market to continue to attract incremental barrels from global markets to meet local market demand, which is in line with the traditional seasonality. Inlet gas volumes at our facilities were slightly lower year-over-year as a result of four scheduled turnarounds in the quarter, including Harmattan, Townsend, Gordondale, and North Pine.
We continue to have a healthy hedge position with our midstream platform with approximately 51% of global export volumes sold or hedged for the balance of the year. This includes an average FEI to North American financial hedge price of $12.66 per barrel. We also have 75% of our expected frac-exposed volumes hedged for the remainder of 2022 at $34.68 per barrel.
Our utility results reflected the normal seasonal slowdown in natural gas demand that is associated with the spring and summer months. Normalized utilities EBITDA was CAD 116 million in the second quarter of 2022 compared to CAD 99 million in the comparable quarter of last year. The 17% year-over-year increase was driven by continued rate-based growth through ongoing ARP investments, customer growth, strong retail contribution, and higher asset optimization in the quarter, partially offset by increased operating costs.
Washington Gas reported normalized EBITDA of CAD 65 million in the second quarter, up 16% year-over-year, driven mainly by continued ARP investments and customer growth, the impact of the Maryland rate case, as well as asset optimization and higher base usage, partially offset by increased O&M costs.
SEMCO and ENSTAR's combined normalized EBITDA was CAD 35 million in the second quarter, up CAD 2 million from the same period last year, driven by customer usage and growth, partially offset by higher O&M costs. As a reminder, we expect the sale of our Alaskan utilities to close in the first quarter of 2023 and therefore expect ongoing contributions for the remainder of the year.
Finally, the retail business generated CAD 16 million in normalized EBITDA, up CAD 6 million year-over-year, which included stronger optimization margins and lower than budgeted gas costs, which was partially offset by higher PJM costs. Some of this strong performance is expected to be reduced in future quarters as a portion of the outperformance is timing related.
The corporate and other segment reported normalized EBITDA loss of $3 million in the second quarter of 2022 compared to an $11 million loss in the same quarter of 2021. The $8 million year-over-year increase in normalized EBITDA was mainly driven by lower corporate expenses, primarily related to AltaGas's strong operating performance and higher employee incentive plan costs associated with the second quarter of 2021, driven by AltaGas's rising share price last year.
Year-to-date, AltaGas has experienced many of the same inflationary pressures that are being seen across the global economy. Although the company is well protected against these inflationary pressures through its cost of service operating model in the utilities and through take-or-pay and fee-for-service contracts within its midstream operations, AltaGas has an acute focus on judiciously managing all controllable costs to protect its customers and deliver the lowest cost possible.
As Randy mentioned, we have had a very active first half of the year in terms of corporate development activity as we announced plans to divest our Alaskan utilities, and we acquired the remaining equity interest in Petrogas from Idemitsu. We believe both the transactions will drive long-term value creation for our stakeholders and allow AltaGas to continue to achieve the corporate objectives that we have set for ourselves.
Looking ahead, we continue to focus on our corporate strategy, connecting customers and markets, and delivering durable and growing EPS and FFO per share while lowering leverage ratios over time. We are maintaining our 2022 guidance ranges, including normalized EPS of CAD 1.80-CAD 1.95 a share, normalized EBITDA guidance of CAD 1.5 billion-CAD 1.55 billion, and a 2022 capital plan of approximately CAD 995 million. With that, I will turn it over to the operator to open the call for questions.
Thank you. Ladies and gentlemen, we will now conduct the analyst question-and-answer session. If you'd like to ask a question, please press the number one, or please press star, then the number one on your telephone keypad. If you would like to withdraw your question, please press Star two. There will be a brief pause while we compile the Q&A roster. Your first question comes from Dariusz Lozny with Bank of America. Please go ahead.
Hey, good morning, and thank you for taking my question. Just wanted to start off on the acquisition of the remaining stake in Petrogas. Can you maybe just talk a little bit about the timing, sort of how the purchase came to be? Did your partner approach you about acquiring the remaining stake, to the extent that you can comment? Also if you could potentially comment on the difference in valuation relative to the majority stake that you purchased back in 2020.
Hey, good morning. Thank you for the question. This is Randy. Just a couple of comments and appreciate the question. You know, from our perspective, it was a good purchase and we believe in the assets and its capabilities and really the value proposition and we wanted to have more, you know, exposure to it, you know, for these reasons. Our partner had looked at monetizing that position, and that's basically how that came about.
You know, but from our perspective, you know, having complete control, streamlining the corporate process, and as I said, we believe in the asset because of its position on the West Coast and the fundamentals and optionality that it provides. You know, from our perspective, you know, acquiring that remaining stake is just gonna enhance the flexibility, optimization of the LPG export growth. You know, from that standpoint, it felt it was a good purchase and the timing fit really well.
Dariusz, it's James here. From a valuation standpoint, I mean, obviously the initial interest that we acquired was a controlling interest and that's what gave us operational control over that facility when we acquired the SAM Holdings, the founder's original interest. Obviously Idemitsu's was a minority interest with obviously limited governance rights. That factored into the valuation difference between the two stakes as well.
Got it. That's helpful. Thank you very much. One more if I can, maybe just pivoting over to the utility. It looks like the D.C. City Council has passed a resolution that would limit commercial gas hookups in new buildings later in the decade. It's not an immediate impact. But just curious, I mean, it doesn't seem like it'll be a large or certainly a near-term impact on numbers, but just how are you thinking about that just kind of long-term strategically as you think about deploying capital and growing your rate base across the WGL footprint?
Yeah. Hi, Dariusz. It's Blue. Thanks for the question. Yeah. As you know, if you've had a chance to look at it, the bill requires the mayor to issue regulations that update commercial buildings with energy conservation codes by December of 2026. We still got a ways out. It also covers remodels for buildings over 50,000 sq ft, as long as it's more than 50% of the prior value of the building. It's kind of a fairly narrowly scripted.
Narrow script, if you will. For us, you know, you talk about the growth profile. No real impact to WGL for C&I in the district, as C&I isn't really a growth area. Over calendar years 2020 and 2021, we only had 5 net C&I adds in D.C. itself, so it represents less than 1% of our C&I customer adds over the period. 90% of the adds happen in Northern Virginia, and that's a trend we've seen for a while. We've got some time to work with the mayor and her staff on what that means and how it approaches, but we don't see it having a significant impact, given the focus on C&I in the area.
Great. That's very helpful. I'll turn it back here. Thank you.
Your next question comes from Robert Hope with Scotiabank. Please go ahead.
Good morning, everyone. I wanted to take a look at the global export business. Can you just talk about what the key drivers were for the strong growth on a quarter-over-quarter basis? You know, was this partially timing related for ships, or are producers or is your logistic capabilities increasing such that, you know, this is a relatively good run right here?
Hey, Robert. Randy Crawford. Thank you for the question. Good morning. You know, look, the record volume is a major milestone for us, and it's really proven that the assets can do it, and we have robust demand as well, and that creates real value. To have that optionality to consistently move those barrels is going to provide, and has provided substantial and sustainable value.
Really it does come down to our, you know, we've been able to prove out that we can move these volumes consistently, and we see a robust demand going forward. You know, this ramp-up of the 110,000, it's allowing us to identify some of the issues and opportunities that we can address, you know, that with clarity and to fix as we push this envelope. Clearly, we're seeing robust demand and while we think, you know, profitably keep it in and around these levels going forward. Again, those will fluctuate. The key driver is to prove out that we can move that level of capacity. I'm really pleased at the value created as a result.
Excellent. A follow-up question there is that, you know, we have seen volumes increase, but the amount of long-term contracts at the facility has been, you know, a little stagnant. What has the tone been regarding your conversations on contracts with producers? Are they just trying to figure out what the world looks like just given the commodity price environment? You know, once there's a better impact or an estimated impact of what Heartland does to the propane market, you know, could you see contracting discussions accelerate maybe towards the end of the year into 2023 for long-term contracts?
I think, yeah. The answer is yes. I mean, look, the recent strength in the fundamentals and the improving commodity price has certainly been working out in our favor in terms of supporting these conversations. You know, we recently have been seeing increasing interest, you know, not only from producers, Robert, but aggregators who wanna participate in the upside of having direct access to Asian pricing.
In the demand side, as customers in Asia look to reach back into the basin and then secure supply. Again, we're having, you know, strengthening fundamentals, strong conversations, and de-risking the midstream and energy export remains a top priority for us. I would just comment that, yeah, the conversations remain constructive, and it's a top priority.
Excellent. Thank you.
Your next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead.
Hi. Good morning, everyone. I'm gonna start with Petrogas. Now that you have it fully under control, how can you accelerate the integration and development of the Petrogas assets and the energy export terminals?
Well, thank you for the question, Robert. I think you're seeing it, right? I mean, we took over operational control. Randy and his team have been, you know, driving a great deal of the optionality as we, you know, move cargoes between even both of our ports, and maximize the value between the two products, so in that optionality.
I think that flexibility of operating those two West Coast facilities is very helpful. Another real attribute and value is the difference in rail deliveries. We have optionality to move on different rails, which will help us to manage our cost going forward and to maximize flows either into Ferndale or RIPET. From a corporate perspective, we're indifferent, and it gives us a lot of optionality and flexibility to create value for all of our customers and shareholders.
Okay. Just on the inflation frontier, when you look at the utility CapEx, is inflation more likely to cause an increase in utility CapEx and delay leveraging, or will it simply result in less progress on ARP programs or other initiatives for the same amount of spending?
Yeah, it's a good question. This is Blue. It's primarily where we would see it is we would get slightly less work done for the same dollars. We wouldn't expect to increase the CapEx per se. I would highlight for you that we're reasonably well protected inside this year just on the way we contract for our materials as well as our contractors and service providers. So we've had contracts that focus more on a per unit payment structure, so our contractors are incented for efficiency as well. Primarily means you might get a bit less work done for the same dollars.
Okay. Thank you. Then last question here, a little bit of a shot in the dark here. Previously, the company had some small to medium-sized LNG projects. I wonder if you still have those or if those were disposed of as part of some of the asset sales? If you still have them, is there any interest in rekindling those?
No, we do not have those at this point in the future. Overall, right, in terms of our DNA, we're focused, you know, on the LPGs and all of the development, and there's significant opportunities, I think, to expand our growth around the LPGs. That's, you know, primarily our focus. Obviously, with the increase in production of natural gas, that comes with associated liquids, and I think those are all important factors in our growth story. Those particular projects are not in our portfolio.
Okay. Thanks very much, guys.
Your next question comes from Ben Pham with BMO. Please go ahead.
Hi. Thanks. Good morning. I had a couple questions on Petrogas and LPG exports. The first one's on your leverage expectations that EBITDA, when you factor in Petrogas, is the trend leverage creeps up a bit in near term and then it drops much more as you look toward 2023 versus what you were planning before?
Well, you know, Ben, it's James here. From a leverage standpoint, we obviously saw a slight reduction in leverage when Pembina had exercised their buyout on our non-operated interest at Aitken Creek. When we decided to recycle that capital and deploy it to the purchase of Idemitsu's minority interest, we basically took back leverage to where it was before the exercise and close of the Aitken Creek facility. I wouldn't necessarily see it as a creep up from where we were exiting 2021.
Obviously you touched on the most salient point as we head into 2023, and we close the ENSTAR transaction, we would see a meaningful deleveraging event as we apply the proceeds from that sale to outstanding debt on our credit facility. Overall, we would expect the leverage reduction from 2021 as a result of the ENSTAR sale, and we consider the Petrogas transaction more or less leverage neutral when you reallocate the proceeds we received on the Aitken Creek facility to the purchase of that minority interest.
Okay. Got it. I know you mentioned some of the seasonality of butane spreads and spreads in general versus Q2. But really directionally, is it correct to think that as the volumes continue to ramp up on LPG exports, that you will see more of a structural declining in spreads? Then maybe one related to that. Have you seen any change in conversations with producers, with petrochemical as an alternative for propane?
Yeah. On butane spreads, I mean, we touched on it in our prepared remarks. If you look at Q2, we had FEI pricing in a shoulder season, so we didn't see a real ramp up. WTI, which is where we're buying butane as a percentage of WTI, we saw WTI prices run up, and we've also seen strong local pricing for butane, which squeezed our butane margins.
That was something that we signaled in Q1 when we had our prepared remarks. Where we are today, though, we've seen WTI moderate a little bit, obviously, and local butane prices have moderated a bit too. The back half of the year, we're entering stronger demand for butane in Asia, so we would expect FEI to rally. We see the back half of the year as having margins on butane that expand from where they are today.
Ben, this is Randy. On your question about the PDH plant in Canada, and that's why, you know, there's robust demand as you saw for Canadian LPGs globally in Asia, and we have the egress solutions and the best market for those. We factored in the plant coming online into our models. That was even at the time when the market dynamics were not as robust as they are today. We feel that there's a lot of headroom for increased production and moving of additional volumes.
All right. That's great. Maybe lastly, can you remind me, Randy, what is your contracted targets for either Ridley or Ferndale or on a consolidated basis?
In terms of the export volumes, Ben?
Yeah. I think you're around 30% right now, and correct me if I'm wrong, and you have targets to go to 40% or 50%, I think, per year. I mean, is that still the plan or has it changed? Just wanted the latest on that.
Oh, no. Sure, Ben. No. The plan and the commitment to de-risking and contracting these volumes hasn't changed in terms of that. As we increase the amount of volumes through there, right? That has an effect on the overall percentages. Overall we wanna be able to continue to de-risk that platform and we're having, as I said, very constructive discussions with both the market as well as producers looking at, quite frankly, hybrid models of tolling where we share in some of the upsides, as well.
We think that, you know, we're not stating a specific percentage, but you'll see that volume continue to increase. What we'll do is we'll continue to export additional volumes over and above the levels that we're at. At this point, you know, the goal is to continue to do that and we'll do it. Specific percentages will depend on the quantity of volumes, but expect the overall increase in tolling and de-risking throughout the year.
Okay. That's great. Thank you.
Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead.
Good morning. Maybe if we just focus on the core utility business and just what you're seeing from a customer standpoint. Are you seeing an increase in bad debts, any bill pressure, delays in payments, and then any mitigation programs you have around that?
Thanks for the question. Just a couple of comments. I'll let Blue, you know, chime in on some of the specifics here. You know, basically these increases in the cost of natural gas and the value of the price of natural gas is unfortunate, right? Especially when we have the resources in the U.S. to develop and mitigate these increases.
Unfortunately, to increase production, we need increased capacity of the markets. As you know, building a pipeline has been challenging in the U.S. around public policy. The reserves are there. Producers want to develop them responsibly and we need to see clear to move these forward. These increases are unfortunate, but they disproportionately affect, to your point about the utility, the least capable of absorbing them. That's, you know, exacerbating this issue. Otherwise, Blue and his team have been investing money, improving the system, lowering operating costs, managing inflation, right, providing a higher quality of service.
We continue to work with our public utility commissions, and we're looking at finding new ways, you know, to fund these increases in gas costs and to protect the most vulnerable in our system through our low-income program. A big focus on that as we move forward. You know, the overall macro is that, you know, we as a public policy matter, we feel that, you know, these prices should be coming down, but we need to build pipelines and at this point, working very closely with the commissions. Blue, did you want to add to that?
Yeah. Thanks, Randy. I think you hit the highlights. I'd add just a little bit of color on a couple of things. To Randy's point, we're very focused on trying to manage cost all the way through the process, knowing it impacts our most vulnerable customers the most. You will see us, the specific answer to your question is, are we seeing an increase in bad debts?
The short answer to that is no, we have not seen that yet. Been a very focused effort with the team to ensure that there are payment programs and other opportunities to help customers keep current. We've also been very focused on ensuring that our customers have access to those third-party programs that are available, LIHEAP and others, to help them as appropriate.
You will see us in our most recent D.C. rate case. For those that are defined the most energy vulnerable, we've actually proposed increasing some credits on a year-round basis to help offset the impact. We're trying to do what we can to protect and help those who are most impacted. To date, we have not seen an increase in bad debt.
Okay. Appreciate the thorough answer, and then maybe it segues into the related question. You know, what are you seeing just on appetite for customers to go towards things like RNG-related options where, you know, big growth area, carbon friendly, but obviously there's a pricing pressure issue across the industry right now.
Yeah, good question. Obviously, it depends on the customer segment. We are actively working through the RNG opportunities in our respective market areas. We certainly have appetite from our transportation customers. We're seeing it in our larger C&I, particularly data center customers, those type of things. Certainly an appetite there. You know, as you roll it through, you saw legislation in Virginia that gives us the opportunity to bring RNG and other lower carbon options into the fuel mix. Certainly see an appetite. It is customer class specific in many cases.
Okay. Appreciate that. Thank you.
Ladies and gentlemen, as a reminder, if you do have any questions, please press star one. Your next question comes from Robert Kwan with RBC Capital Markets. Please go ahead.
Morning. Just starting at a high level here with guidance, can you just talk about and just give an update as to the different headwinds and tailwinds you're seeing as we're now halfway through the year? As part of that, are there any moving pieces outside of the ordinary kind of commodity prices, weather and FX rates?
Hey, Robert, it's James here. In terms of guidance, I mean, obviously we do expect to be in the range. In terms of tailwinds, to your specific question and headwinds, you know, on the tailwind side, we are seeing stronger frac spreads that we've been able to capture, and that's gonna benefit us for the balance of the year. The Petrogas acquisition that we undertook is gonna benefit us from an EPS standpoint, but not necessarily an EBITDA standpoint because we were already consolidating 100% of that EBITDA. FX, you touched on, has been a tailwind as well, just given where it is today versus where we set our guidance back in December of 2021.
Stronger volumes in the first half of this year with respect to global exports and the performance of the retail business have all been tailwinds. In terms of headwinds, you know, obviously the butane margins that we've experienced here in the first half and that we called out early in the year being compressed relative to last year has been a headwind.
The Aitken Creek purchase was also something that was unexpected when we set our guidance. We've also incurred some increased customer costs at the utilities to address customer service levels there and make an investment in the customer experience. Those were all headwinds. When you kinda take a step back and you look at all the pluses and minuses, we expect to be in the range despite some of those headwinds.
That's great. Just drilling down into the midstream logistics and timing. Notice you called out the hedge timing, which can reverse out. Just on the OpEx, and you noted OpEx improvements. Can you just talk about like, are you able to quantify, you know, where what those opportunities might look like? What are the greatest opportunities, how quickly you can get at them? You know, put differently, how much of the impact in the quarter do you think you can improve on a sustainable basis?
Hey, Robert, it's Randy Toone. As far as operating costs, you know, we've been working quite hard on logistics. Logistics is one of our biggest costs to get products from the source to Asia. We've had a big focus on that for a number of years, and we're working with our service providers to get those costs down.
We know it's a vital thing to be sustainable and to grow our volumes. We will continue to work with our service providers to lower that cost. It's gonna be mostly on logistics. Also, if you look at these time charters, we've got a one-time charter this year that's helped reduce our ocean freight, and we have two more time charters coming on next year. We feel that that's gonna definitely help lower our freight rates going across the ocean.
Robert, I wouldn't mind just adding to that, not necessarily.
Go ahead.
Sorry. I just wanted to add to Randy Toone's comment, not necessarily from the logistics standpoint, but the one thing that we wanna highlight is with when it comes to supply costs on the global exports as well, we had turnarounds at four facilities which took equity barrels that we have offline, right? Those impacted margins with global exports as well.
Obviously, with the turnarounds behind us now, that's something that's not gonna happen in Q3 and Q4. We would have access to those equity barrels as well. The turnarounds, just from the midstream platform as a whole, reduced obviously volumes and corresponding EBITDA by about $9 million as well. That kind of obviously doesn't reoccur in the back half of this year as well.
No, that's great. CAD 9 million from the turnarounds. Does that include the higher supply costs because you didn't have the equity barrels and you had to go out and source them elsewhere or?
No, that.
Is that additive to that nine?
No, those. That would be in addition to the nine.
Like, are you disclosing roughly what that amount might be?
No, we're not getting that granular. I did wanna point out that was part of the margin compression.
Okay. Would you be willing to disclose just on the OpEx side, like how much did you see that increase in the quarter versus how much you think you can get back with some of the initiatives, that you've been talking about?
It's Randy Toone again. I think we're hopeful that if you look at our logistics costs, you know, we did see in Q2 higher fuel costs, like costs of diesel went up and we also saw higher rates. We're working with our service providers to reduce that. I would say we'd see, you know, say anywhere from CAD 2 million- CAD 5 million for the back half of this year of savings.
That's great. Thank you very much.
Your final question comes from Matthew Weekes with iA Capital Markets. Please go ahead.
Good morning. Thanks for taking my questions. I was just wondering with the Virginia, you know, with the expanded ARP program that was approved there, and, you know, in the core utilities, are you seeing sort of expanded spending profiles, you know, resulting from, you know, higher costs to sort of execute these programs? Or is that kind of playing into sort of the capital profile of those businesses?
Hey, Matthew, it's Blue. I'll answer your question. What we're seeing, I think I alluded to it in one of my questions earlier, we're seeing inflationary costs in certain subsets of our business. I think what you see from the Virginia SAVE approval is a recognition by that governing body that the work we're doing there is having a positive impact in upgrading our system, keeping our operating costs low and reducing our climate impacts.
Therefore, I think that's why you saw that extension. We're being very conscious on the cost base there. Where we're seeing our biggest cost pressures are anything to do with fuel-type costs. You know, the fleet component is impacted. Certainly, paving costs are up. That's a high energy use component. We're seeing that across all aspects of industry, certainly not just our work.
We believe that the work being done through those APRP programs is having a very positive impact on both our customers and our system from a lower forward operating cost as well as a lower or more positive climate impact as we try to help the region meet the goals. I don't know if that answered your question, but that's what I'd focus on.
No, that's perfect. Thanks. I just wanna follow up on that. Given that sort of, you know, I think the growth trends in the utilities do appear positive, and there's quite a robust, you know, growth profile happening there. Would you say thinking about the ENSTAR monetization that's set to happen and taking into account Petrogas, you know, are you comfortable with sort of where the balance sheet's going to be at going into 2023 to 2028 to continue to fund the kind of growth that you expect?
Yeah. I mean, Matthew, it's James Harbilas here. The short answer is yes. I mean, obviously, even before we monetized ENSTAR this year, we had a fully funded CapEx program for 2022. Looking out into 2023, obviously, once that deal closes, we'll reduce leverage. It creates a lot of balance sheet capacity for us to pursue organic growth in the midstream platform, as well as to execute on the 8%-10% rate base growth that we see coming out of the ARP programs that have been expanded by Virginia. There's still a lot of mains to replace, as Blue suggested, in all our jurisdictions. Obviously, by investing in that type of capital, we're improving reliability on the system, reducing leaks and making the system a lot safer. We can fund that ARP growth at 8%-10% that we've outlined.
Yeah. This is Randy. I'll just add, I think James, you know, described it well, but in fact, the sale of the Alaskan utility really has provided us enough liquidity to fund both of our businesses and to grow the individual bases even larger and to position us down the road for continued growth. That's really the strategy, and positions us quite well to execute on our enviable growth opportunities.
Okay. Thank you. I appreciate the commentary on that. I'll turn it back. Thanks.
My apologies. This does conclude the Q&A portion of today's call. I'd now like to turn the call back over to Mr. Morrison.
Thanks, Pam. Thanks to everyone for joining us on the call and for your continued interest in AltaGas. That concludes our call this morning. I hope everybody enjoys the rest of your day, and you may now disconnect your lines.