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AltaGas Ltd
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Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Fourth Quarter 2021 Financial Results Conference Call. My name is Michelle and I will be your operator today. All lines have been placed on mute to prevent any background noise. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session. I'd like to remind everyone this conference call is being broadcast live on the Internet and recorded.
I would now like to turn the call over to Mr. Adam McKnight, Director of Investor Relations. Please go ahead, Mr. McKnight.
Thanks, Michelle, and good morning everyone. Thank you for joining us today for AltaGas' fourth quarter and full year 2021 financial results conference call. Speaking on the call this morning will be Randy Crawford, President and Chief Executive Officer and James Harbilas, Executive Vice President and Chief Financial Officer. We're also joined here this morning by Randy Toone, Executive Vice President and President of our Midstream Business; Blue Jenkins, Executive Vice President and President of our Utilities Business; and Jon Morrison, Senior Vice President, Investor Relations and Corporate Development.
We'll proceed on the basis that everyone has taken the opportunity to review the press release and our fourth quarter results. And similar to previous quarters, we've published an earnings summary presentation that you can find on our website. This presentation walks through the quarter and highlights some of the key variances and nonrecurring items that we would assume will be helpful for the market to understand. As always, today's prepared remarks will be followed by an analyst question-and-answer period, and I'll remind everyone that we will be available after the call for any follow-up or detailed modeling questions that you might have.
As for the structure of the call, we'll start with Randy Crawford providing some comments on our financial performance and progress on our strategic priorities, followed by James Harbilas providing a more detailed walk-through of our fourth quarter financial results, near-term outlook, and 2022 guidance. And then we'll leave plenty of time at the end for Q&A.
So, just before we begin, we'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 the 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 both SEDAR and EDGAR.
And with that, I'll now turn the call over to Randy.
Thank you, Adam, and good morning everyone. 2021 was a strong year for AltaGas, as we achieved a number of significant milestones across our platform. I am proud of the strong financial and operational performance that we delivered over the course of the year, and the progress we made on our ESG initiatives.
We delivered earnings per share growth of 25% year-over-year and normalized EBITDA growth of 14%. These results were well within the ranges of our April 2021 increased guidance despite the operational and financial impacts associated with the devastating flooding that impacted communities in British Columbia and Washington state during the fourth quarter.
Our 2021 operating results built upon the strong growth that we delivered the past two years and is a testament to our diversified model that continues to demonstrate strong advantages throughout market cycles and operating environments. We continued to deepen our organizational capacity and significantly advanced AltaGas' long-term corporate strategy by improving operating practices that are focused on long-term operational excellence.
In our Utilities, we achieved 6% EBITDA growth, despite milder weather in Michigan and D.C. during the fourth quarter. We added 17,000 new customers across our Utilities network in 2021, while increasing our rate base by approximately 8.5% year-over-year through our continued investment in our networks, enhancing the safe and reliable service we offer our customers.
Our utility operations were strong and we continued to center on the same regulatory capital and cost discipline that we had been focused on [indiscernible] (04:37) over the past three years. Our continued investment in Accelerated Pipeline Replacement has resulted in a 23% and 13% reduction in leaks since 2019 and 2020, respectively. We are now exceeding our customer service metrics, having overcome the initial challenges we faced by changing our call center provider at Washington Gas in the third quarter. These are foundational improvements that will continue to accrue benefits well into the future.
With our Midstream segment, we delivered an exceptionally strong performance this year, despite the unexpected headwinds faced in the fourth quarter. We're extremely proud of the financial performance that we delivered over 2021. With more than CAD 2 billion of investment in the recent years within the Northeast B.C. in our global export platform, we are excited about the egress solutions that we have been able to provide to producers in the region and our ability to provide critical source [ph] and needing (05:33) natural gas liquids for key Asian markets.
We also take great pride that our infrastructure and operations will support better global environmental outcomes that align with lower carbon and lower emissions future that is upon us. We successfully completed the integration of Petrogas and achieved combined synergies that exceeded our CAD 30 million target. This was a testament to the strong talent we added to complement the existing strengths of our organization.
Through the combination of our export assets, we were able to average approximately 90,000 barrels a day of global exports in 2021, which was in line with our annual target. With the flooding behind us, the platform is well positioned to achieve our 2022 export target of 97,000 barrels a day. Our gas gathering and processing, and fractionation and liquids handling operations also demonstrated strong growth, which is a testament to the integrated value chain we operate. We continue to make strategic investments in our Montney and global export platform with the continuous focus on connecting customers and markets over the coming years.
The macro environment for energy fundamentals continues to strengthen as the tightening supply and demand picture drives commodity prices to levels not seen since 2014. The unfortunate events that have been unfolding in Eastern Europe illuminate the critical value of energy independence and diversity. These events are already producing far-reaching geopolitical implications regarding energy security.
Germany recently announced plans to further diversify its energy supply with the recent announcement of planned additions for two new LNG terminals as well as numerous discussions by foreign countries related to the investment and long-term contracting of diverse energy supply. We are fortunate in Canada and the United States to have access to abundant sources of energy, and it's imperative that we invest in critical energy infrastructure continues as we continue the transition to the energy sources of the future.
AltaGas is well-positioned to support the continued development of energy resources such as the Montney and, to a lesser extent, the Marcellus Shale to facilitate the best outcomes for our customers in Canada, the US, and Asia. It's unfortunate that the narrow view that has been taken regarding MVP has caused significant delays to the completion of the pipeline. The pipeline will ensure diversity and affordability of natural gas critical to East Coast utilities that serve the energy needs of US residents and businesses. The 2 Bcf a day design capacity of the pipeline has the potential to free up natural gas originating in the Gulf that could be available for export to Europe.
We also take a lot of pride that our infrastructure and operations will support better global environmental outcomes that align with lower carbon and lower emissions future that is upon us. Our Midstream business will continue to be centered around our global export platform, which provides access to key West Coast North American ports that provide a structural advantage, which is a 60% advantage over US Gulf Coast and a 45% advantage over the Middle East for shipping timing savings. This provides North American producers and aggregators with the best netbacks for propane and butane, while providing diversity of critical LPG supply and contributes to the energy security in Asia.
In these uncertain times in which we live, we take a great pride in being able to be a steady and reliable energy provider to North America as well as Japan, South Korea, and other key Asian markets. And as I look ahead, I am extremely excited about the position of our company, and the increasingly constructive energy demand fundamentals as the global economy continues to recover.
We remain steadfast in our strategy, and are firmly committed to leveraging our strategically positioned Utilities and Midstream assets, both with significant organic growth opportunities. So, in closing, I am proud of the role that AltaGas plays in supporting North American energy independence and our ability to export affordable butane and propane LPGs to the world.
And with that, I will turn the call over to James to review the financial results in detail.
Thank you, Randy, and good morning everyone. As Randy mentioned, we are very pleased with our 2021 financial results and the strong progress that we were able to accomplish during the year. We achieved normalized EPS of CAD 0.38 in the fourth quarter and CAD 1.78 for the full year. This included landing within the upper end of our 2021 guidance range of CAD 1.65 to CAD 1.80, and represented a 25% year-over-year increase.
Normalized EBITDA for the quarter came in at CAD 341 million and CAD 1.49 billion for the full year, which was slightly below the midpoint of our guidance range of CAD 1.475 billion to CAD 1.525 billion, and represented a 14% year-over-year increase. You will recall that both of these guidance ranges were increased in April 2021 versus our original expectations at the start of the year.
Normalized FFO was CAD 287 million for the quarter and approximately CAD 1.2 billion for the full year, representing 19% year-over-year growth. This strong cash generation provides us with the foundation to fund our strong ongoing organic growth opportunities and increasing our returns of capital to shareholders over the long term.
Turning to our segmented results for the fourth quarter, normalized Midstream EBITDA came in at CAD 102 million compared to CAD 128 million in the fourth quarter of 2020. The quarter included continued year-over-year growth in our global exports platform, albeit at a slightly slower pace than would have otherwise been the case due to devastating flooding that occurred during the fourth quarter and the large rail outages on the West Coast. AltaGas' gathering and processing volumes increased 9% year-over-year in the fourth quarter of 2021, while fractionation and liquids handling volumes increased 37% year-over-year.
Growth within AltaGas' facilities continue to be more heavily weighted within Montney facilities and the company's industry-leading footprints in the region. These strong volume growth numbers were offset by two major factors. The first was the CAD 24 million timing-related hedging loss that we previously disclosed in the third quarter. This relates to the recognition of revenue for an LPG cargo that was loaded at the end of the third quarter at spot prices with the offsetting hedge loss not realized until delivery in the fourth quarter once the ship reached its destination. The second factor was the logistical and cost challenges associated with the flooding on the West Coast with the total financial impact of approximately CAD 20 million.
Although we were able to mitigate some of the transportation and supply chain outages by redirecting certain propane volumes to RIPET that were originally destined for Ferndale, we were not able to alleviate butane volume disruptions with financial performance further impacted by higher transportation costs associated with rail switching to handle the large logistical outages. Other factors that impacted the fourth quarter results include AFUDC on MVP no longer being recorded throughout 2021, the loss contribution from the US storage business that was monetized in the second quarter of 2021, and the impact of the Gordondale blend and extend contract.
Considering the size and magnitude of the flooding and mudslides, we were encouraged by the swift recovery by the team to get us back on track in early 2022. Looking ahead, we continue to actively de-risk the Midstream platform and reduce commodity price exposure and volatility where appropriate.
We're well hedged through 2022 with approximately 44% of global export volumes tolled or collectively hedged. This includes an average FEI to North American financial hedge price of approximately $13 per barrel between our expected propane and butane volumes. We also have 74% of our expected frac exposed volumes hedged in 2022 at CAD 33 per barrel.
Normalized Utilities EBITDA was CAD 238 million in the fourth quarter compared to CAD 259 million in the comparable quarter of last year. The year-over-year decrease was largely due to unfavorable weather conditions and the impact on retail, marketing power and gas margins, and higher PJM costs in 2021. Lastly, the continued weakness in the US dollar to Canadian exchange rate drove a further CAD 7 million year-over-year impact during the quarter compared to the fourth quarter of 2022.
WGL reported normalized EBITDA of CAD 183 million in the fourth quarter, up 8% year-over-year, driven mainly by the positive impacts of the Maryland and D.C. rate cases, continued ARP investments, as well as higher returns on pension assets and asset optimization. The quarter also included some costs associated with replacing the customer call service provider at Washington Gas following service and performance issues with the former provider.
SEMCO and ENSTAR's combined normalized EBITDA was CAD 60 million in the fourth quarter, down CAD 6 million from the same period last year due to warmer weather in Michigan, partially offset by colder weather in Alaska and slightly higher operating and G&A costs related to employee benefits. And finally, the retail business generated CAD 27 million lower normalized EBITDA contribution on a year-over-year basis due to the combination of outsized performance in the fourth quarter of 2020, which was driven by the timing of PJM fixed costs, and the timing impact of swap gains between the third and fourth quarters of 2021, the latter of which had the effect of pulling profits into the third quarter of 2021 rather than the fourth quarter of 2021.
The Corporate and Other segment reported a normalized EBITDA of CAD 1 million compared to CAD 5 million in the same quarter of 2020. The CAD 4 million year-over-year decrease was driven by the combination of higher expenses related to employee incentive plans as a result of the AltaGas's rising share price over the course of 2021 and the monetization of Pomona and Ripon in 2020.
During the quarter, we recognized a CAD 271 million pre-tax impairment on the Mountain Valley Pipeline to reflect a heightened risk and legal challenges associated with the project given recent court rulings. We continue to believe the pipeline would be completed and is vital to long-term energy security on the US East Coast, but the impairment reflects some of the recent risks on the project.
Subsequent to the quarter-end, AltaGas closed the sale of a 60 megawatt stand-alone energy storage development project in Goleta, California for total proceeds of approximately CAD 15 million. AltaGas also agreed to sell an interest in certain Midstream processing facilities to a customer during the first quarter for total consideration of approximately CAD 234 million. The transaction is expected to close in the second quarter of 2022.
Turning to our balance sheet, we are maintaining a disciplined approach to capital allocation within a self-funding model that will continue to strengthen our balance sheet and increase financial flexibility over the medium to long term. We remain steadfast in our goal to reduce our net debt-to-EBITDA to below 5 times in the medium term. 2021 year-end net debt was CAD 8.3 billion compared to CAD 8.2 billion at 2020 year-end. This was above our expected levels due to a combination of factors, including larger-than-expected working capital, including higher gas cost, cost of gas and storage within the Utilities which should start to unwind in the next few quarters.
Looking ahead, AltaGas continues to focus on delivering durable and growing EPS and FFO per share while lowering leverage ratios. We are maintaining our 2022 guidance ranges, including normalized EPS of CAD 1.80 to CAD 1.95 per share, normalized EBITDA guidance of CAD 1.5 billion to CAD 1.55 billion, and a capital program of approximately CAD 995 million.
And with that, I will turn it back to the operator for questions.
Thank you. Ladies and gentlemen, we will now conduct the analyst question-and-answer session. [Operator Instructions] Your first question comes from Linda Ezergailis of TD Securities. Please go ahead.
Thank you. Just wondering beyond the broad industry implications on recent unfortunate geopolitical events and the clear value of Western Canadian and North American energy security and supply, how are you thinking about maybe the implications that might have on AltaGas' strategy and maybe any specific operational potential impacts beyond constructive demand fundamentals?
Hi, Linda, good morning. This is Randy. Thank you for the question. Specifically, on the geopolitical unrest and the impact on AltaGas, specifically, I would say there's not an impact overall, but as I said in my prepared remarks, we're seeing a lot of interest from foreign markets that are interested in controlling their destiny around energy and those recent events, we believe, are only going to bolster that appetite.
So, we're going to continue to work with these entities for contracting offtake at the plants. And so, these customers are looking to acquire the rights to output and I expect that to continue. So, that's one of the impacts that we're clearly seeing. From an operational perspective, we continue to deliver and the team is doing an excellent job.
Great. And just as a follow-up, what about your domestic customers? Are you seeing rumblings potentially of a supply response to meet the need for domestic demand? Or is it still too early to see that those conversations picking up?
Well, I think that definitely that we're seeing continued importance of natural gas and the impacts from some of the things in Europe overall. But overall, I'll let Blue comment on specifically with the utility, but we're continuing to see a lot of activity around increasing request for supply. Yeah, Blue?
Yeah, happy. Hi, Linda. So, we are seeing an increased response in some of the supply basins that we, of course, access and that's primarily driven as you alluded to the geopolitical events. We're also seeing an increased focus on those producers responding to an increase in the climate initiatives, so certifying our gas and those type of things. So, I think it's quite positive from that. We certainly haven't had any access issues to supply and when we go out to talk to the markets, we have a very robust response. So, we see that all as quite positive.
Thank you. And maybe this is a...
And, Linda, I'll just add to – I'm sorry, Linda. I was just going to add that from a pipeline capacity perspective, right, that we continue to need that infrastructure to be built out even to have that supply response.
Yes, good point. And just maybe a quick question for James. With the asset sales, Midstream and the Brush power plant, what would be the EBITDA contribution from those sold assets? Can you confirm that this is either credit neutral or positive? And are there – I'm just curious also the rational for selling the Midstream assets and might there be other assets sold this year?
Thanks for the question, Linda. Look, I mean at the end of the day when we look at the Midstream assets, the multiple on that sale is roughly 9 to 10 times EBITDA. So, you can back into the foregone EBITDA from close to year-end on that number and we don't expect it to impact our guidance ranges and we see it as credit neutral. I mean it'll obviously bring down our net debt-to-EBITDA figure from where it was at year-end, get us closer to about 5.2 to 5.3 times versus where we exited 2021.
And with respect to the decision to sell it, I mean it's consistent with our approach around creating value by operating these assets and this was a non-operated interest. So, that was some of the strategic rational beyond us exiting, but the liquids associated with this plant continue to be dedicated to our liquids infrastructure.
That's helpful context. Thank you. I'll jump back in the queue.
Your next question comes from Dariusz Lozny of Bank of America. Please go ahead.
Hey, good morning and thank you for taking my question. I was just wondering if you could comment on – there was the report in a US news outlet that AltaGas is taking bids for your stake in one of your Alaska gas utilities. Just wondering if you could touch on that at all or potentially comment on whether you'd consider selling any other gas utility assets.
Yeah, thank you for your question. Obviously, we've talked about our core and non-core assets and utilities assets are core, and I won't – I cannot comment on any specific asset sale as you can appreciate. But we continue to look at opportunities and we have a strong track record of recycling capital and looking at ways to drive shareholder value. But philosophically, our strategic objective is for our invested capital to be in the assets that are always providing the growth dynamic and that's what we look at with all of our assets. So, our objective is to position our assets so that we can profitably grow and leverage the asset for growth. And so, that's how we really approach this. I can't comment anything specific on any rumors that are out there.
Okay. No, thank you. I appreciate that color. And maybe just along similar lines, obviously, the MVP pipeline is having some delays as you alluded to in the opening remarks. In the past, you had said that you would consider transacting that after it's in-service. Any changes to your outlook on that as the in-service date now appears less clear?
Yeah. I mean, I think we've said that we would be patient along those lines. And so, I don't think – just a comment in general, right, I think the key area in MVP is the biological opinion and once we get clarity on that and if that gets cleared, I think everything will fall into place. But most importantly, the MVP pipeline is consistent with what I've talked about, the approach of the US needs to take to ensuring access to clean energy from burning energy.
And it's not that long ago, as you know, that we're importing natural gas and using significantly more amounts of coal. So, now that we've created the cleaner energy, independent country, we should not have to worry about those same concerns that they're having in Europe, but we can't take it for granted. And so, this is a really important pipeline, and we've got to continue to recognize just how fortunate we are in energy in North America.
Hey, I wouldn't mind just adding that I don't want to remind people that we always positioned MVP as a way for us to get below 5 times debt-to-EBITDA quickly, right? So, we continue to believe that the pipeline will be built; and once it is, we can get to below 5 times through monetizing that pipeline.
But we haven't incorporated into our 2022 funding plan, which I think is an important thing to point out and we're not reliant on the sale and monetization of MVP to maintain our current ratings. We can continue to improve our credit ratings through organic growth within our FFO and obviously EBITDA on the investments we've made in the past. So, I just want to make sure that we put that into context from a delay standpoint with respect to this non-core asset.
Got it. Thank you very much for those responses. Appreciate it.
Your next question comes from Robert Catellier, CIBC. Please go ahead.
Yeah. I just like to follow up on MVP, some of your equity partners have taken a different approach on the level of impairments they've taken. So, what does this mean with respect to alignment on the project, or are the partners still generally aligned?
Oh, Rob, thanks for the question. Well, absolutely, I think partners are focused to get this pipe – in the critical nature of this pipe. So, I don't think that's changed in any way.
Okay.
Yeah, Robert, it's James here. I mean, if you look at our approach to the impairment, it is very consistent with the approach that the operator took. So, we used similar probability assessments, obviously, cash flow profiles and estimates around asset retirement obligations if the pipeline is decommissioned. So, our impairment really followed the assumptions that the operator use, so we're closely aligned there as well.
Okay. That was going to be my next question. Just what you would estimate the ARO to be, the asset retirement obligations, should things not work out the way you envision and the project ultimately be stopped?
Well, yeah, if you look at NextEra's filing, I think they disclosed an asset retirement obligation of roughly [ph] $400 million (27:31). Our obligation would be above 10% of that, which is our equity ownership in the pipeline and that's what we factored into our model when we ran our impairment analyses.
Okay. And then just couple more quick ones here, but just is there any update on the butane export license progress?
Hi, Robert, it's Randy Toone. I believe right it's just going through public notification and that's a certain number of days. And so, we should have that license here probably within the next couple of months.
Okay. And then finally, [ph] so a thinly available (28:15) question, but how would a non-operated liquids pipeline enhance your business if one should become available in the market?
Okay. I'm sorry, Rob, I was just trying to understand the questions just like that. Look, I just – again, back philosophically that we have focused on creating value, we're an operating company and we add value through our model of operational excellence in controlling the asset. So, we think that's a critical part of how we operate and how we add value to our customers and I think that's kind of where we would look at that.
Okay. Thanks very much.
Your next question comes from Robert Kwan of RBC Capital Markets. Please go ahead.
Great, good morning. If I can come back to one of the answers, James, you gave earlier, just around the leverage target of under 5 times and just with the MVP delay, are you really just linking getting there with MVP only? Or if you think about the uncertainty and the extended timeline, do you see other assets that could help you get to that target, maybe if you can also comment on just some of the recent M&A that we've seen in the past week or so for both Midstream in Western Canada as well as LDCs in the US?
Yeah. So, Rob, my comments around MVP was that if we were able to – if the consortium was able to hit its original in-service date, which was estimated as Q2 2022, we saw it as an immediate way for us to get below 5 times and that's how we positioned it when we talked about at our Investor Day and rolled out our guidance.
We still think we can get to 5 times even without an MVP monetization. It's obvious it's just going to take us longer to get there with the organic growth that we would see on the platform and when we run our models five years out, we can get below 5 times net to EBITDA (sic) [net debt-to-EBITDA] (30:21), but it takes time without the monetization of MVP.
If we're able to move forward with it in 2023 assuming that's the new in-service date once we go through some of the – once we revisit the biological opinion and move that through the process, then obviously we can get there in 2023. So, that's what I meant with respect to that asset. I'll defer to Randy on some of the M&A activity.
Thank you, Robert. Appreciate the question. And so, look, my comment in general about some of the LDC and the other activity is that I'm actually excited that the private side is seeing the value that's intrinsic in these assets and we're going to continue to work to extract that additional value and improve the overall value of our utility assets. So, overall, that's exciting to see that recognizing that intrinsic value.
I guess just, Randy, with you mentioning the private side seeing the value in terms of trying to reach that leverage target, is there any kind of thought of whether it's asset or a combination of non-MVP assets just to strike while the iron is hot and get yourself to under 5 times?
Like I said, I don't want to comment on anything specific, but the fact is I think our management team has shown that we focus on creating shareholder value, right? But we've got a lot of additional value to extract in investments in a lot of these assets. So, I think that we'll continue to look at opportunities to recycle capital, but in general, I think we've got a pretty good track record of that. But overall, excited about the fact that the intrinsic value of these assets is being recognized.
Got it. If I can just [indiscernible] (32:02) a couple of small questions on guidance. The guidance statement specifically called out that an effective 21% tax rate. I'm just wondering if there's something to read into that. And the other is you've highlighted the mix, [ph] Uts versus Midstream and (32:18) EBITDA. Recognizing it's a small change, but Midstream is going up notwithstanding MVP is coming out of this year and you also have the asset sale you just announced. So, just is that commodity prices or there's something else going on in either of the two segments that's changed since December?
No. So, I just want to address the first part of your question with respect to effective tax rate. I mean, we've always assumed an effective tax rate of roughly 21% to 22% when we've rolled out our guidance. So, I don't think there was anything unique about that. We've disclosed it in the past.
If I'm following your second question, I mean, obviously, we've reaffirmed the guidance range that we rolled out at our Investor Day. The asset sales that I referenced in the past, yes, it'll be a bit of a grind to our overall EBITDA between the close date and the sale date. But there are some tailwinds around frac spread that can more than offset that and that's why we're not going to move our guidance range. We're still going to land within that guidance range and Midstream will benefit from some tailwinds on frac spread that'll help to offset some of the EBITDA that we'll lose by closing this transaction.
Got it. Okay, thank you.
Your next question comes from Jeremy Tonet of JPMorgan. Please go ahead.
Hi, guys. This is [ph] Steve (33:47) on for Jeremy. Just a couple from me. As far as the flooding goes, are there any long-term impacts on your strategy going forward? Is there any possible steps you're thinking about taking to kind of help avoid repeating this in the future?
Yeah, [ph] Steve (34:08), thanks for the question, sir. Overall, I think the optimization of our ports and the activities that the team did to manage through this was excellent and we're always taking – looking at a variety of things around unit trains and optimization in storage that can only enhance and mitigate some of these impacts. This was quite a significant event, but certainly we're taking a variety of different optimization steps to ensure that we can move our products consistently every day. Randy, do want to add anything else to do that?
Sure. Yeah, the railroads are a very important piece of the supply chain for Canada and that was a significant outage for them and they are – the railroads are trying to build their own resiliency into their network and so through force-fires, through floods, they're trying to build that resiliency in themselves along with what Randy said that we're building in.
Got it. And then as far as I know with the blend and extend contract with Gordondale and then there're some contracts coming up again in 2022. So, I just wanted to see if a similar contract agreement would be viable for the ones that are coming out soon. Would you look to do just – you're maintaining the [ph] cost of service on the ones that have cost of service (35:33) and just how you think about that going forward?
Yeah. I think that I know the ones that you're referring to that shows they're coming up and unfortunately our website is a little out of date, so thanks for pointing that out and we will update that. But we don't have any immediate contracts that are coming up for renegotiation that would subject us to any kind of blend and extend discussions with customers. So, we apologize for that on the website.
Understood. But beyond that, with the blend and extend contract always on the table, just how do you favor contract terms, I guess?
So, when you say – I mean, look, typically the approach that we'll take on a blend and extend is obviously to try to keep the same NPV on these contracts, right? So, if we're going to drop the rates, we're looking for some extended terms, so that when we do an NPV calculation, we can more or less maintain the returns that we're going to generate on those contracts. I mean, if your question is philosophical, that's the way we'll typically try to approach it and obviously the rates on those contracts that are coming up for renegotiation need to reflect where the market is as well.
Got it. Appreciate the color guys.
Your next question comes from Rob Hope of Scotiabank. Please go ahead.
Morning, everyone. I want to go back to the gas processing sale. Kind of what was the genesis of this? Does it change how volumes are allocated to that specific facility and does it also, I would say, alter the fee structure for the remaining volumes?
So, Rob, it's James here. No, I mean, look, at the end of the day, the liquids associated with that processing facility continues to be dedicated to our liquids handling infrastructure in the region. So, what we're forgoing obviously is the gas processing – our share of the gas processing fee when we had that non-operated investment. That's what we're forgoing. It doesn't really change anything else about the remaining footprint or the way we run our business, because it was a non-operated interest.
And I'll just add, we just don't see this transaction having any adverse impacts or impact on our overall Midstream and energy export value supply chain.
All right. Appreciate that. And then just moving over to RIPET and Ferndale, we've seen FEI kind of diverge here recently from Bellevue and even more so from Edmonton. So, as you take a look at your hedging profile through the rest of the year, you're pretty good for Q1, but it goes down quite quickly for Q2 and beyond. Are you looking to layer on more hedges here or is this an opportunity to go out to your longer-term customers and get more tolled volumes here? So, kind of how are you balancing duration for kind of near-term torque?
Rob, it's Randy Toone here. We're going to take advantage of the higher FEI prices and layer in more hedges when – we're just looking at the April 1 supply and we just want to make sure that those supply agreements are going to line up with our hedging. So, you'll see more hedging come in here over the next – probably over the next few weeks, so.
And I will also add, the macro, it lines up obviously quite well and that we'll continue to layer those in, as Randy had said, but we'll focus on also optimizing our network to get increased volumes and to continue to meet the demands of our customers. So, I think it all goes, but I think the macro is setting up reasonably strong for the year for us.
Thank you.
Your next question comes from Ben Pham of BMO. Please go ahead.
Hi, thanks. Good morning. I wanted to start with your comments around de-risking your business over time, and I'm wondering to your comments around the geopolitical risks and tight supply, commodity prices rising, [ph] is that enough (39:46) or has that changed your view on maybe the pace at which you're looking to de-risk or hedge your business over time or it's status quo from before?
Hey, thanks. No, what I was implying is that we've been consistently having discussions with the markets about wanting them, they want to reach back and control our destiny. And the team and Randy have done an excellent job of sort of validating the fact that we can deliver consistently to Asia, the energy.
And so, I think that as we look forward, right, we're going to see the market reaching back and entering the longer-term type of tolling arrangements as well. So, that really hasn't modified our strategy, I think it just looks that it's sort of the next step as we validate this strategy for customers to reach back. And I think this tragic events that are happening just underscores the importance of being able to control your destiny and have access to energy from reliable sources and diversity of that. So, that's what I was referring to and I think it just enhances our strategy.
Okay. And maybe I can switch to Utilities, you mentioned 6% EBITDA growth, rate base going up 8%. Can you provide perhaps where earnings went for 2021? And then also where you did land on the ROE?
Sure. I think overall, right, what's been driven is the historical investments that have lowered leaks, reduced cost and such that we've done and we've continued to make improvements in the business, improving the service levels and, as you referenced, the overall EBITDA. And so, I think we made significant progress building this team and improving return on equity, [ph] I don't have that (41:41) in front of me, but I believe about 0.75 or so was the improvement in the ROE this year in the basis points, but I'll let James answer.
Yeah. No, that's right, Randy. We're still about 0.6 to 0.7 short of our allowed ROE and we have made progress, as Randy touched upon. Obviously, we had some headwinds in the fourth quarter that directly went to us addressing customer service issues where we've made tremendous progress there, and we see those costs as transitory. We don't see them as ongoing now that we're starting to approach the service levels that we need to approach on the customer service side.
Okay, that's great. Thank you.
Your next question comes from Andrew Kuske of Credit Suisse. Please go ahead.
Thank you. Good morning. I guess this question for one, if not both of the Randy's on the call. And it's really when you think about the transactional activity we've seen in Western Canada most recently, what do you think that means for asset values, but then also the competitive dynamics? Greater presence of private capital in the basin and just competitively how does it affect you and your footprint?
Sure. Andrew, well, first of all, I think that we are – our core competency of being able to export in attached global markets makes us quite distinctive from that standpoint. And I think that – and certainly with the rising energy prices and the need to get to these valued markets, I think that puts us in a strong position vis-à-vis our competitors.
I think what you see in the basin is that a lot of efficiencies and consolidation with regard to that that are driving those types of transactions. But overall, I think that when you remain competitive, you look at your cost structures and you focus on your customers and give better access to markets, I think that really will allow us to be – continue to be distinctive and to grow our footprint and increase shareholder value.
That's helpful. And then maybe this is a two-parter for the second part of the question and it really winds up being on the hedging around those export-oriented businesses, which you manage to grow, but you also have this interesting opportunity to expand and continue to optimize the cost structure of those businesses. So, how do you think about the hedging right now on the current market environment versus open? And do you triangulate for really your capital projects in the future on the expansion plans, whether it be RIPET or Ferndale?
When we look at hedging, look, we focus on that in terms of managing our cash flows and then as we look through at our earnings and plan, but we always are looking to optimize those assets. So, more broadly, like, we're looking at improving our logistics, driving down our operating cost and that comes with the scale that we're building across the entity going forward.
So, we look – as we move forward with our customers and move more toward a demand pull and tolling, that's clearly another way of hedging overall. And so, I think that's our strategic approach over time is to continue to do that, and to activate – actively monetize the merchant activity to the extent that we can optimize the capacity.
And, Andrew, I'll just add. I mean Randy Toone touched on one of the critical factors that we consider when we're looking to hedge and that's having clear visibility into the supply, the quantity of supply that's available in the market and the timing of that as well. So, that factors into our decision making in terms of when we're executing those hedges as well. So, even though we're hedged at a lower percentage between Q2 and Q4, as Randy Toone touched on, you can expect that to go up as the contracting season kicks in on April 1, and we get better visibility into the timing and quantity of the volumes that are available.
Okay, that's helpful. And then, James, if I could just sneak in one more and it really is on your comment on the working capital, like, obviously, with the gas prices moving upwards and generally, you're passing through their cost of gas to the end user. But just for clarity, you have – I would assume you have effectively [ph] metric released (46:06) from the debt raters just given the current circumstances.
Sorry, Andrew, I'm going to apologize. I did not catch the last part of your question. It came across a little pixilated. Can you repeat that last part, please?
Sure. So, just given the fact that you pass through the cost of natural gas to the end users in the regulated utility businesses, the fact that your working capital's increasing right now just given it's winter, given the fact we got gas prices, like, you're not getting any negative blowback from the debt raters at this point in time, just given your regulatory protections?
No, no. Yeah, no, I appreciate that clarity. We aren't, I mean, if, obviously, the – to put it into perspective, the 55 Bcf of storage that we have, the cost of that gas, our weighted average cost of gas is 75% to 80% higher year-over-year and from a – it will unwind. We'll start to collect it, but the rating agencies specifically give us an allowance for the cost of that gas because of the pass-through nature that you touched on. So, it wouldn't be a drag to our FFO to debt metrics with S&P.
Okay, that's great. Thank you.
Your next question comes from Patrick Kenny of National Bank. Please go ahead.
Oh, thanks guys. Just a quick follow-up. You touched on the LPG supply re-contracting season this spring. But just given the pause on activity in Northeast B.C. and how tight fractionation capacity is in Western Canada right now, if you do have to reach, say, further into the Bakken or other basins to backfill supply, just curious what impacts, if any, there might be on your export margins year-over-year.
I'll let Randy comment on that maybe more specifically. But we're actively looking to source volumes from the Bakken and other basins and certainly there might be some margin differential because of cost. But overall, having the best markets for those products is certainly helpful in that sense. So, I look at it as incremental as we go to the other basins going forward from our plan, but Randy, answer that.
Yeah. So, look, we're quite confident in the supply come April 1 out of Western Canada, so either Northeast B.C. or Fort Saskatchewan. The Bakken is – logistically it's – we have to get rail cost down to really make those economics work. But we are working on a number of initiatives to make that happen over the next one to two years. But we feel that we can meet our targets sufficiently with the volumes in Western Canada.
Okay, that's great. And then, James, just on the recent hybrid issuance and I guess the associated redemption of the Series J prefs, looks like the math was a no-brainer on that one. I know you have some time here, but how are you thinking about other potential pref redemptions? I think the Series C is due this fall and then a few more still to come over the next couple of years. But just curious how the math might be looking today assuming you can refi with hybrids along the way on similar terms as this most recent one.
Yeah, great question, Pat, and obviously we have been very active in terms of trying to replace hybrid prefs with hybrid instruments with a cost advantage that you touched on. I mean we're going to continue to monitor the markets in terms of cost and accessibility between now and when we have to make that decision this fall when Series C comes up for rate reset.
I mean if I look at even where the underlyings have gone and some of the spreads just given interest rate pressures that everyone is seeing across the curve, I still think that we can make Series C work, but I don't want to make that determination now. We'll have to wait until we get closer to that redemption date and make the call now, but we are open to it. We're going to continue to evaluate it and do what's best from [indiscernible] (50:21) cost standpoint between those two instruments.
Okay, that's great. I'll leave it there. Thanks.
Thank you.
Your last question comes from Linda Ezergailis of TD Securities. Please go ahead.
Thank you. Just a cleanup question on your maintenance capital. Just curious what's driving the increase year-over-year. Do you have any facilities that have planned outages? And maybe you could give us some context as to what they are in which quarter. And then given that maintenance capital is going up in 2022, do we revert to a run rate beyond this year looking more like the last five years of CAD 20 million to CAD 35 million? Or do you expect due to inflationary factors that maybe there will be some sort of a discrete step-up beyond this year as well?
<: Hey, Linda, it's James. So, yeah, the maintenance CapEx in 2022 is going to be a little higher because we had a few turnarounds that we deferred from 2021 into 2022. We expect to do those between Q2 and Q3 of this year and obviously under our contracts, we're able to flow through the cost of those turnarounds to end use customers. So, we don't anticipate inflation being an issue.
Okay. Thank you. And as another follow-up, there is the potential for CP to go on strike mid-March. What impact might that have on your operations and how might you be able to mitigate that if they do go on strike, hopefully not for too long, but just give us a sense of how you're thinking about that?
Hi, Linda, it's Randy Toone. We use CP and so – but not – for a small part of our business. Most of our railcars are on CN. So, we do see it having a small impact, but we don't see it as a material impact and as we saw with other strikes with the railroads, they don't last very long.
Great. Thank you.
Ladies and gentlemen, this concludes the Q&A portion of today's call. I will now turn the conference back to Mr. McKnight. Please go ahead.
Thanks, Michelle. Thank you everyone once again for joining our call today and for your interest in AltaGas. And as a reminder, we will be available after the call for any follow-up questions that you might have. That concludes our call this morning. I hope you all enjoy the rest of your day. You may now disconnect your phone lines.