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Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the AltaGas Third Quarter 2021 Financial Results Conference Call. My name is Kelsey, 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 recorded.I would now like to turn the conference call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.
Thank you, Kelsey, and Good morning, everyone, and thanks for joining us today for AltaGas' Third Quarter 2021 Financial Results Conference Call.Speaking on the call this morning will be Randy Crawford, President and Chief Executive Officer; James Harbilas, Executive Vice President and Chief Financial Officer. And 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.In addition to the third quarter press release, financial statements and MD&A that were released earlier today, we've also published a third quarter earnings summary presentation. This presentation walks through the quarter and highlight some of the key variances and nonrecurring items that we would assume will be helpful for the market to understand and can be found on our website under the Events and Presentations section.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 questions that you might have. We will proceed on the basis that everyone has taken the opportunity to review the press release and our third quarter results.As for the structure of the call, we'll start with Randy Crawford, providing some comments on our third quarter financial performance and progress on our strategic priorities. Followed by James Harbilas, providing a more detailed walk-through of our financial results, near-term outlook and guidance. And then we'll leave plenty of time at the end for questions.Before we begin, we'll also remind everyone that we will refer to forward-looking information in today's call. This information is subject to certain risks and uncertainties as outlined in 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 the EDGAR and CR systems.And with that, I'll now turn the call over to Randy.
Thank you, Adam, and Good morning, everyone.AltaGas delivered strong third quarter results with normalized EBITDA growth of 15% year-over-year, and FFO growth of over 50% year-over-year, which reflects the durability of our diversified platform. Both the principal businesses executed well on major initiatives, and we continue to advance our opportunity set for our global export and utility businesses.Building on progress made in the first half of the year, we are well-positioned to meet our overall objectives for 2021 and beyond. Heading into the fourth quarter, we are well-positioned to achieve the high end of our guidance range, and we remain on target to reduce our net debt to normalized EBITDA ratio by up to 5.5x over the course of the year. At our midstream business, EBITDA increased approximately 60% versus the prior year comparable period, reflecting contributions from continued investment in our global export platform. Most notably, during this quarter, we achieved record liquefied petroleum gas export volumes that averaged approximately 105,000 barrels a day to Asia.The scaling of our platform also benefited our integrated network, resulting in an 11% year-over-year increase in gathering and processing volumes and a 15% year-over-year increase in fractionation and liquid handling. Our expanded midstream business continues to match our strong expectations as we remain steadfast in building a world-class platform that resolves -- revolves around global exports.We continue to leverage our industry-leading LPG export capabilities to realize significant operational and commercial synergies and benefit from implementing best practices across the combined platforms.In the third quarter, we shipped a record 18 VLGCs of North American propane and butane to markets in Asia. On average, RIPET shipped over 58,000 barrels a day of propane in the third quarter, setting a record for that terminal.At Ferndale, we exported over 42,000 barrels a day of combined butane and propane across 9 ships. This performance is a testament to the experience and hard work of our combined midstream teams and their ability to improve upon logistics to optimize the supply chain between the 2 facilities.In mid-October, we filed an application with the Canada energy regulator for a 25-year butane export license for up to 40,000 barrels a day of additional exports. This is a proactive step to ensure AltaGas and our partners are well-positioned to meet the needs of our customers on a long-term basis by continuing to connect the growing LPG production in Western Canada to global markets.Our well-positioned gas processing fractionation business, as I mentioned, continues to realize high single-digit to double-digit volume growth. Inlet gas processing volumes were up 11% year-over-year and fractionation and liquids handling volume increased 15% year-over-year in the third quarter.This strong growth highlights the strategic positioning of our Montney focused midstream platform and our alignment with leading well-capitalized producers who continue to execute long-term development plans in the basin.The utilities segment, excluding the onetime pension accounting adjustment in the third quarter of 2020 and the unfavorable impact of the Canadian U.S. dollar exchange rate, achieved normalized EBITDA increase of 5 million in USD terms. The results in a seasonally low throughput quarter reflect the strong execution of our strategic plan and leave us in a position to close the under earning GAAP and achieve our allowed return in 2022.During the quarter, we continued to execute on the company's various accelerated pipeline replacement program with an ongoing focus on replacing aging infrastructure to improve the safety and reliability of the system. Investment during the quarter but the year-to-date 2021 capital spend on accelerated investment to CAD242 million. Over time, these investments should reduce operating costs and emissions through leak reduction and drive better customer, environmental and social outcomes.Turning to headlines of natural gas shortages in Europe and the increased demand coming from Asia, we have seen a significant run up, both globally and domestically of natural gas prices. As a result, heading into 2021 and 2022 heating season, natural gas prices are meaningfully ahead of recent years.Fortunately, for this upcoming winter, AltaGas Utilities winter seasoned supply plan is designed to source slightly more than 50% of normal win -- winter gas throughput volumes from contracted storage services. Given that the bulk of the company storage was filled at much lower non-heating season prices, we expect that this position will partially shelter customers from some of the significant price moves that we are seeing and are expected in the market in the next few months.The energy transition is upon us and will have impacts across the energy value chain. However, as evidenced by the current global energy shortage and cascading negative pricing effects that are taking place across the world, we continue to believe in the role, benefits and reliability that responsibly sourced natural gas will provide to our customers as we embrace the energy transition. Our view on the transition is that natural gas and LPGs will remain critical pieces of the long-term global energy kitchen.We view AltaGas' role to be focused on reducing emissions across our operations and investing in energy evolution opportunities that leverage our unique asset base and further reduce the environmental footprint of our operations and those around us. We will also continue to advance initiatives around renewable natural gas and hydrogen. On the latter, we are pleased that the Maryland Public Service Commission approved our first RNG project, a partnership between WGL and Washington Suburban Sanitary Commission to transform sewage waste into renewable energy. This is our first foray into projects of this type, and it will enable AltaGas to refine and learn more about this promising technology so that we can identify other potential projects to expand the use of RNG in the years ahead.Through this evolution, we will advocate for our customers' long-term interest with a focus on safety, reliability and affordability.And with that, I will turn the call over to James to review the financial results in more detail.
Thank you, Randy, and Good morning, everyone. As Randy mentioned, we are pleased with the results that we delivered in the third quarter with continued execution on AltaGas' long-term strategic plan, positioning the company to drive further long-term stakeholder value creation. Normalized EPS of $0.02 in the third quarter of 2021 compared to $0.04 in the third quarter of 2020 positions AltaGas well to deliver on 2021 financial guidance. Normalized FFO per share of $0.61 in the third quarter of '21 compared to $0.40 in the third quarter of 2020, representing 53% year-over-year growth and continues to provide the foundation for increased returns of capital to shareholders and to fund ongoing organic expansion.Normalized EBITDA of $244 million in the third quarter of 2021 compared to $250 million in the third quarter of 2020, representing 15% year-over-year growth. Results reflected strong execution across the entire platform, particularly within the midstream segment, which demonstrated robust growth across the business. Normalized midstream EBITDA was $186 million in the third quarter 2021 compared to $114 million in the third quarter of 2020, representing a 63% year-over-year increase.Midstream results were positively impacted by approximately $20 million this quarter as a result of revenue recognized for an LPG export cargo that was loaded at the end of the third quarter at spot prices, but the offsetting hedge loss will not be realized until delivery at the destination point in the fourth quarter. As a result of this timing-related hedging loss, our EBITDA for Q3 2021 is roughly $20 million higher than we anticipated, and we would, therefore, expect a commensurate offset to the normalized EBITDA reported for the fourth quarter as it effectively had the impact of pulling revenue forward 1 quarter.Normalized EBITDA from our global exports business of $106 million increased $78 million year-over-year, driven by the Petrogas acquisition and record global export volumes from our 2 export facilities.Due to the previously mentioned timing related hedging loss, global exports EBITDA was approximately $20 million higher in the quarter. Our processing and fractionation business continues to be supported by strong fundamentals for natural gas and long-term Montney development plans as gas processing volumes were up 11% year-over-year, while fractionation and liquids handling was up 15% year-over-year.Other factors impacting midstream normalized EBITDA in the third quarter included higher revenue associated with the Harmattan cogeneration facility due to favorable Alberta power prices, offset by no AFUDC recognized for MVP as well as a lower contribution from Gordondale due to the blend and extend contract taking effect in 2021.We continue to actively derisk the midstream platform and reduce commodity price exposure and volatility where appropriate. In the third quarter, approximately 94% of our frac exposed volumes were hedged. We also remain well-hedged through the balance of the year with approximately 66% of fourth quarter global export volumes told or collectively hedged.This includes an average SEI to North American financial hedge price of approximately USD $12.64 per barrel for both propane and butane. We also have 95% of our expected frac exposed volumes hedged in the fourth quarter at $25.70.Normalized utilities EBITDA of $62 million in the third quarter of 2021 compared to $80 million in the third quarter of 2020. There was a $17 million pension accounting change that was realized in the third quarter 2020 that was not present this quarter, while the unfavorable move in the Canadian to U.S. dollar foreign exchange rate drove a further $4 million year-over-year decrease compared to the performance in the third quarter of 2020.WGL reported normalized EBITDA of $13 million compared to $32 million in Q3 2020. In addition to the previously mentioned pension accounting impact, the quarter included warmer weather in D.C., a $4 million negative impact from foreign exchange, which was partially offset by the positive impact of Maryland and DC rate cases and continued ARP investments.TEMCO and NSTAR's combined normalized EBITDA was $25 million in the third quarter, down $3 million from the same period last year due to warmer weather in Michigan, partially offset by colder weather in Alaska and slightly higher onetime costs and foreign exchange.And finally, normalized EBITDA from the retail energy marketing business was $23 million in the quarter, an increase of $3 million year-over-year, driven by higher gas margins due to favorable pricing and the timing of certain in the money hedge settlements in Q3, partially offset by lower power margins. The Corporate and other segment reported normalized EBITDA loss of $4 million compared to $19 million earned in the same quarter of 2020.The $23 million year-over-year decrease was driven by the combination of higher expenses related to employee incentive plans as a result of AltaGas' rising share price over the course of 2021, the monetization of Pomona Energy Storage and AltaGas rip in Energy Inc. in the third quarter of 2020 and the absence of recoveries related to the Canada emergency wage subsidy that were present in the third quarter of 2020.Depreciation and amortization expense for the third quarter of 2021 was $111 million compared to $108 million for the same quarter in 2020. The increase was mainly due to new assets placed in service and the consolidation of the Petrogas assets. Interest expense of $69 million was up slightly over last year's comparable period of $65 million as a result of modestly higher average debt balances, partially offset by lower average interest rates and a lower U.S. dollar to Canadian dollar exchange rate.Looking ahead, AltaGas continues to be focused on many of the same priorities the company has over the past 2.5 years. This includes executing on our long-term corporate strategy of building a diversified platform that operates long life energy infrastructure assets that are positioned to provide resilient and durable value for the company's stakeholders.AltaGas continues to focus on delivering durable and growing EPS and FFO per share while targeting lower leverage ratios and increasing margins of safety within the business over time. This strategy should support steady dividend growth and provide the opportunity for ongoing capital appreciation for its long-term shareholders. AltaGas is reiterating its 2021 increased guidance ranges that were provided in April 2021, which includes normalized EPS guidance is $1.65 to $1.8 per share. 2021 normalized EBITDA guidance is $1.475 billion to $1.525 billion. And AltaGas' 2021 capital expenditure plan is being reduced from $910 million to $850 million.The largest drivers for the reduction are lower forecasted utility spend, which is partly driven by a stronger Canadian U.S. dollar exchange rate, which reduces the cost of capital expenditures in Canadian dollar terms, and select midstream spending is now expected to roll over into early 2022 instead of 2021.The capital expenditures program remains heavily weighted towards a lower risk utilities business, and it's comprised primarily of ARP and system betterment projects that are anticipated to deliver stable rate base growth and strong risk-adjusted returns. These investments are directed at delivering improved long-term customer, safety and environmental outcomes.Finally, we are looking forward to hosting our first Investor Day over the past 5 years, which will be held virtually on December 15th. More details on this event will follow in the next few days.That concludes our prepared remarks, and we would be happy to turn it over to the operator for Q&A. Operator?
[Operator Instructions] Your first question comes from Rob Hope from Scotiabank.
First question is just on the 2021 guidance and you're reiterating kind of the upper end of the band. Just taking a look at Q4, are there anything specifically we should watch out for, just given the strong results year-to-date and I guess aside from that $20 million LPG headwind in Q4. It seems that the top end of the range is relatively conservative, unless there's some other things that are settling out in Q4?
Rob, it's James here. Yes. Look, I think that when you look at Q4 of 2020, and you try to extrapolate that into Q4 2021, there's a few things that contributed to 2020 results that are not going to repeat in Q4 of 2021. So you touched on, obviously, the hedge loss, which has already been telegraph. But we had AFUDC that we were recording on MVP in Q4 of 2020. That's not contributing anything in '21.We obviously sold the U.S. storage transportation business that contributed in 2020. There's FX headwinds, just given a higher exchange rate on the U.S. dollar front that also helped Q4 of 2020. And then obviously, on the retail side of the business, we do have higher PGM costs throughout 2021 relative to the comparative period in 2020. So those are some of the items that would probably push us a little bit lower than where we were in Q4 of 2020. But we still feel comfortable that the top end of our range is achievable.
I appreciate the color. And then just as we take a look out to 2022, FEI, propane pricing has been strong, but we've seen a real catch up in kind of North American propane benchmarks. How are you looking at that exposure and maybe speak to kind of the potential to kind of move more butane over propane in that year?
Yes. I mean, I can provide some comments and then maybe Randy Toone could jump in there, too. But I mean, if you look at propane spreads throughout 2021, we've really started to see them strengthen heading into Q4. And then when we look at the forward curve into 2022, the FEI at Mont Belvieu spreads almost $10.So we do expect some strength there, and we will start to actively hedge some of that position heading into 2022 as well. And for '21, we're already highly hedged, but we continue to layer in hedge our hedging program above the 65% that we exited Q3 at just given the strengthening in the curve.
And this is Randy Toone. We know North American LPG prices are high, especially heading into the winter. So it all depends on what kind of winter North America has. But FEI is always -- they're also going into winter, and we feel that the FEI will strengthen as well, and that margin will be there. I mean, from September 30 to probably yesterday, when I got the last report, we have seen the spread on propane expand by about $1 from an FEI in Mont Belvieu step -- dollar a barrel.
Your next question comes from David Quezada from Raymond James.
Maybe a question on the utility side of things. Could you discuss the commentary, I guess, in the MD&A about just the natural gas quality service standards? And will there be any costs associated with the efforts there?
David, this is Randy. I'll let Blue just make some comments on that. But with respect to the service levels, we've been working with our regulators and very proactive in our approach to addressing some of the shortcomings of our former service provider. And so we took very strong proactive actions, and we're trending to service levels that are at pre-pandemic level. So we're certainly addressing that directly. Blue, I'll let you go ahead and comment.
Yes. Thanks, Randy, and thanks, David, for your question. As Randy mentioned, we have been in regular communication with our commissions all the way through as we were aggressively transitioning from our original service provider to the new one. So it's always tough to predict that. We don't expect it will be anything that looks like in the read-through on the request, but it's always hard to say, but we feel very good about where we are and where we're headed and good conversations along the way. And we have weekly conversations with them, and they can see the progress. So we're quite optimistic on where that lands.
Great. That's helpful. And then maybe just one more for me. The RNG project that you announced. Just curious if there's any color you can provide on like the capacity or the cost -- capital cost in that project? And maybe some thoughts on what you think that RNG could represent on the utility side of your business longer term?
This is Randy. I'll let Blue make his comment, but we're still in the early days of executing the SG strategy, but we are preparing for the lower carbon energy system of the future. And this is just the first step in the direction in our announcement today, and there's going to be more, and we're going to continue to invest in reducing our carbon emissions intensity, which includes products to help our customers to do the same. But we'll let you comment specifically on the project.
Yes. Thanks, Randy. The scale of this one is not big. What it does provide is that first working relationship as we build out all of the materials transfer stations, meters, gas quality analyzers, pressure regulation, SCADA systems, odorization equipment, all those things that come through that RNG process, working with a very strong partner here.All of that gas stays in region, in fact, will be used for generation on-site for that particular facility. So it's really a win-win for the region and for us and for WSSC. As Randy mentioned, lots of other things going on in the hopper. So more to come. This one is really our dipping our toe in the water as we design, build those facilities and get comfortable on how to handle those type of opportunities.
Your next question comes from Patrick Kenny from National Bank.
[Audio Gap] export license. Would you be looking to expand capacity at RIPET and/or Ferndale to accommodate that incremental 40,000 barrels a day? What would that capital cost look like? The expected build multiple? And then from a timing perspective, when do you think you might receive regulatory approval and be in a position to have that incremental capacity in service?
This is Randall Crawford. A lot of exciting things happening in our midstream business and leveraging our export network throughout. And as I've mentioned in the past, there's significant opportunities for low-cost expansion opportunities as we continue to grow scale. I couldn't be more proud of the team, but they've used operations research, digitization to really optimize the system to move record volumes through this quarter. And we're being proactive in terms of our licensing and move more products into both of those facilities. So I think we feel optimistic about approval, and I'll let Randy add some commentary.
Yes. So the butane license like Randy says, is this kind of secures our future to be able to export butane. And right now, we're exporting butane out of Ferndale around 20,000 to 25,000 barrel a day. We do think that we can develop an expansion out at Ridley Island with our partner. And the timing of that is still yet to be determined, but we think we'll have regulatory approval here soon with our partners, and we can probably talk more about that in the coming future.
Okay. And you used the term proactive here to describe the application. I mean, perhaps you could just share some insights into the level of customer demand for this additional butane export capability, both from existing and prospective customers and perhaps which customers might be more inclined to support any capital investment needed upstream versus downstream?
Patrick, great question. We're seeing robust demand for our services in Asia on both the butane and propane front. So that clearly is a big opportunity as we continue to demonstrate our ability to consistently deliver clean burning energy into Asia. So I think what you're seeing as we look toward these expansion opportunities is to -- is it the direct market. We're reaching back and locking in longer term agreements.And so we're certainly moving forward with producer push and some firm long-term agreements with some of the larger producers in the basin to get them access to FEI pricing in global markets. But we're really seeing robust demand on the market side. And it goes to our strategy of reaching further with our ships or their upstream with our customers.
A quick follow-up on the supply push comment there. But would you need to expand any of your fractionation and liquids handling capabilities to support the higher butane export volume?
We continue to work toward touching the molecule throughout our innovated network, and we look at opportunities to do that. But clearly, the basin is oversupplied and that we can be able to move products from a variety of customer locations. And so yes, we would see expansion opportunities, and we think that we'll talk a little bit more about that on the Investor Day, but we source product, clearly from the Montney, but also into the Balkan in section through our customers. So tremendous opportunities to be able to give access to our customers to premium global markets. It really is a differentiating factor for us.
Next question comes from Dariusz Lozny from Bank of America.
Congratulations on the quarter. Just wanted to follow up on the capital shift that you announced. Just curious, as we look ahead into next year, how should we think about the mix between utilities and midstream? It sounds like perhaps it could be even more weighted towards utilities than it is in '21? And related to that, around your 8% utility rate base growth target. Should we be thinking about as we look out ahead over the next couple of years? Should we be thinking that, that would be a sequential 8%? Or could there be some variability in there perhaps from year-to-year?
Dariusz, it's James here. So with respect to your first question, the capital shift that we talked about or the reduction, obviously, that we discussed on the call was primarily driven -- the lion's share of it was driven just by the foreign exchange rate being lower relative to what we had said for the budget. So of the $60 million reduction, I'd say about $40 million of that was FX related. The balance was, obviously, us just shifting some midstream capital for turnarounds into early 2022 versus 2021.That being said, I don't anticipate that, that would materially shift the proportion of capital that we have earmarked in 2022 for utilities versus midstream. I still think that, that percentage is going to stay relatively stable as we head into 2022. With respect to your comments around growth rate, I mean, obviously, December 15th, we're going to be sharing a lot more information in terms of our rate base growth over the next little while. But we would expect the 8% that we've cited in the past is a CAGR. So you might see a little bit of variability, but that's what we would average in terms of rate base growth over the next 4 to 5 years.
Excellent. That's very helpful. And if I can stick with utilities for one more question. I think I heard at the opening remarks and maybe just a point of clarification that you are on track to exit '21 at a run rate of achieving your authorized ROE at the WGL utility specifically, but just maybe if you can clarify that? And maybe just talk about some of the efforts there on -- I know you discussed ARP, but also maybe on the OpEx side as well, if you could.
Sure. No. This is Randy. And as I've said in the prepared remarks, we are on track, and we intend to earn our allowed returns. And now I'll just give you some color on the opportunities ahead and that we think that there's just continued focus on optimization across our utility business. And that's what -- really what we do as a company is to look for those opportunities to bring efficiencies to the business. And of course, invest capital to take out cost and lower cost over time. And one of the great ways that the utility is doing it is the continued execution of our ATRP program. Because as you well know, not only does that have clean energy benefits through reduced emission, but it lowers operating costs, which will be I think a great offset to some of the inflationary pressures and keeping costs low for our customers.So our teams are committed to that. The digitization, the improvement of process, reduction of activities and the renovation and reinvention that's going on at our utility that Blue and his team are leading is very exciting. And as James has said, we get into some more detail in our Investor Day, and we're looking forward to it. But I think you'll see that they're well-positioned to continue the growth going forward.
Your next question comes from Linda Ezergailis from TD.
Just want to get some more understanding of how you're thinking about locking in some of the positive pricing that you're seeing in the forward markets as it relates not just to FEI spreads, but also your frac spreads. Can you talk about how your hedging approach might change? Is that all going into 2022? And the actual levels that you might have already locked in for 2022?
Yes, Linda, it's James here. Obviously, I think you touched on an important factor, which is significantly higher frac spread heading into 2022 than what we've seen in 2021. So we've already been out there hedging part of that and locking in that cash flow. I think we already addressed how we're approaching FEI to Mont Belvieu, given where we see Cal 22 right now. And obviously, on the freight side as well, and we've already started to lock in volumes. In terms of our approach to its, as we get visibility and certainty around supply volumes, as we get closer to 2022, that's where we start to layer in those hedges and protect those cash flows.So we'll update, obviously, the markets as we move through our reporting cycle with year-end, but we'd also probably have a little bit of an update at our Investor Day in terms of how we're going to approach that going forward. But typically, what we want to wait and do is get some certainty around supply, and then we'll go into the markets if we like where those spreads are to lock in those cash flows.
Okay. That's helpful. And just in terms of tolling, understanding that we'll probably get a more fulsome update at your Investor Day. But also, can you just help us understand what the sticking points might be for producers to commit to either your base capacity or potential expansions at RIPET? And when you might see some traction on that front?
Linda, this is Randy. Thank you for the question. It's a good question. And we're in constant discussions as the kind of consolidation that's going on in the basin with our larger producer customers. And clearly, I think as the pricing some of the environment has improved. I think that's actually looking toward longer-term commitments that our producers is something that we're having pretty extensive discussions on. And as you alluded to, we'll get into a bit more detail in our Investor Day about that. But I think that it's the continued execution by our team, which has been tremendous, is encouraging as well to our producer community.And so in terms of term and consistency, I think those are the types of things that are driving increased tolling. And it's a big driver for us. And I also alluded to Linda, that we're also seeing demand from the market as well for longer-term and to be able to reach back. So I think as you look at our -- us going forward as we continue to grow this business and derisk the platform, you're going to see a combination of both producers locking in longer-term as well as the market.
And maybe, well, just as a follow-up, while we're on the topic of tolling in contracts. Can you provide us with an update on Blythe and what the thoughts are at what point and at what levels that facility might be re-contracted and how the attributes around and sort of commercial arrangements might differ from what is in place currently?
Well, Linda, as you -- as I think you're aware it's under a current tolling agreement or 2 more, I believe, right, 2 more years, and that we're in discussions to extend that arrangement with the California Commission as well as the Southern California add in. So I think that, again, the key drivers there is that's a very critical asset into the grid in California. So again, I don't want to run those negotiations. But overall, I think you'll see a similar aspect of tolling for an extended term.
Your next question comes from Robert Kwan from RBC.
If I can just go back to guidance. And James, you listed a number of things that you saw as headwinds year-over-year. I'm just wondering, what are you seeing in terms of -- all those things were already baked into the Q3 results other than the $20 million hedge timing. Outside of that one piece, what -- are you seeing anything to be concerned or headwinds why just kind of rolling Q3 forward minus that hedge adjustment?
So when you say -- and I just want to clarify, Robert, when you say rolling Q3 forward in terms of basically reducing the positive contribution for the hedge and having the same kind of results on the midstream platform or just overall?
Yes, sorry. Yes, just -- yes, on the midstream platform. You listed a bunch of other things that I think you were just trying to frame for Q4. And I think almost all of those things were already baked into the Q3 year.
Yes. So I just -- so great question if you're just focusing on the midstream platform. I mean, obviously, the midstream platform moved 18 ships in Q3. And part of that was a bit of a spillover from ships that were Q2 that's kind of slipped into Q3. I think it's -- the capacity of the export facilities also increases in the summer months because we're able to move more product via pipeline out of the refineries into the Ferndale facility, which gives us the ability to move more export volume.So Q4, we don't expect to do 18 ships as a result of that. We're now relying again on rail. We don't have that pipeline capacity because the refineries are using that. But we would be looking to do 13 to 14 ships in the quarter, which would put us on track for the expected ships that we had for the entire year. So that is another factor that you can't just extrapolate Q3 into Q4 on the midstream side.
Okay. That's fair. And then just on the utilities, FX will be like year-over-year, with the seasonality, you can make the most sense, but you got the FX offset by or not offset, but -- and then on the positive side, that you've got new rate flash rate base. Anything else, obviously, whether it can be a swing, but anything else or has to think about on the utility side for Q4 '21?
Yes. I mean you touched on one. It was weather. That's definitely a risk. But the other one that I touched on in my response to an earlier question was just DGM charges on the retail side. They were a lot lower in Q4 of 2020 versus what they've been averaging throughout 2021 and Q4 is going to be a higher PGM charge on the retail business. So we will see some variability year-over-year as a result of that as well.
And I -- are you able to quantify what that year-over-year impact might look like?
Yes. I probably in the neighborhood of $15 million to $18 million.
Okay. That's great. I guess just to finish on just the NGL setup into 2022. And you touched on hedges. I guess just first, are you able just to quantify what the realized losses on the frac spread hedges were this year, i.e., what should reverse out into 22? And then the uncertainty on the volumes, are there any early thoughts? I know the NGL year is a little bit far out to talk about, but what -- anything just on the upcoming gas year and what extraction premiums might look like for 22 versus 21?
Do you want to comment on that one?
Sorry, Robert, it's Randy Toone here. So I can't comment on the frac hedge losses. But as far as volumes go, we're very confident we'll have similar frac spread barrels as we did in '21, it's close to 10,000 barrels a day. And that will be similar for 22. Are you talking about export volumes?
Well, you got comments or bill, but I was largely looking about what you think you can secure on the frac spread side of things. But if you've got comments as to what you might be seeing on the export volumes for '22 that would be great, too.
Yes. Sorry, Robert, it's James again. So are you looking for what we've already locked in in terms of hedges for '22?
Well, actually, the hedging question was just trying to -- like how much money have you lost on the frac spread hedges year-to-date, presumably, unless you've hedged again for 22 well below market, that stuff should all just reverse itself out if you've got similar volumes for next year.
So I mean if I understand your question, I think it was about $5 to $6 is what we had in Q3. And obviously, the frac spread heading into 2022 is higher than where we were in hedged for pretty much the entire 2021 calendar year. So we are hedging right now well above the $26 that we've been enjoying throughout 2021. I mean, we've seen frac spreads go out to about as high as $40. So right now, we're probably averaging closer to the low 30s in terms of some of the hedges that we've executed for 2022.
Okay. I can take that off-line. I guess, just, Randy, though, on the extraction premiums, so is there anything that we should we be expecting a material less than extraction premiums in 22 just given where frac spreads are?
No, we -- from where we have our extraction facilities, we won't be impacted by higher extraction premiums. I'm sure there will be, but it's not going to be material for us.
Next question comes from Ben Pham from BMO.
On WIGO and your comments around sheltering the commodity price over the next few months. I'm wondering if you can maybe comment on what percent of the commodity bills comprises the consumer bill. Also curious around, is there a lagged impact between earnings and recovering that commodity price and cash flows? And also, can you comment on historical sensitivity consumers to these higher gas prices in the past?
I'll let Blue address that.
So a couple of comments. One of the things about both our Washington Gas and our Semco utilities is about half of our flowing supply in the winter comes out of storage on a normal winter. And that, of course, that storage cost this year is materially lower than the winter strip. So that's a built-in protection for the customer base right out of the get-go. In terms of what percentage is the commodity of the overall bill, obviously, that varies by jurisdiction. Remember, for us, the commodity is just a pass-through, right? It's just a recovery.So obviously, you have a little bit of risk on higher bills, meaning a higher level of bad debt and collection and some of that. But overall, we expect the build to be up about 20% on an annualized basis due to commodity cost, all in, which is very consistent with what we're seeing nationwide. In terms of sensitivity to colder weather, again, you always get a little bit of energy efficiency that comes. It would have to be materially colder across the jurisdiction than what we've seen, we think have a big impact on throughput. But those are kind of the data points, if that helps.
Yes, it does. And I was also curious, more the consumer sensitivity in the past. And we've seen low gas prices for some time, but there's a period of time where gas prices were quite elevated. Are consumers pushing back a lot at that time? And also, it sounds like there's not really a huge lag impact. I mean, you recover your commodity price quite quickly. It's not a deferral mechanism where you recover over the next couple of years.
That's correct. Yes, that's right on the commodity recovery. That's right.
Okay. And maybe the consumer side of things, I mean, maybe not comment on historical, but are you hearing or expecting any pushbacks on this 20% increase?
No. Well, I mean, none of us like higher bills, right? So the good news is, I don't know that -- maybe that's the wrong term. The -- it's well covered in both the regional and national press in terms of energy prices across the country. And so it's not a surprise. We, too, of course, put out information and press releases to our consumers so they can plan accordingly. We also have energy efficiency programs, and we offer -- we help them winterize their home, to do some of those things, point them to energy assistance funds and those type of things. So we're very public about that opportunity as well.The other thing that we talk about that I think is understood may not be understood at the individual consumer level, but it's certainly understood at the commission level as while natural gas prices are up so is every other commodity. And when you look at the cost of actually heating a home for the winter, natural gas is still the lowest cost option compared to the other alternatives, which obviously include electric, home heating oil, propane, et cetera. It's still materially cheaper against all of those. So those things are all balancing points when we have those conversations at both the commissions and the consumer level.
Your next question comes from Andrew Kuske from Crédit Suisse.
I guess the question is for Randy, and it's more of a strategic bent, and it's really looking at the big picture perspective of the turnaround that you've already gone partway through, maybe not fully there for restoring all the value in the company. But when you look at the utility business, where you still have some ROE restoration, some CapEx catch up and some other stuff going on.And then the lumpiness on the midstream side, where you've had some incremental capital got deployed, big step-ups in EBITDA contributions. And then overall deleveraging of the company, like how do you think about just pace of growth and strategic positioning for AltaGas overall with the business mix that you have and just some of those underlying issues associated with the differences of the business?
Yes. No. Thank you for the question, Andrew. I appreciate it. As I've stated in the past, we remain focused on operating our long life infrastructure assets, right? We're committed to our long-term strategy and building a diversified utility and midstream business. And when I came here in December of '18, I talked about the restructuring, as you pointed out, and the enviable opportunity for growth that has helped for our company. And I would tell you that our diversified model and the strategy is working.We see it in our performance and our operational results as well as our performance in our stock price. So I think that as we sit here today, we're going to continue to remain focused on executing our strategy, de-risking, deleveraging and optimizing the amends upside that we have in both businesses. And so at this point, that's our primary focus, and I think it's working.
Appreciate that. And then I guess if we sort of sort of look back at RIPET, in particular and then what you've done with Ferndale thus far, you clearly ripped that there were some questions on that in the beginning, very validated. You can see that in your results. Do you think about the capital going towards that export-oriented business in, say, the next 3 to 5 years maybe accelerating and being able to be done faster than the past because of the validation of the strategy and just the outlook for the commodity in Western Canada.
Well, thank you for that. And I completely compare. I do be more excited about the opportunities that we have in front of us and what we've demonstrated. Randy and his team. We're fast becoming an energy logistics and export company, and the team has done an outstanding job to validate that model going forward. In terms of your question in the next few years, yes, I think you're going to see us continue to invest in increasing the scale of this business and locking in longer-term contracts with customers, both on an Asia and beyond. And so I think that you'll see that continue to accelerate. And we'll talk a little bit more, obviously, in the upcoming Investor Day. But yes, credit to the team.But again, I think the future is about moving this cleaner energy and fuels to Asia out of this tremendous Montney basin. And I think that we're also -- there's tremendous option value as you look ahead toward alternative fuels. And as we continue to move the cleaner LPG fuels into the future, we think we're well-positioned through our ports and access to move their fuels of the future as well. So again, we're going to continue to invest, increase that scale, and I think we're going to drive real value. I know we are to our customers into Canada as well.
Your last question comes from Robert Catellier from CIBC.
Yes, Robert Catellier from CIBC. I just wondered if you could elaborate on the com so it had in the MD&A, but the pace of activity recovery. Specifically the impact of the internal resolution between the government of B.C. and Blueberry River First Nations. And maybe you could also talk about the relatively modest statement retentions from the major producers in the B.C. Royalty review as well?
I’ll let Randy address you specifically with the Blueberry River?
Robert, yes. So the -- we've always had a very collaborative and strong relationship with the Treaty 8 members and -- and -- when we look at development, we've always took a balance between environmental and with economic needs. And when you look at the Treaty 8 and what they've publicly talked about was that they're not -- they don't want to stop development. They want to say in development. And I think AltaGas has always worked collaboratively with them to give them a say in how we develop.And so we're encouraged by some of the discussions they're having with the B.C. government, and we think that they're going to come up with a process going forward that we'll continue to have development because that resource is so valuable. And when we look at our customers, a lot of our customers have been proactive, and they already have permits in place, and some of our customers are not slowing down. And so we do still think that, that resource is going to be developed, and we think that we're in a good spot to work with our customers to help develop it.
And just the Royalty review, too early to tell, I know, but any indications of that causing any variability in drilling intentions?
Well, what we know about the royalty review is that they're taking a look at the process and seeing if they can make it simpler. And I do -- what we know is that they're looking quite a bit at the Alberta Royalty process, and we're very familiar with that. And so we're not worried that it's going to have a huge impact on, say, development in that area.
Okay. And I know quite early days, but there's an update to the B.C. climate plant. I wondered if you see any impact on that your business, specifically methane emission targets and requirements there. And also, there's some indications that the new projects have to have enforceable plans to meet net 0 2050. Do you see any immediate impact that you can talk to with respect to how you might develop the midstream business there?
Yes. We've took a look at the B.C.'s new climate plan. And when we look at our facilities, we're always looking at reducing our carbon footprint. And so we are looking at electrification of our facilities or carbon capture and working with our customers to do that. And we just don't think that, that's going to slow down anything. It's going to change the way you might develop.
Okay. That's fair. Last question for me. I wondered if you could -- there's a couple of comments about growth in G&A, both in the utilities and in the corporate side, I wonder if you could attribute that between just the growth you're seeing as an enterprise and the effects of inflation.
Yes. I think the growth in G&A and others, to a large extent, this quarter, related to accruals around long-term incentive. But overall, I think the growth in the cost is consistent with the growth in the business. And I think the team has done an excellent job of managing its cost and implementing the digitization and new technology for productivity overall. And I think that's generally in this quarter, it's particularly related to the long-term incentive plans.
This concludes the Q&A portion of today's call. I will now like to turn the call back over to Mr. McKnight.
Thanks, Kelsey, and thank you, everyone, once again for joining our call today and for your interest in AltaGas. And as a reminder, the Investor Relations team will be available after the call for any follow-up questions that you might have.That concludes our call this morning, and I hope everyone enjoys the rest of their day. You may now disconnect your phone lines.