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. All lines have been placed on mute to prevent any background noise. If you have any difficulties hearing the conference, please press star then zero for operator assistance at any time. After the speaker's remarks, there will be a question-and-answer session. As a reminder, this conference call is being broadcast live on the Internet and recorded. I would now like to turn the conference call over to Adam McKnight, Director, Investor Relations. Please go ahead, Mr. McKnight.
Thank you, Kelsey, and good morning, everyone. Thanks for joining us today for AltaGas's 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. 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 highlights some of the key variances and non-recurring items that we would assume will be helpful for the market to understand, and it can be found on our website under the Events and Presentation section. As always, today's prepared remarks will be followed by an analyst question-and-answer period. 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 walkthrough of our financial results, near-term outlook, and guidance.
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 two of our investor presentation, which can be found on our website and more fully within our public disclosure filings on both the EDGAR and SEDAR systems. 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 5.5 times 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 liquids handling. Our expanded Midstream business continues to match our strong expectations as we remain steadfast in building a world-class platform that 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 nine 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 two 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 and 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 platforms and our alignment with leading well-capitalized producers who continue to execute long-term development plans in the basin.
The Utility segment, excluding the one-time pension accounting adjustment in the third quarter of 2020 and the unfavorable impact of the Canadian/US dollar exchange rate, achieved normalized EBITDA increase of $5 million in US dollar terms. 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 gap and achieve our allowed return in 2022. During the quarter, we continued to execute on the company's various accelerated pipeline replacement programs with an ongoing focus on replacing aging infrastructure to improve the safety and reliability of the system. Investments during the quarter brought the year-to-date 2021 capital spend on accelerated investments to CAD 242 million. Over time, these investments should reduce operating costs and emissions through leak reduction and drive better customer, environmental, and societal outcomes.
Turning to the 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 season supply plan is designed to source slightly more than 50% of normal winter gas throughput volumes from contracted storage services. Given that the bulk of the company's 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 picture. 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 interests with a focus on safety, reliability, and affordability. 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 CAD 0.02 in the third quarter of 2021 compared to CAD 0.04 in the third quarter of 2020 positions AltaGas well to deliver on 2021 financial guidance. Normalized FFO per share of CAD 0.61 in the third quarter of 2021 compared to CAD 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 CAD 244 million in the third quarter of 2021 compared to CAD 213 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 CAD 186 million in the third quarter of 2021 compared to CAD 114 million in the third quarter of 2020, representing 63% year-over-year increase. Midstream results were positively impacted by approximately CAD 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 CAD 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 one quarter. Normalized EBITDA from our global exports business of CAD 106 million increased CAD 78 million year-over-year, driven by the Petrogas acquisition and record global export volumes from our two export facilities. Due to the previously mentioned timing-related hedging loss, global exports EBITDA was approximately CAD 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 de-risk 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 tolled or collectively hedged. This includes an average FEI to North American financial hedge price of approximately $12.64 US 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 CAD 62 million in the third quarter of 2021 compared to CAD 80 million in the third quarter of 2020. There was a CAD 17 million dollar pension accounting change that was realized in the third quarter of 2020 that was not present this quarter. While the unfavorable move in the Canadian to US dollar FX rate drove a further CAD 4 million year-over-year decrease compared to the performance in the third quarter of 2020. WGL reported normalized EBITDA of CAD 13 million compared to CAD 32 million in Q3 2020. In addition to the previously mentioned pension accounting impact, the quarter included warmer weather in DC, a CAD 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.
SEMCO and ENSTAR's combined normalized EBITDA was CAD 25 million in the third quarter, down CAD 3 million from the same period last year due to warmer weather in Michigan, partially offset by colder weather in Alaska and slightly higher one-time costs and foreign exchange. Finally, normalized EBITDA from the retail energy marketing business was CAD 23 million in the quarter, an increase of CAD 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 CAD 4 million, compared to CAD 19 million earned in the same quarter of 2020.
The CAD 23 million year-over-year decrease was driven by the combination of higher expenses related to employee incentive plans as a result of AltaGas's rising share price over the course of 2021, the monetization of Pomona Energy Storage and AltaGas Ripon 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 CAD 111 million, compared to CAD 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 CAD 69 million was up slightly over last year's comparable period of CAD 65 million as a result of modestly higher average debt balances, partially offset by lower average interest rates and a lower US 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 two and a half 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 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 include normalized EPS guidance is 1.65-1.80 per share. 2021 normalized EBITDA guidance is CAD 1.475 billion-CAD 1.525 billion. AltaGas's 2021 capital expenditure plan is being reduced from CAD 910 million to CAD 850 million. The largest drivers for the reduction are a lower forecasted utility spend, which is partly driven by a stronger Canadian US dollar exchange rate, which reduces the cost of capital expenditures in Canadian dollar terms. Select midstream spending is now expected to roll over into early 2022 instead of 2021.
The capital expenditures program remains heavily weighted towards the lower-risk utilities business, and it's comprised primarily of ARP and system betterment projects that are anticipated to deliver stable rate-based 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 five 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?
Thank you. Ladies and gentlemen, we will now conduct the analyst question-and-answer session. If you would like to ask a question, press the star, then the one on your telephone keypad. If you would like to withdraw your question, press the pound key. There will be a brief pause while we compile the Q&A roster. Your first question comes from Rob Hope from Scotiabank. Please go ahead.
Good morning, everyone. First question is just on the 2021 guidance, and you're reiterating kind of the upper end of the band. You know, 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 CAD 20 million LPG headwind in Q4, you know, it seems that the top end of the range is relatively conservative unless there's, you know, some other things that are settling out in Q4.
Rob, it's James here. Yeah, 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 gonna repeat in Q4 of 2021.
You touched on, obviously, the hedge loss, which has already been telegraphed. We had AFUDC that we were recording on MVP in Q4 of 2020 that's not contributing anything in 2021. We obviously sold the US storage transportation business that contributed in 2020. There's FX headwinds just given a higher exchange rate on the US dollar front that also helped Q4 of 2020. Then obviously on the retail side of the business we do have higher PGM costs throughout 2021 relative to the comparative period in 2020. You know, those are some of the items that would probably push us a little bit lower than where we were in Q4 of 2020. We still feel comfortable that the top end of our range is achievable.
I appreciate the color. Just as we take a look out to 2022, you know, FEI propane pricing has been strong, but we've seen a real catch up in kind of North American propane benchmarks. You know, how are you looking at that exposure? Maybe speak to kind of the potential to kinda, you know, move more butane over propane in that year.
Yeah. I mean, I can provide some comments and then maybe Randy Toone could jump in there too. I mean, if you look at propane spreads throughout 2021, you know, we've really started to see them strengthen heading into Q4. When we look at the forward curve into 2022, there's the FEI to Mont Belvieu spread is 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. For 2021, we're already highly hedged, but we continue to layer in our hedging program above the 65% that we exited Q3 at, just given the strengthening in the curve.
Yeah. This is Randy Toone. We, you know, we know North American LPG prices are high, especially heading into the winter. It all depends on what kind of winter North America has. 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 thirtieth to probably yesterday when I got the last report, we have seen the spread on propane expand by about $1 from an FEI to Mont Belvieu standpoint. $1 a barrel.
Appreciate that. All right. Excellent. Thank you.
Your next question comes from David Quezada from Raymond James. Please go ahead.
Yeah, thanks. Morning, everyone. 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?
Sure. Hi, David, this is Randy. I'll let Blue make some comments on that. With respect to the service levels, you know, we've been working with our regulators and very proactive in our approach to addressing some of the shortcomings of our former service provider. We took very strong proactive actions, and we're trending to service levels that are at pre-pandemic levels. We're certainly addressing that directly. Blue, I'll let you go ahead and comment.
Yeah. 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. You know, 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. We feel very good about where we are and where we're headed and good conversations along the way. We have weekly conversations with them and they can see the progress. We're quite optimistic on where that lands.
Great. Thank you for that. That's helpful. Maybe just one more from 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 on that project and maybe some thoughts on what you think that RNG could represent on the utility side of your business longer term.
Look, this is Randy. I'm gonna let Blue make his comment. You know, we're still in the early days of executing the ESG strategy, but we are preparing for the lower carbon energy system of the future. This is just the first step in that direction in our announcement today. There's going to be more, and we're gonna continue to invest in reducing our carbon emissions intensity, which includes products to help our customers to do the same. Blue, why don't you comment specifically on the project?
Yeah. 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, so transfer stations, zone meters, gas quality analyzers, pressure regulation, you know, 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. 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, more to come.
This one is really our dipping our toe in the water as we, you know, design, build those facilities and get counsel on how to handle those type of opportunities.
Excellent. Thank you for that. I'll get back in the queue.
Your next question comes from Patrick Kenny from National Bank. Please go ahead.
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? From a timing perspective, you know, when do you think you might receive regulatory approval and be in a position to have that incremental capacity in service?
Look, this is Randy Crawford. You know, a lot of exciting things happening in our midstream business, and leveraging our export network, you know, throughout. As I mentioned in the past, there's a significant opportunities for low-cost expansion opportunities as we continue to grow scale. I couldn't be more proud of the team, where they've used operations research digitization to really optimize the system to move record volumes through this quarter. We're being proactive in terms of, you know, our licensing and to move more products into both of those facilities. I think we'd be optimistic about approval, and I'll let Randy add some commentary.
Yeah, the butane license, like Randy says, is this kind of secures our future to be able to export butane. Right now we're exporting butane out of Ferndale around 20-25 thousand barrels a day. We do think that we can develop an expansion out at Ridley Island with our partner. 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. 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, you know, both from existing and prospective customers. Perhaps, you know, which customers might be more inclined to support, you know, any capital investment needed, upstream versus downstream.
Yeah. Hi, Patrick. Great question. We're seeing robust demand for our services in Asia, on both the butane and propane front. That clearly is a big, you know, opportunity as we continue to demonstrate our ability to consistently deliver clean burning energy into Asia. I think what you're seeing as we look toward these expansion opportunities is at the direct market. We're reaching back and locking in longer-term agreements. We're certainly moving forward with producer push and some firm long-term agreements with some of the larger producers in the basin to give them access to FEI pricing in global markets. We're really seeing robust demand on the market side.
It goes to our strategy of reaching further with our ships further upstream, with our customers.
A quick follow-up on the supply push comment there. 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, you know, touching the molecule throughout our integrated network, and we look at opportunities to do that. But clearly the basin is oversupplied, and that we can be able to move products, you know, from a variety of customer locations. Yeah, we would see expansion opportunities, and we think that we'll talk a little bit more about that on our Investor Day. But we source product, you know, clearly from Montney, but also through the Balzac and such, and through our customers. Tremendous opportunities to be able to give access to our customers to premium global markets. It really is a differentiating factor for us.
Got it. Thanks for that. I'll jump back in the queue.
Your next question comes from Dariusz Lozny from Bank of America. Please go ahead.
Hey, good morning. Thank you for taking my question and 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 2021. Related to that, around your 8% utility rate base growth target, should we be thinking that, as we look out ahead over the next couple of years, that would be a sequential 8%, or could there be some variability in there, perhaps from year to year?
Hey, Darius, it's James here. With respect to your first question, you know, 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 set for the budget. Of the CAD 60 million reduction, I'd say about CAD 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 would materially shift the proportion of capital that we have earmarked in 2022 for utilities versus midstream.
I still think that percentage is gonna stay relatively stable as we head into 2022. With respect to your comments around growth rate, I mean, obviously, December 15th, we're gonna 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 said in the past is a CAGR. You might see a little bit of variability, but that's what we would average in terms of rate base growth over the next 4-5 years.
Excellent. Thank you. That's very helpful. 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 2021 at a run rate of achieving your authorized ROE at the WGL utility specifically. Just maybe if you can clarify that and maybe just talk about some of the efforts there. 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 said in the prepared remarks, we are on track, and we intend to earn our allowed returns. I'll just give you some color on the opportunities ahead, that we think that there's just continued, you know, focus on optimization across our utility business. You know, that's really what we do as a company, is to look for those opportunities to bring efficiencies to the business. Of course, invest capital to take out costs and lower costs over time. One of the great ways that the utility is doing it is the continued execution of our ARP program.
Because as you well know, that not only does that have, you know, clean energy benefits through reduced emission, but it lowers operating costs, which will be, quite frankly, a great offset to some of the inflationary pressures, and keeping costs low, you know, for our customers. 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. As James had said, you know, we'll get into some more detail in our Investor Day, and we're looking forward to it. I think you'll see that they're well positioned to continue the growth going forward.
Excellent. Thank you. I'll leave it there and congrats again on the quarter.
Thank you. Appreciate it.
Your next question comes from Linda Ezergailis from TD. Please go ahead.
Thank you. Just wanna 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, if at all, going into 2022 and the actual levels that you might have already locked in for 2022?
Yeah, Linda, it's James here. You know, 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. 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 at 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, though, it's 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.
We'll update obviously the markets as we move through our reporting cycle and with year-end, but we'd also probably have a little bit of an update on at our Investor Day in terms of how we're gonna approach that going forward. Typically what we wanna 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. 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. I mean, we're in constant discussions as the, you know, kind of consolidation that's gone on in the basin with our larger producer customers. Clearly, I think, you know, as the pricing and some of the environment has improved, I think that's actually, you know, looking toward longer term commitments that our producers is something that we're having, you know, pretty extensive discussions on. And as you alluded to, we'll get into a bit more detail in our Investor Day about that. I think that it's, you know, the continued execution by our team, which has been tremendous, is encouraging as well to our producer community.
You know, in terms of term and consistency, I think those are the types of things that are driving increased tolling. It's a big driver for us. I also alluded to, Linda, that we're also seeing demand from the market as well for longer term and the ability to reach back. I think as you look at us going forward as we continue to grow this business and de-risk the platform, you're gonna see a combination of both producers locking in longer term as well as the market.
Thank you. Maybe just as a follow-up while we're on the topic of tolling and 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 recontracted and how the attributes around any sort of commercial arrangements might differ from what is in place currently?
Well, Linda, as I think you're aware, it's under a current tolling agreement for 2 more, I believe, right, 2 more years, and that we're in discussions, you know, to extend that arrangement with the California Commission as well as Southern California.
I think that, again, the key drivers there is that's a very, critical asset, into the grid, in California. Again, I don't wanna front run those negotiations, but overall, I think you'll see a similar aspect of tolling, for like an extended term.
Thank you. I'll jump back in the queue.
Your next question comes from Robert Kwan from RBC. Please go ahead.
Good morning. If I can just go back to guidance. 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, you know, all those things were already baked into the Q3 results other than the CAD 20 million hedge timing. Outside of that one piece, what are you seeing anything to be concerned or headwinds-wise, just kind of rolling Q3 forward minus that hedge adjustment?
When you say and I just wanna clarify, Robert, when you say rolling Q3 forward in terms of basically reducing the positive contribution from the hedge and having the same kind of results on the Midstream platform or just overall?
Yes. Sorry. Yeah, on the midstream platform.
Yeah.
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 number.
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 kinda slipped into Q3. I think 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. 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 'cause the refineries are using that.
We would be looking to do 13-14 ships in the quarter, which would put us on track for the expected ships that we had for the entire year. That is another factor that you can't just extrapolate Q3 into Q4 on the Midstream side.
Okay. That's fair. Just on the utilities, FX will be. Like year over year with the seasonality, it can make the most sense. You got the FX offset by, or not offset, and then on the positive side that you've got, you know, new rates, rate base. Anything else? Obviously, weather can be a swing, but anything else for us to think about on the utility side for Q4 2021?
Yeah. I mean, you touched on one. It was weather. That's definitely a risk. The other one that I touched on in my response to an earlier question was just PGM charges on the retail side. They were a lot lower in Q4 of 2020 versus what they've been averaging throughout 2021. 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. Quarter over.
Are you able to quantify what that year-over-year impact might look like?
Yeah. I probably in the neighborhood of CAD 15 million-CAD 18 million.
Okay. That's great. Thanks. I guess just to finish on just the NGL set up 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 2022? 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 anything just on the upcoming gas year and what extraction premiums, you know, might look like for 2022 versus 2021.
Wanna comment on that, Randy?
Sorry, Robert. It's Randy Toone here. So, I can't comment on the frac hedge losses, but as far as volumes go, you know, we're very confident we'll have similar frac spread barrels as we did in 2021. It's close to 10,000 barrels a day, and that will be similar for 2022. Or are you talking about export volumes?
I was largely looking about what you think you can secure on the frac spread side of things. If you've got comments as to what you might be seeing on the export volumes for 2022, that'd be great too.
Yeah. Sorry, Robert, it's James again. Are you looking for what we've already locked in in terms of hedges for 2022?
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 2022 well below market, that stuff should all just reverse itself out if you've got similar volumes for next year.
I mean, if I understand your question, I think it was about, you know, CAD 5-CAD 6 is what we had in Q3. Obviously the frac spread heading into 2022 is higher than where we were hedged for pretty much the entire 2021 calendar year. We are hedging right now well above the CAD 26 that we've been enjoying throughout 2021. I mean, we've seen frac spreads go out to about as high as CAD 40. 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 offline. I guess just Randy, though, on the extraction premiums, should we be expecting a material lot less extraction premiums in 2022, just given where frac spreads are?
No, 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 gonna be material for us.
Perfect. Thank you.
Your next question comes from Ben Pham from BMO. Please go ahead.
Hi. Thanks. Good morning. On WGL and your comments around sheltering the commodity price over the next few months, I'm wondering if you can maybe comment on what % of the commodity bill comprises the consumer bill. Also curious around, is there the outright impact between earnings and recovering that commodity price in cash flows? And also, can you comment on historical sensitivity of consumers to these higher gas prices in the past?
I'll let Blue address that.
Yeah. Hi, Ben. 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. That, of course, storage cost this year is materially lower than the winter strip. 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. Obviously you have a little bit of risk on, you know, higher bills, meaning a higher level of bad debt in collection and some of that.
Overall, we expect the bill 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 know, 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 that would put impact on throughput. Those are kind of the data points, if that helps.
Yeah, it does. I was also curious about the consumer sensitivity in the past. I mean, we've seen low gas prices for some time, but there's a period of time where gas prices were quite elevated, where consumers pushing back a lot at that time. 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. Yeah, that's right on the commodity recovery. That's right.
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?
Yeah. Well, I mean, none of us like higher bills, right? The good news is, I don't know, that maybe that's the wrong term. 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, you know, help them, you know, winterize their home, do some of those things, point them to energy assistance funds and those type of things. We're very public about that opportunity as well.
You know, 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, is while natural gas prices are up, so is every other commodity. 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, you know, home heating oil, propane, etc. It's still materially cheaper against all of those. You know, those things are all balancing points when we have those conversations at both the commissions and the consumer level.
All right. That's great. That's very helpful.
Your next question comes from Andrew Kuske, from Credit Suisse. Please go ahead.
Thanks. Good morning. 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, you know, the turnaround that you've already gone partway through, maybe not fully there for restoring all the value in the company. 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, you know, 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?
Yeah, no. Thank you for the question, Andrew. Appreciate it. As I've stated in the past, we remain focused on operating our long-lived infrastructure assets, right, that we're committed to our long-term strategy, building a diversified utility and midstream business. When I came here in December 2018, I talked about the restructuring, as you pointed out, and the enviable opportunity for growth that I felt for our company. I would tell you that our diversified model and strategy is working. You can see it in our performance and our operational results as well as our performance in our stock price. I think that, you know, as we sit here today, we're gonna continue to remain focused on executing our strategy, de-risking, deleveraging and optimizing the immense upside that we have in both businesses.
At this point, that's our primary focus, and I think it's working.
Appreciate that. I guess if we just sort of look back at RIPET in particular, and then what you've done with Ferndale thus far. You know, clearly RIPET, there are 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 3-5 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, no, thank you for that. I completely concur. I couldn't 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. 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 in Asia and beyond. I think that you'll see that continue to accelerate. We'll talk a little bit more, obviously, in the upcoming Investor Day. Yes, credit to the team.
I think the future is about moving this cleaner energy and fuels, you know, to Asia out of this tremendous Montney Basin. Also, there's tremendous option value as you look ahead toward alternative fuels. 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 the fuels of the future as well. Again, we're gonna continue to invest, increase that scale, and I think we're gonna drive real value, I know we are, to our customers and to Canada as well.
Okay. Thanks, Randy.
Appreciate it. Thank you.
Your last question comes from Robert Catellier from CIBC. Please go ahead.
Yeah. Robert Catellier, CIBC. I just wondered if you could elaborate on the comments you had in the MD&A about the pace of activity recovery, specifically the impact of the interim resolution between the government of BC and the Blueberry River First Nations. Maybe you could also talk about the relatively modest stated drilling intentions from the major producers and the BC royalty review as well.
I'll let Randy address, you know, specifically with the Blueberry River.
Yeah. Hi, Robert. Yeah, so you know, we've always had a very collaborative and strong relationship with the Treaty 8 First Nations members. When we look at development, we've always took a balance between environmental and with economic needs. When you look at the Treaty 8 and what they've publicly talked about was that they're not they don't wanna stop development. They want a say in development. I think AltaGas has always worked collaboratively with them to give them a say in how we develop.
You know, we're encouraged by some of the discussions they're having with the BC government, and we think that they're gonna come up with a process going forward that will continue to have development because, you know, that resource is so valuable. When we look at our customers, you know, a lot of our customers have been proactive, and they already have permits in place, and some of our customers are not slowing down. We do still think that that resource is gonna be developed, and we think that we're in a good spot to work with our customers to help develop it.
Just the royalty review, too early to tell, I know, but any indications that's causing any variability in drilling intentions?
What we know about the royalty review is that they, you know, they're taking a look at the process, and seeing if they can make it simpler. What we know is that they're looking quite a bit at the Alberta royalty process and, you know, we're very familiar with that. We're not worried that it's gonna have a huge impact on, say, development in that area.
Okay. I know it's quite early days, but there's an update to the BC climate plan. I wondered if you see any impact on that to your business, specifically methane emission targets and requirements there. Also there's some indications that the new projects have to have enforceable plans to meet net zero 2050. Do you see any immediate impact that you can talk to with respect to how you might develop the midstream business there?
Yeah, we've took a look at the BC's new climate plan. You know, when we look at our facilities, we're always looking at reducing our carbon footprint. We are looking at electrification of our facilities or carbon capture and working with our customers to do that. You know, we just don't think that that's gonna slow down anything. It's just gonna change the way we might develop.
Okay. Fair enough. Last question from me. I wondered if you could... There's a couple comments about growth in G&A, both in the utilities and in the corporate segment. I wonder if you could, you know, attribute that between just the growth you're seeing as an enterprise and the effects of inflation.
Yeah. I think the growth is, you know, in G&A and others is to a large extent this quarter related to accruals around long-term incentive. Overall, I think the growth in the cost is consistent with the growth in the business. I think the team's done an excellent job of managing, you know, its cost and implementing the digitization, new technology for productivity overall. I think that's generally, you know, in this quarter it's particularly related to the long-term incentive plans.
Okay, fantastic. Thank you.
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. Thank you everyone, and once again for joining our call today and for your interest in AltaGas. 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.