AltaGas : Q3 2020 Conference Call Transcript

FINAL TRANSCRIPT

AltaGas Ltd.

Third Quarter 2020 Financial Results Conference Call

Event Date/Time: October 29, 2020 - 10:00 a.m. E.T.

Length: 64 minutes

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CORPORATE PARTICIPANTS

Adam McKnight

AltaGas Ltd. - Director, Investor Relations

James Harbilas

AltaGas Ltd. - Executive Vice President and Chief Financial Officer

Randy Crawford

AltaGas Ltd. - President and Chief Executive Officer

Randy Toone

AltaGas Ltd. - Executive Vice President and President, Midstream

Blue Jenkins

AltaGas Ltd. - Executive Vice President & President, Utilities and President, Washington Gas

CONFERENCE CALL PARTICIPANTS

David Quezada

Raymond James - Analyst

Rob Hope

Scotiabank - Analyst

Analyst

J. P. Morgan - Analyst

Julien Dumoulin‐Smith

Bank of America - Analyst

Ben Pham

BMO - Analyst

Linda Ezergailis

TD Securities - Analyst

Andrew Kuske

Credit Suisse - Analyst

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Robert Kwan

RBC Capital Markets - Analyst

Robert Catellier

CIBC Capital Markets - Analyst

Elias Foscolos

Industrial Alliance - Analyst

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PRESENTATION

Operator

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the AltaGas Third Quarter 2020 Financial Results Conference Call. My name is Kenzie, and I will 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 *, then 0 for Operator assistance at any time.

After the speakers' 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.

Adam McKnight - Director, Investor Relations, AltaGas Ltd.

Thanks, Kenzie. Good morning, everyone. Thank you for joining us today for AltaGas's third quarter 2020 financial results conference call.

Speaking on the call this morning will be Randy Crawford, President and Chief Executive Officer, and James Harbilas, Executive Vice President and Chief Financial Officer. We're also joined here this morning by Randy Toone, Executive Vice President and President of our Midstream business; Blue Jenkins, Executive Vice President and President of our Utilities business and Washington Gas; 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 have also published two investor presentations. The first is our regular October

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monthly investor presentation, which includes a refresh of our regularly disclosed information and incorporates our third quarter results.

The second presentation is a Q3 earnings presentation, which walks through the quarter and highlights some of the key variances and one‐time items that we would assume will be helpful for the market. We'll refer to the latter presentation at some points in our prepared remarks, and both are available on our website under Events and Presentations.

As always, today's prepared remarks will be followed by an analyst question‐and‐answer period, and we'll remind everyone that we will be available after the call for any follow‐up or detailed modelling questions.

We'll proceed on the basis that everyone has taken the opportunity to review the press release and our third quarter results.

And before we begin, we'll also remind everyone that we will refer to forward‐looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward‐looking information disclosure on Slide 2 of our investor presentations, which can be found on our website and more fully within our public disclosure filings on both SEDAR and EDGAR.

For the structure of the call, we'll start with James Harbilas walking through the financial results and our near‐term outlook, and then we'll turn it over to Randy Crawford to review some strategic and other focus points, and then we'll leave plenty of time for a Q&A session at the end.

And with that, I'll now turn the call over to James.

James Harbilas - Executive Vice President and Chief Financial Officer, AltaGas Ltd.

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Thanks, Adam, and good morning, everyone. Looking at the financial results for the quarter, our diversified business model once again delivered strong and stable results and leaves us on track for a solid year, despite the large economic disruptions that have taken place due to the global pandemic.

Normalized EBITDA was $213 million compared to $173 million for the same quarter last year, representing a 23 percent year‐over‐year increase. These results continue to reflect the stability and resiliency of our business, strong execution from our operating teams, and tight ongoing cost management.

We also had a couple of one‐time items impacting our results in Q3 2020 and Q3 2019, which we have laid out in more detail in Slides 7 to 10 of the Q3 2020 Investor Presentation that Adam mentioned earlier. We realize that everyone has slightly different normalization practices, and hopefully these slides provide additional colour on run rate, financial performance, and core factors that impacted results across each of our divisions and on a consolidated basis.

Excluding the $40 million loss of normalized EBITDA associated with the 2019 asset sales, the 2019 unfavourable impact to the third quarter of 2019 results associated with the Virginia Hearing Examiner's Report and the $21 million favourable impact to our third quarter 2020 financial results associated with the pension accounting policy change at Washington Gas, our third quarter adjusted run rate EBITDA increased 19 percent year over year within our core businesses.

Our Utilities business continues to deliver the stable and resilient results that we and our stakeholders expect, despite the ongoing economic challenges associated with COVID‐19. If you recall, more than 70 percent of our utility customers are residential, and approximately 70 percent of earnings are protected through decoupling and fixed building charges.

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Additionally, all our jurisdictions-Washington D.C., Maryland, Virginia, Alaska, and Michigan- have the approval for the creation of regulatory assets for the recovery of any incremental COVID‐19‐ related costs.

In our Midstream segment, operations remain strong. RIPETs volume was up again quarter over quarter to a new record of 42,700 barrels per day of Canadian propane exported to Asia, despite being impacted by unexpected downtime due to third‐party terminal and supply chain challenges. And volumes within our Northeast BC assets continue to see positive growth associated with the recent expansions, and we believe we remain geographically advantaged.

Normalized net income for the third quarter was $12 million or $0.04 per share, up considerably from a net loss of $62 million in Q3 2019 or $0.22 per share.

In addition to the strong year‐over‐year growth in EBITDA, net income also benefitted from lower interest expense, which was partially offset by modestly higher depreciation and amortization expense and a lower income tax recovery.

Interest expense was down $27 million year over year to $65 million in the quarter on lower debt balances and lower interest rates compared to 2019.

Depreciation and amortization expense increased modestly by $4 million year over year due to new assets being placed into service in Northeastern BC, which was partially offset by fixed asset provisions we recorded in the last quarter of 2019.

And finally, we recorded an income tax recovery of $13 million in the quarter, compared to a recovery of $34 million in the same quarter last year. The decrease is mainly due to the absence of tax recoveries related to asset sales that took place in the third quarter of 2019.

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Normalized funds from operation were up $45 million year over year to $112 million, or $0.40 per share, due to lower current interest expense and higher EBITDA, which was partially offset by higher income tax expense.

Third quarter Utilities segment normalized EBITDA increased $65 million year over year to $80 million. If we adjust for asset sales, the one‐time impact of the Virginia Hearing Examiner's Report on Q3 2019 results, and the one‐time impact of the pension accounting policy change on our Q3 '20 results, the Utilities segment run rate EBITDA would have increased by more than 40 percent.

Growth in the base business was driven by our 2019 settled rate cases, continued ARP spending, strong operational execution, and cost management, which were only modestly offset by COVID‐19‐ related impacts, including lower margins in our retail business.

At the regulated utilities, WGL's normalized EBITDA was approximately $32 million for the quarter, up $67 million year over year. Excluding the one‐time adjustments I previously mentioned, the increase is due to higher revenue from the Maryland and Virginia rate cases, which added $6 million in the quarter; higher accelerated pipe replacement program spending, which added $4 million the quarter; and lower operating costs of $11 million, which highlighted ongoing cost discipline and the execution of our operational excellence model. The latter included an 8 percent year‐over‐year reduction in leaks in the quarter.

In Michigan, SEMCO contributed $15 million to normalized EBITDA in the third quarter, up $2 million year over year, due to colder weather and lower operating expenses.

ENSTAR and CINGSA contributed $14 million of normalized EBITDA for the quarter, compared to $10 million for the same quarter last year. The increase is the result of lower costs and higher fixed storage service revenue, slightly offset by lower customer usage.

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Finally, normalized EBITDA from the retail business was $20 million, which is slightly lower than the same period last year, due to lower margins associated with COVID‐19. And while margins within our retail business continue to be down year‐over‐year basis, they have shown much improvement from the lows of the second quarter, and we believe will continue to improve from here.

Our Midstream business continues to deliver strong results despite the economic challenges across the industry. We continue to see healthy throughput volumes across our network, including continued ramp‐up in our Northeastern BC facilities, and we believe that that should continue in the coming quarters.

Midstream's third quarter normalized EBITDA was $114 million. Excluding the $11 million of lost EBITDA associated with the 2019 sale of Central Penn, our core Midstream business grew by approximately $3 million year over year.

RIPET generated approximately $23 million of normalized EBITDA on record exports of nearly 43,000 barrels to Asia, spread across seven‐and‐a‐half ships. While export volumes continue to show sequential growth, they were slightly behind our expectations due to a rail outage and issues within our supply chain. These challenges are expected to modestly spill over into the fourth quarter. However, we continue working with our third‐party logistics partners to ensure they are not repeated in the future.

RIPET's third quarter results were also impacted by price volatility in the Asian spot market during the quarter. Positively, FEI pricing and the FEI‐to‐Mont Belvieu spread rose throughout the quarter, and the rising spot price also pulling the back end of the curves higher with the Cal 2021 FEI‐to‐Mont Belvieu strip now in the low nines. Our tolled volumes also increased more than 20 percent on a sequential basis due to volume ramp‐ups from key customers during the quarter.

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The Northeastern BC assets continue to show positive volume growth, reflecting the ramp‐up of customer volumes associated with the expansions that we placed into service earlier this year, which is a trend that we expect to continue into the fourth quarter and into 2021. As we have said in the past, we continue to believe that our platform is positioned for where the market is headed.

Fractionation and liquids handling volumes were up at North Pine and our Northeastern BC facilities, which more than offset slightly lower inlet volumes at Harmattan and Younger. Gas processing volumes also increased at our Townsend deep‐cut facility and Nig Creek, and we had higher inlet volumes at Gordondale. These were partially offset by slightly lower volumes at Younger, due to a turnaround in September, and slightly lower inlet volumes at JEEP and PEEP.

We realized an average frac spread of $16 per barrel in the third quarter and had more than 10,000 barrels per day hedged at an average price of approximately $27 per barrel, excluding basis differentials.

During the third quarter, we reported equity earnings of $6 million from Petrogas, and as we messaged a couple of weeks ago, we plan to consolidate Petrogas upon closing our most recent increase in our investment into the Company.

Our $900 million self‐funding 2020 capital program remains intact, with approximately 75 percent to 80 percent directed towards the Utilities business. We continue to maintain significant financial flexibility, with AltaGas's excess liquidity expected to exceed $3.6 billion at 2020 year‐end.

Overall, we are very pleased with our third quarter results and are reiterating 2020 guidance ranges of normalized EBITDA of $1.275 billion to $1.325 billion and normalized EPS of $1.20 to $1.30 per share.

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And with that, I would now like to turn the call over to Randy to discuss some additional key components of our forward strategy and outlook for the coming period. Randy?

Randy Crawford - President and Chief Executive Officer, AltaGas Ltd.

Thank you, James, and good morning, everyone. As we close this chapter on another quarter, I'm proud of our team and what we have accomplished as we execute on the near‐term priorities that we laid out coming into the year.

Although the third quarter continued to include economic disruptions due to the global pandemic and other short‐term challenges, we remain steadfast in refocusing and de‐risking the business. We are taking purposeful steps to build a resilient and durable platform that is positioned to build a sustainable and successful future.

As James highlighted, our third quarter financial results continue to illuminate the resilience of our business platform and its ability to provide the predictable and reliable performance that we and our stakeholders expect. Even with the large economic challenges, our third quarter run rate EBITDA increased by 19 percent year over year, after adjusting for one‐time items.

Within our Utilities segment, we continue to make strong progress towards our operational excellence model while continuously evaluating the safety and reliability of our operations and attaining our allowed returns.

As shown on Slide 8 of our third quarter earnings presentation, our Utilities run rate EBITDA was up approximately 40 percent on a year‐over‐year basis. Washington Gas had another strong quarter of performance as we continued to deliver on cost‐reduction initiatives and accelerated pipeline replacement that we had previously outlined.

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Leaks were down double‐digit percentages on a year‐over‐year basis again this quarter, with year‐to‐date leaks at Washington Gas down 11 percent versus 2019.

Our data‐driven, predictable model has provided the ability to more intelligently deploy capital to drive down operating costs and improve our overall service.

O&M costs came in even better than we expected across almost all categories and reflects our improved focus on system reliability, ongoing upgrades, and ARP spending. We also had a large pension cost adjustment in the quarter that will also reduce pension costs modestly in the coming quarters and years.

As we have said all year, we remain focused on improving the customer value proposition by providing lower costs, higher reliability, and we continue to expect that this strategy will continue to generate significant customer and shareholder value over the coming years.

In addition to the improvements we've seen at Washington Gas, we also witnessed steady execution at SEMCO, ENSTAR, and CINGSA, with each utility providing steady operating performance that benefits our customers while providing the appropriate rates of return for our shareholders.

In our Midstream segment, we achieved record volumes out of RIPET by exporting an average of approximately 43,000 barrels a day of Canadian propane to Asia, moving us closer towards our goal of reaching our 50,000‐barrels‐a‐day 2020 exit rate.

Tolled volumes through the facility increased more than 20 percent on a sequential basis, and demonstrates our value proposition to provide access to premium LPG market in Asia for North American producers and aggregators.

Our Northeast BC assets have continued to show positive volume and margin improvements, which reflect ramping customer volumes and is a trend we expect to continue over the coming period. As

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we have said in the past, we continue to believe that our strategy to provide producers and aggregators increased access to global markets significantly enhances our midstream value proposition. As such, we believe that we are well positioned for where the market is headed over the next three to five years.

Our Midstream business also added two notable long‐term customers joined us subsequent to the quarter, including the addition of ConocoPhillips through its acquisition of Kelt Exploration's Inga, Firewood, and Stoddard assets; Canadian Natural Resources, through its acquisition of Painted Pony Petroleum. In new agreements, a global energy company that is focused on LNG exports at Townsend and North Pine.

Conoco, Canadian Natural, and the global energy company are industry leaders that have long track records for relentless execution. We are fortunate to add them as long‐term customers, and we look forward to working alongside them to achieve their long‐term goals in the Montney.

Following these transactions, approximately 87 percent of our expected normalized 2020 EBITDA will be generated from our regulated utilities and investment‐grade counterparties.

As we said two weeks ago at the time of the announcement, we are also excited with the opportunity to continue the advancement of our global export strategy through our planned increase in our ownership in Petrogas. The acquisition is aligned with our midstream strategy and complements AltaGas's existing operations. The transaction provides AltaGas with operational responsibility, a strategic asset that, along with RIPET and our existing midstream assets, provides scale and the ability to focus on the best of both businesses to capture efficiency and improve gross margins that will accrue to shareholders and customers. It also advances our corporate focus on building a diversified, low‐risk, high‐ growth utilities and midstream businesses that is building a resilient, durable, and compounding value to our stakeholders.

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On a run‐rate basis, we anticipate that this transaction will be approximately 10 percent accretive to earnings per share, approximately 15 percent accretive to cash flow per share, while improving our pro forma run rate leverage metrics, despite being entirely debt financed. The acquisition will consolidate AltaGas's ownership and strategic assets that we know well and are positioned to optimize for the benefit of our company and the broader North American energy industry.

We also remain constructive on the outlook for LPGs in Asia. Although there was some choppiness in the spot market at points in the third quarter, prices for propane and butane have been on a steady rise over the past few months and are pulling the backend of their respective strips higher.

Marked demand increases are being seen across the Asian market over the past few months as these economies reopen. Economic activity returns and population mobility rises. Global petrochemical feedstock demand will also rise sharply in the second half of '20, which will again be led by Asia, and these core demand trends should remain positive into 2021.

As we approach the final months of 2020, we remain confident in achieving the goals we set out in December of 2019 despite the macro headwinds throughout the year. We are maintaining our 2020 outlook for expected normalized EBITDA in the range of $1.275 billion to $1.325 billion and normalized net income from $1.20 to $1.30 per share. We believe this is a testament to the resiliency of our diversified business and the purposeful actions we've taken over the past 18 to 24 months, and you can expect the same from us in the years ahead.

Now before we open the lines to Q&A, I wanted to take the opportunity to discuss one item that we received several inbounds over the past couple of months, and we believe it is appropriate to address them in an open and candid manner. This is the idea around AltaGas potentially evaluating a corporate

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split into one pure‐play utilities entity and another pure‐play midstream platform. The acquisition of Petrogas further positions the Company for those options.

Since joining AltaGas, I have always said that we would be focused on creating value. And to be clear, in some ways, we're agnostic to how we achieve that feat. And you'll find that same view is shared with the entire senior management team. We are unwavering in our view that we need to do the right thing for our shareholders and broader stakeholders. However, we are still in the early days of executing the strategy that we laid out last year. It is critical that we integrate this business with our own. Until we do, we are not going to consider that option.

There is no doubt that the increased ownership in Petrogas further distinguishes AltaGas. It makes us larger and more attractive due to our unique value chain. Once we have fully integrated Petrogas and the world returns to somewhat of a sense of normalcy, it is certainly an option that is worth consideration. But what we want to avoid right now is allowing any sort of poverty of attention to arrive on the task at hand.

We are excited to take operational responsibility for the Petrogas assets in conjunction with AltaGas. The opportunities and options are plentiful, and the ability to grow the Midstream into something even more unique is our number‐one priority. There is simply no better way to generate for our shareholders. And while we are immensely proud of what we have accomplished in the past 18 to 24 months, more work is left to be done, and everyone here looks forward to finishing that work.

We're also not of the view that the discount in our evaluation is entirely underpinned by a single factor. We need to de‐risk the business in multiple ways, including continuing to deleverage the balance sheet. We believe there is a uniqueness in our diversified model in that, despite the industry‐leading, rate‐ based growth that is in front of us, we believe that we are in a position to be able to internally fund the

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equity portion of this growth on a self‐funded basis through the harvesting of the excess free cash flow that will come from our strong Midstream business. This is unique, as operating a self‐funding model is a rarity for most growing utilities.

So hopefully, that gives you some idea of how we are thinking about the path forward. We are all about adding value. The timing is important, and we will be purposeful in the actions we choose. Any actions also need to follow a well‐defined strategy that we have laid out. But over the journey to achieving operational excellence, we will continuously be evaluating what other levers we may want to pull and in what sequence they may best be actuated.

And with that, I'll turn the call back to the Operator to open the line for Q&A.

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 * then the number 1 on your telephone keypad. If you would like to withdraw your question, press the # key. There will be a brief pause while we compile the Q&A roster.

Your first question comes from the line of David Quezada with Raymond James. Please go ahead. David Quezada - Raymond James

My first question here, just on RIPET. Wondering if there's any colour you can provide on the supply chain issues. And I know you mentioned they moved into 4Q a little bit. Are you able to comment if they've been dealt with now? And then just maybe what needs to happen to hit that 50,000 barrels a day target by the end of the year?

Randy Crawford

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Sure. And thank you for the question, David. Obviously, the team is doing an excellent job. We reached our record volumes. But clearly, working with CN and some of our logistics partners is a big key driver to improving productivity and maximizing volumes.

I'm going to let Randy address the question more directly. However, I will continue to point out that with the acquisition of Petrogas creating more optionality, we're becoming much more of a logistics company, and that is obviously going to help with some of these particular operational challenges this quarter.

Randy, do you want to comment on that some more?

Randy Toone - Executive Vice President and President, Midstream, AltaGas Ltd.

Sure. Thanks, Randy. Yeah. So Q3, we did have record volumes going through RIPET despite some of these disruptions we've had both on rail and marine. We feel that we've got a plan in place to rectify those. And so our goal is to get three cargoes out in November and three cargoes out in December, which will be 50,000 barrels a day. We're going into winter, so we have to build resilience into that value chain, but we are doing that while working with our third‐party service providers.

David Quezada

Great. Thank you for that. And then maybe just one more from me; a broader question. As you continue to deleverage and you've got the cash flow lift from Petrogas, do you see that providing the opportunity to increase spending in the Utility business since you want to remain self‐funded? Just wondering if there's any upside to that capital spending plan in the future as a result of that.

Randy Crawford

Sure, David. Our priorities haven't changed. Right? Maintaining a strong balance sheet, additional approach to capital allocations; those are key and critical to our long‐term strategy. And we

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have one of the highest rate‐base growths, between 8 percent to 10 percent in our utility, which is quite attractive.

So I think that overall we're going to just focus on prioritizing the capital, earning the returns on the investment. And to the extent that we increase that over the particular years, the driver's really going to be about availability of crews and opportunities to continue to improve the existing infrastructure.

James, do you have any other comments that you would like to make to David on that subject?

James Harbilas

Just to put some of the debt metrics into context, obviously, if you look at where we expect to end with year‐end debt and the midpoint of our range, we expect debt to EBITDA to be about 5.5 times. And we said on the Petrogas call that once you layer in the additional EBITDA from Petrogas acquisition, without any asset monetizations, just the drawdown of our line to finance it, that'll come down by another

0.15 to 0.2 turns from a debt to EBITDA standpoint. So we are seeing progress towards that stated goal that we've made in the past to get to 5 times debt to EBITDA.

David Quezada

Excellent. Thank you very much. I'll get back in the queue.

Operator

Your next question comes from Rob Hope with Scotiabank. Please go ahead. Your line is open. Rob Hope - Scotiabank

Good morning, everyone. Randy, thank you for all the colour on kind of the longer‐term strategic value. Just want to dive into that a little deeper. When you say you want to execute the strategy, looking at 2021, what does this include? And how would you view it to be executed? I guess, from my seat, it looks like ramping up RIPET, maybe expanding RIPET, and integrating Petrogas are the key issues on the

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Midstream side that you're looking to maximize value. And then I guess delivering the overall balance sheet.

Randy Crawford

Yeah. No. Absolutely, Rob. Thank you for the question, and I think you characterized it right. We want to integrate this, maximize volumes at RIPET and both Ferndale, continuing to provide our customers access to our overall global markets, and integrate this asset, execute the synergies, and create the value, and then we can look at other opportunities. So our priorities are focused. Right? Our mission is principle‐ centred, and we're focused entirely on executing those key drivers that you described and that I said in my prepared remarks.

Rob Hope

And then as a follow‐up there, when you take a look at improving the balance sheet, we could see an MVP sale, maybe a Blythe sale. What about the Midstream business? Are there any assets or partial assets of something like Townsend that you could evaluate as a sale of to improve the balance sheet?

Randy Crawford

Good question. We're always looking at our assets, how they fit into our overall strategy, right, and the integration of our Midstream business model. So again, we think most of those are focused on an integrated platform. A little early to tell, as I've said in the past, around Petrogas. We think most of those assets are all an integrated platform that add value to our customers and to our shareholders.

So I think that we'll clearly look at assets along that line, but I think the primary focus on improving the balance sheet is to get a return on these assets, generate the cash flows that we expect, and look at our noncore asset sales, which we've described, as you point out, Blythe and the Mountain Valley pipeline are key drivers that will get us to the targets that James … And we hope to overachieve

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and to achieving a net debt and EBITDA that is below 5 over time with that execution. And quite frankly, we work well with our rating agencies and working to get an upgrade is continues to be a priority.

Rob Hope

All right. Appreciate all the colour. Thank you.

Operator

Your next question comes from Jeremy Tonet with J.P. Morgan. Please go ahead. Analyst - J. P. Morgan

Hi. This is John for Jeremy.

Randy Crawford

Hi, John.

Analyst

Just wanted to ask-hey-first wanted to ask kind of looking at where results have been so far this year and compared to guidance, seems like results have been strong and kind of basically the kind of the midpoint or the lower end of the guidance would indicate kind of a step down year over year that's not really consistent with what we've seen thus far. So I guess anything-and I'm talking EBITDA here, I guess-is it fair to think upper end of the guide is more likely than the lower end? Or is there anything else we should consider for the fourth quarter?

Randy Crawford

You know, John, I would tell you that we stick to our guidance. We've been pretty consistent in performing on that. If you look at the results in the third quarter and throughout the year, and really, there's the excellent progress that Blue and his team have continued to perform at the utility, I would be

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expecting that we would be above the midpoint, frankly, with the last fourth quarter ahead of us of our guidance.

Analyst

Okay. Thank you. Yeah. That makes sense. And then second question for me. I'm just wondering if you could talk more about the kind of longer‐term RIPET volume progression. I know the guidance for 50,000 barrels per day by year‐end of 2020. But I guess beyond that, how should we think about that increasing?

Randy Crawford

Sure. As we've said, John, with capacity at RIPET of 80,000 barrels a day, we've gotten authority to move that level of product through our certificate, and we continue to work on some of the logistics operations surrounding that so that we can do it. We have the best market in Canada for LPGs, in our judgment, and we're giving excellent access to our customers, both to domestic markets but, frankly, to the global markets. And we see robust demand in Asia. It's coming back.

So again, I think that as we look forward with the integration of Petrogas and we look at the logistics optimizations that we expect to achieve, you know what, we'll stick to our guidance that we've had about the 50,000 barrels. But in the long run, given the supply and demand and the excellent markets in Asia, I think you'll continue to see us progress toward that 80,000. I'm not prepared to give you a specific timeline at this point.

Analyst

Yeah. That makes sense. That's helpful. That's all for me.

Randy Crawford

Thank you, John.

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Operator

Your next question comes from Julien Dumoulin‐Smith, Bank of America. Please go ahead. Julien Dumoulin‐Smith - Bank of America

Wanted to follow up on the last question on volumes at RIPET and also more broadly at Ferndale. Randy, I know you'd previously articulated a strategy or a plan to move to I think it's 60 percent tolled volumes at RIPET by the year‐end '21. So I was wondering if you could comment or speak to sort of how you see that progressing at Ferndale.

Randy Crawford

Yeah. Good morning, Julien. Nice to hear from you. Appreciate the question. Yeah. Absolutely. We continue to see all the progress through this quarter, sequentially up 20 percent for our tolling volumes. And I think that's really a statement about the value proposition of what we're providing to our customers and access to the market.

So I think it's a journey. We're looking at continuing to de‐risk the platform at Ferndale as well. So I think as we get the integration and close the assets, I'll be able to give you a bit better clarity around that guidance. As I said at the last call that about 40 percent of that EBITDA is already fixed through tolling and some longer‐term agreements at Petrogas more broadly.

So again, I think that at the end of the day, providing open access, giving our producer customers access to really valued markets that they have not been able to access previously, which is going to be critical for them to increase volume.

So the shift that's going on, Julien, in Northeast BC with some of the larger upstream players through the consolidation, I think, is going to be a lever that we'll be working with to provide them access to more tolling.

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So early discussions around butane and propane, but directionally, I'm upbeat and positive.

Julien Dumoulin‐Smith

Okay. Excellent. Thank you. And just shifting gears to the Utilities business, if I can. As part of the-I think you reported a $16 million uplift at WGL year over year. Can you quantify or speak to what proportion of that was due to the lower operating costs that you reported? And then also maybe speak to the composition of those operating costs, where you saw the most savings, and where, potentially, you see those as being sustainable going forward.

Randy Crawford

Yeah. Julien, excellent performance, as you saw this quarter with the utility. As you look at the components of those values, about $10 million in the quarter was operating cost reductions. The others were the impact of previous rate cases offset by some late fee revenue that we were not allowed to bill through the COVID.

In terms of sustainability, primarily here, we're investing our smart capital investments into our infrastructure. That's a driven‐down rate. Incoming leak rate, the outstanding leak balances; so that's contributing about 20 percent of that value. Overall costs that we're looking at in every aspect of our business while focusing on reliability is employee activities. Staffing is down. Some of the planned additions that we have had because of the activity levels being reduced.

So I will tell you that we see these as sustainable and repeatable and we're going to build on that. You couple that with some successful resolutions in our Washington, D.C. rate case and our Maryland rate case that we would expect into next year really positions us well. That coupled with our ongoing cost and customer service improvements to earn our allowed return, as we've guided in the past.

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So excellent job by Blue and all the team. They're renovating, they're reinventing, and they're really driving innovation at the utility and focused on improving service levels for our customers. So I couldn't be more excited about the result. So I see them as sustainable over the long run.

Julien Dumoulin‐Smith

Okay. Great. That's it for me. Thank you very much.

Operator

Your next question comes from Ben Pham with BMO. Please go ahead. Ben Pham - BMO

Yeah. Thanks. Good morning. I wanted to ask your commentary on the counterparties. Clearly, there's a big pause upon your cash flow quality as you look forward here in your guidance into next year. I was wondering is there anything you can share on any sort of high‐level incremental differences, maybe with respect to your anticipated growth rate-

Randy Crawford

Jeremy?

Ben Pham

-Midstream. Is there-

Randy Crawford

-address your question.

Ben Pham

Oh sorry. It's Ben Pham here. Can you hear me okay? Hello?

James Harbilas

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Hey, Ben, can you repeat your question? I don't know if we still have Randy on. We might have lost him. But if you can repeat that question, we'll deal with it.

Ben Pham

Oh. Sure. Okay. So my question is on the counterparty commentary you had. You had a nice boost there. We've seen, too, a bunch of other folks and improvements in cash flow quality, percent contracts goes up. I was wondering is there any sort of impact you can maybe share in terms of does your future growth rate change there on Midstream projects. Is there more JVs to consider? And then is there anything on maybe any sort of friction on returns or anything else that you're thinking here long term for the Midstream business?

James Harbilas

Yeah. I mean we haven't seen any friction on returns. I think the one salient point you touched on that we expect could potentially accelerate growth at some of our facilities in Northeastern BC is the consolidation that's going on in the Basin right now. Right? Obviously, some of the acreages have been consolidated in the hands of better‐capitalized producers, and we would expect that they are better positioned to move forward with development plans to satisfy take‐or‐pay commitments that they've inherited through that consolidation and obviously continue to grow production. So that's what we're excited about with the consolidation that we've seen so far.

Ben Pham

Okay. And maybe on, since I have you here, on the accounting policy, the pension plan, you have a bit of detail in there. You're booking at the $20 million; bringing back some of the benefits from future years it seems like what's going on. Is there anything to think about in terms of future impact on the EPS?

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Or do these utilities have trackers that mitigate or pass through that? And is there any other electives you can make on these others utilities you have similar to this pension plan elective?

James Harbilas

Yeah. Maybe I'll provide a little context for the change first and then kind of answer your questions around enduring benefit, and. So when we looked at our pension plan at WGL, the plan assets are heavily skewed towards fixed income products. And as a result, we decided to make this accounting change because, obviously, if interest rates go up or down and that impacts your discount rate and in turn impacts the plan liabilities, this is a more effective hedge in terms of how we're treating the increase in those plan assets. So it's an offset to changes in the discount rate, and that's what reduces the volatility in our pension expense.

Going forward, we expect there to be a benefit, and Randy touched on it, of about $3 million to $4 million to pension expense into 2021 so that the reduced volatility and the lower pension expense will benefit our customers.

And then you talked about trackers. We don't have any trackers in place for pension expense. These are expenses that are calculated when we go into rate cases through actuarial studies. And that's how we set the recovery for those expenses in our rates going forward.

Ben Pham

Does your discount rate on the liabilities, is that also trued up each quarter too then? Is that what's going on as well?

James Harbilas

No. It'll be based on an annual actuarial study that will calculate those expenses.

Ben Pham

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Okay. All right. That's it for me. Thank you very much.

James Harbilas

Thank you.

Operator

Your next question comes from Linda Ezergailis with TD Securities. Please go ahead. Your line is

open.

Linda Ezergailis - TD Securities

-potential asset sales for 2021 and 2022. And specifically, I see that you've got about $1 billion of debt maturing. I'm assuming that a lot of that would be repaid, but I'm wondering what your thoughts are about the merits of refinancing at extending the term potentially, et cetera.

James Harbilas

Linda, I'm going to apologize to you because I think we're having some technical issues here and I did not catch the first part of your question, only the last couple of sentences. Do you mind just repeating that? Because we are having some technical difficulties here.

Linda Ezergailis

Sure. It's just around, in summary, just trying to get a sense of your base financing plans for 2021 and 2022 beyond just potentially selling assets. I see you've got about $1 billion of debt maturing, and I'm wondering about how you balance the benefits of refinancing at low rates for potentially longer term versus repaying, and how any sort of other sources of capital, whether it be through JVs, et cetera, might inform your plans.

James Harbilas

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Yeah. You know what, in terms of the maturities that we've got coming due in 2021, I mean, we've been very successful in refinancing maturities throughout 2019 and 2020 in the MTN market, and that'll be our primary source. We've said on Petrogas that we're going to obviously draw down on the facility when it closes, and we will use the proceeds from any asset monetizations to repay those drawings.

But with respect to regular or scheduled maturities, we will most likely access the MTN markets to be able to deal with those, because we have seen attractive pricing at different tenors and we'd like to position ourselves to continue to take advantage of that.

On future funding and JVs, I mean, we like our footprint. We've already got some very strong JV partners within our existing investments. I wouldn't say that there's any short‐term plans for us to change that approach at this point.

Linda Ezergailis

That's helpful. And I'm wondering, when you think about your rate filings and plans at your utility level, if there were an increase in corporate tax rates in the US, what are your thoughts about potentially when and how you might recover that in your utility rates?

James Harbilas

Yeah. I think that we've talked about this on past calls in terms of what the expected benefit is to some of our debt metrics, and we've estimated those to be in the 4 percent to 5 percent range.

In terms of future recovery though, we would probably move forward with rate filings and try to recover those to the extent that it does lead to higher deferred taxes that would permit us to recover them.

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When the tax rates went the other way, obviously, some jurisdictions dealt with them as special filings, and other jurisdictions dealt with them in the context of rate filings. So I would anticipate that we would follow the same approach.

Linda Ezergailis

That's helpful context. Thank you. And just a detailed modeling question. For your maintenance CapEx, it was trending a little bit light. I'm wondering if there might be higher activity in Q4, and what an appropriate run rate for your Midstream business might be prospectively in 2021 and beyond.

James Harbilas

Yeah. So typically, Q4 tends to be a very heavy CapEx quarter for us, both on expansion and maintenance. In terms of a run rate for the Midstream business, we think that $20 million for maintenance capital is an annual number that you can use for modelling purposes.

Linda Ezergailis

That's very helpful. Thank you. I'll jump back in the queue.

Operator

Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead. Andrew Kuske - Credit Suisse

Thank you. Good morning. So I guess the question is really, where do you see yourselves in the transformation of the Utilities? And what inning are we in at this stage across the entire portfolio? And then, if you looked at the spectrum of the utilities you own, what are the better performers versus the worst performers? And what's the spectrum of the respective innings that they're individually in?

James Harbilas

Yeah. I'll start and then maybe I'll ask Blue to jump in as well.

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I mean if you look at the jurisdictions that we're in, Alaska and Michigan, those utilities have been performing at their regulated returns for quite some time, and they've been there consistently. In WGL, and I think Randy touched on this already, we've made tremendous progress from where we were in 2019 through a combination of operational excellence initiatives on OpEx, obviously focused capital allocation, and executing on our ARP capital spend, and then obviously getting caught up in rates.

So we have made progress of about 150 to 180 basis points from where we were in 2019 in improving ROEs there, but there's still some work left to do. And we anticipate that we can continue to move the needle in 2021 and 2022, and that'll be through a combination of additional rate cases that are currently being litigated in different jurisdictions and obviously a continued focus on OpEx and capital allocation.

Blue, is there anything that you want to add?

Blue Jenkins - Executive Vice President & President, Utilities and President, Washington Gas, AltaGas Ltd.

No, James. I think you hit the highlight. I think we're well underway at the jurisdictions covered by Washington Gas. A lot of opportunity, we think, still in front of us, but we've built-we have a really solid base and we've got good momentum and we expect to see that carry forward. It's all speculative on are we third, fourth inning. Who knows? But there's still some ball to play, but we're very happy, as James points out, with the progress we've made.

And then to his point, I would reiterate, the other jurisdictions, Alaska and Michigan, are performing very well and at their allowed returns. So we're very happy with where they are and expect to see that performance continue.

Andrew Kuske

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And then maybe as a follow‐up, how do you facilitate the exchange of information between the jurisdictions just to share best practices, among other things?

Blue Jenkins

Yeah. You bet. I'm happy to take that. So this is Blue. So what we have is we're organized, obviously at the Utilities division. We have individuals with accountability that reaches across all of those utilities. So our operations, our COO role, for example, and, you know, has accountability across the utilities, and so we see that there. We also have that same structure across our regulatory group so that we take what we're learning and best practices and try to push that across. So it's a great question. I think we are structured and have processes in place to account for that and then take advantage of those opportunities.

Andrew Kuske

Okay. That's great. Thank you very much.

Operator

Your next question comes from Robert Kwan with RBC Capital Markets. Please go ahead. Robert Kwan - RBC Capital Markets

Thanks. Good morning. Just wanted to go back to some statements that you made earlier in the call. And with the pendulum continuing to swing towards splitting up Utilities and Midstream, and you've had the transaction Midwest earlier, recently here. You've got your comments that you want to integrate the businesses as well as de‐risk the Midstream side of things. And I just want to dig into that a little bit more.

You've got kind of the $30 million of Petrogas synergies that you put forward, and there were some comments earlier about trying to get the RIPET volumes to your target. I guess, in the grand scope

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of things, what do you see beyond that $30 million given that's not a super‐material number if you were thinking about a transaction? So what is the revenue synergy upside that you see? And then what's the risk to actually getting to your target volumes on RIPET such that if somebody were to look at bidding for your assets that they wouldn't want to pay you for it?

James Harbilas

Rob, there's a lot to unpack there. I mean, in terms of additional upsides on the Midstream platform, we've always talked about additional volumes at RIPET and obviously optimizing Ferndale with very, very little capital investment that we feel that we can capture. There's also other volume growth within the Basin, and additional product offerings that we can bring to producers, potentially a condensate solution that we're excited about, and we want to continue to focus on to be able to grow that business.

So I think that we've made steady progress in terms of getting our volumes up at RIPET, and we think that we can make continued progress in 2021. So that's where we want to focus on optimizing those two platforms. And we got a question earlier about progress at the utilities. We still think that there's a lot of efficiencies and improvements we can drive there that'll help to drive shareholder value.

Robert Kwan

Do you have any-like are you able to, similar to what you did on the Petrogas synergies at that $30 million level, are you able to kind of quantify some of the other opportunities that you just mentioned?

James Harbilas

Well, no. Not at this point. I mean we'd like to focus, as Randy said a little earlier on the call, on the integration of Petrogas and capturing those synergies. And once we assume operational responsibility of that, we would be in a better position to continue to update the markets on whether or not there's

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additional upside in terms of integrating that asset. But we do see continued opportunities in Western Canada to grow volumes at our existing facilities.

Robert Kwan

And if I can finish with a question on the LDCs. And overarching, you made some comments earlier about trying or wanting to be in that self‐funding position and that being difficult with how strong the growth is there, as well as reducing risk. And what are your thoughts about proposing accelerated amortization for those businesses? Trading off the arithmetic that would moderate rate base but from that very strong number to something that would still be above average? Could you improve the cash flow profile and presumably de‐risk with kind of some of the thoughts out there or concerns in the market around the existential risk to gas infrastructure businesses?

James Harbilas

Yeah. I just want to clarify your opening comment. I don't think we ever said that we would be stressed to self‐fund the growth that we're seeing in our utilities at 8 percent to 10 percent rate base growth. I think we've been able to do that this year. And when we look out over the next five years, we feel that we can continue to self‐fund the growth that we're seeing within our jurisdictions being driven by ARP spending and obviously new metre growth.

In terms of your broader question on accelerating depreciation, I mean, each and every jurisdiction in the context of its rate case filings has depreciation studies that need to be updated. And once we make those updates, and if we think that the useful lives have to change as a result and it results in more depreciation recovery, we'll deal with that in each individual rate case that we file.

Robert Kwan

All right. Is there any change in thought, though, just at the management level, that you'll be-

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James Harbilas

No. Not at this point.

Robert Kwan

-useful lives. Okay. Okay. Thank you.

James Harbilas

No.

Operator

Your next question comes from Robert Catellier with CIBC Capital Markets. Please go ahead. Robert Catellier - CIBC Capital Markets

Hey. Good morning, and thanks for the presentation, particularly the comments you made about a corporate split. I really only have one question left at this point. Randy pointed to the strengthening curve with respect to Asian propane and that export business. Can we assume that you're going to continue to aggressively seek to toll the business? Or is there a point at which it makes more sense to- the economics are strong enough to keep the spot business and hedge it?

Randy Crawford

Hey, Robert. Randy. I'm back. So thank you for the question. And so I apologize for being cut off there for a bit. But to your question, I think certainly every company would like to eliminate risk from its portfolio and that's what we're going to balance. And our primary approach will be to balance various linked related tolling contracts with some hedged merchant activity that really provides upside for the Company.

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So our propane and butane export terminals, coupled with our storage, that creates optionality. So we'll plan to position the business to capture short‐term arbitrages to capture this option value and augment the revenues surrounding the export business.

But at the same time, we're going to continue to toll and increase our tolling to de‐risk the assets, because just like with RIPET, we have 50,000 a day that we're going to be moving and we have 80,000 barrels a day of capacity. So again, there'll always be that opportunity to continue to capture short‐term arbitrage coupled with our increased tolling over the next few years.

Robert Catellier

Right. That's an understandable answer. Now that you're back on the line, I want to get back to the corporate split and just one quick question. I just wondered if there were any observation or takeaways from the recent DTE announcement.

Randy Crawford

Yeah. You know what? Look, DTE is an excellent company with an excellent midstream footprint. I think each company has particular drivers in their structure moving forward. So it's difficult for me to comment particularly on their approach because I think we're a bit unique into what we're attempting to accomplish.

But clearly, consolidation is occurring. It's occurring in the upstream space. We think that's good. We're very comfortable working with some of the larger and major players. I think that's right in our sweet spot in terms of we know what it takes to develop these world‐class resources and we have something that we bring of value to connect producers to valued markets.

So we'll continue to exercise that for us. With respect to the DTE and the Dominions, I think each one is a specific case on their own.

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Robert Catellier

Yeah. Agreed. Thanks very much.

Randy Crawford

Thank you, Robert.

Operator

Before we move on to the last question, I would like to remind participants that if you have any further questions, simply press *, and then the number 1 on your telephone.

This last question comes from Elias Foscolos with Industrial Alliance. Please go ahead. Elias Foscolos - Industrial Alliance

Good morning. I've got a couple questions to ask. First one is, it's rather minor, but I just want to understand something. In terms of seven‐and‐a‐half ships at RIPET for the quarter, can you confirm that that half ship was an operational issue? I just find it to be a strange number.

Randy Crawford

Sure. Randy or James, you want to address that specifically?

Randy Toone

It wasn't an operational issue with our terminal; it was more logistics. We had some disruptions with our supply chain, and so we filled the-half pulled the ship and then we de‐berthed and then we brought it back to berth when we had enough product to fill it up.

James Harbilas

And, Elias, I just want to add a little bit-

Elias Foscolos

I appreciate that clarity. Yeah.

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James Harbilas

So, Elias, I wouldn't mind just adding, though, to Randy Toone's comments that when we're loading ships, we recognize revenue when we transfer product from the tank onto the ship. So there are going to be situations where we're not getting a full ship in a quarter, just based on the way we recognize revenue. Because if we're loading and we don't completely fill the ship by the 30th or 31st of every month, then some of that'll slip into the next quarter.

Elias Foscolos

Okay. I appreciate that clarity. The next question, and this will probably deal with the utilities, and maybe this was answered but maybe I didn't hear it quite correctly. It was $10 million to $11 million of cost reductions annualized, or quarter over quarter. So can we sort of draw the line that somewhere between $30 million and $40 million is sort of the run rate number that would happen off of that? It seems like a pretty impressive piece of work.

Randy Crawford

Look, I think it is a quite an impressive work. If you even look at the overall utility results year over year and the increase that we've attributed, even in the first and second quarters as well, we've been trending along those lines. And, of course, in terms of our return on equity, we have quite a bit of room and that's part of our operational excellence strategies going forward. So, again, we're going to have to continue the effective and productive deployment of capital in our ARP programs, in accelerated pipeline replacement, and we would expect to continue to drive down cost.

But thank you for the comment. It is. It's quite impressive what Blue and the team have been accomplishing, and while focusing again on improving customer service, improving the safety and reliability of the infrastructure, which is obviously one of our key and most important drivers, the safety

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and reliability. So as you continue to put smart capital to work, you should continue to see improved efficiencies on the cost structure.

Elias Foscolos

Okay. One last question directed towards James, I guess. I'm going to try to word this correctly. I understand on a consolidated basis we should see an improvement in credit metrics, which is debt to EBITDA. But understanding Petrogas is a separate entity from the rest of AltaGas and some of the regulated utilities, I think you said on the previous Petrogas call you discussed this with the credit rating agencies. I just want to confirm that this isn't going to cause any stress on the credit rating given the-I mean, I understand the consolidated number, but we do have separate entities.

James Harbilas

Our conversations with the rating agencies have been constructive for all the reasons that we highlighted on the earlier Petrogas call. If you look at our net debt to EBITDA metrics, they are improving as a result of this. But more importantly, the FFO to debt metrics are improving as well. In the past, we would only include distributions or dividends that we got from Petrogas into our FFO metrics. When we're consolidating, we're obviously including the EBITDA from that subsidiary because we've got operational responsibility and we own greater than 51 percent.

So we are treating it consistently with how the rating agencies would treat this acquisition, and it would improve our credit metrics. And we don't anticipate any issues with the rating agencies as a result of that.

Elias Foscolos

Great. That was-

James Harbilas

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In fact, DBRS-just sorry, just to clarify-DBRS has already come out with a report affirming the

ratings.

Elias Foscolos

Okay. Great. Thank you very much.

James Harbilas

Thank you.

Operator

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

Adam McKnight

Thanks, Kenzie, and thank you everyone, 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. I hope you enjoy the rest of your day. And you may now disconnect your phone lines.

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