Thank you, Kelsy. And good morning, everyone.

Thank you for joining us today for AltaGas' third quarter 2021 financial results conference call. Speaking on the call this morning will be Randy Crawford, President and Chief Executive Officer; James Harbilas, Executive Vice President and Chief Financial Officer.

And we're also joined here this morning by Randy Toone, Executive Vice President and President of our Midstream Business; Blue Jenkins, Executive Vice President and President of our Utilities business; and Jon Morrison, Senior Vice President, Investor Relations and Corporate Development. In addition to the third quarter press release, financial statements and MD&A that were released earlier today, we've also published a third quarter earnings summary presentation.

The presentation walks through the quarter and highlights some of the key variances and non-recurring items that we would assume would be helpful for the market to understand. And it can be found on our website under Events and Presentation section.

As always, today's prepared remarks will be followed by analyst question-and-answer period. And I'll remind everyone that we will be available after the call for any follow-up that you might have.

We'll proceed on the basis that everyone has taken the opportunity to review the press release and our third quarter results. As for the structure of the call, we'll start with Randy Crawford providing some comments on our third quarter financial performance and progress on our strategic priorities, followed by James Harbilas providing a more detailed walk-through of the financial results, our near-term outlook and guidance.

And then we'll leave plenty of time at the end for the questions. Before we begin, we also remind everyone that we will refer to forward-looking information in today's call.

This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 of our investor presentation, which can be found on our website and more fully within our public disclosure filings on both SEDAR and EDGAR systems. And with that, I'll now turn the call over to Randy.

Thank you, Adam. And good morning, everyone.

AltaGas delivered strong third quarter results with normalized EBITDA growth at 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 execute 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 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 achieve liquified 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 volume in a 15% year-over-year increase in fractionation and liquids handling. Our expanded Midstream business continues to match our strong expectation 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 into market 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 shifts.

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 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 fraction and liquids handling volume increased 15% year-over-year in the third quarter. The 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.

Utility segment, excluding the one-time pension accounting adjustment in the third quarter of 2020, and the unfavorable impact of the Canadian-U.S. dollar exchange rate achieved normalized EBIT increase of $5 million in U.S.

dollar terms. The results in a seasonally low throughput quarter reflect the strong execution of our strategic plan and leave us in a position to close the underearning gap and achieve our allowed return in 2022.

During the quarter, we continue to execute on the company's various accelerated pipeline replacement program with an ongoing focus on replacing aging infrastructure to improve the safety and the liability of the system. Investment during the quarter, about the year-to-date 2021 capital spend on accelerated investment to CAD$242 million.

Over time, these investments should reduce operating cost and emissions through leak reduction and drive better customer, environmental and societal outcomes. Turning to headlines of natural gas shortages in Europe and the increased demand coming from Asia, we have seen a significant run up both globally and domestically of natural gas prices.

As a result, heading into 2021 and 2022 heating season, natural gas prices are meaningful ahead of recent years. Fortunately for this upcoming winter, AltaGas utility’s 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 source 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, the 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 for the focus on safety, reliability, and affordability.

And with that, I will turn the call over to James to review the financial results in more detail.

Thank you, Randy, and good morning, everyone. As Randy mentioned, we are pleased with the results that we delivered in the third quarter with continued execution on AltaGas long-term strategic plan, positioning the company to drive further long-term stakeholder value creation.

Normalized ETFs of $0.02 in the third quarter of 2021, compared to $0.04 in the third quarter of 2020 positions AltaGas well to deliver on 2021 financial guidance. Normalized FFO per share of $0.61 in the third quarter of 2021 compared to $0.40 in the third quarter of 2020, representing 53% year-over-year growth and continues to provide the foundation for increased returns of capital to shareholders and to fund ongoing organic expansion.

Normalized EBITDA of $244 million in the third quarter of 2021 compared to $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 $186 million in the third quarter 2021 compared to $114 million in the third quarter 2020, representing a 63% year-over-year increase. Midstream results were positively impacted by approximately $20 million this quarter, as a result of revenue recognized for an LPG export cargo that was loaded at the end of the third quarter at spot prices.

But the offsetting hedge loss will not be realized until delivery at the destination point in the fourth quarter. As a result of this timing related hedging loss, our EBITDA for Q3 2021 is roughly $20 million higher than we anticipated.

And we would therefore expect a commensurate offset to the normalized EBITDA reported for the fourth quarter, as it effectively had the impact of pulling revenue forward one quarter. Normalized EBITDA from our global exports business of $106 million increased $78 million year-over-year, driven by the Petrogas acquisition and record global export volumes from our two export facilities.

Due to the previously mentioned timing related hedging loss, global exports EBITDA was approximately $20 million higher in the quarter. Our processing and fractionation business continue to be supported by strong fundamentals for natural gas and long-term 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 Hermatin [ph] flow generation facility due to favorable Alberta power prices offset by no AFUDC recognized for MBT 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 totaled or collectively hedged.

This includes an average FEI to North American financial hedge price of approximately US$12.64 per barrel for both propane and butane. We also have 95% of our expected frac exposed volumes hedged in the fourth quarter at $25.70.

Normalized utilities EBITDA $62 million in the third quarter of 2021 compared to $80 million in the third quarter of 2020. There was a $17 million pension accounting change that was realized in the third quarter of 2020, that was not present this quarter while the unfavorable move in the Canadian to U.S.

dollar foreign exchange rate drove further $4 million year-over-year decrease compared to the performance in third quarter 2020. WGL reported normalized EBITDA of $13 million compared to $32 million in Q3 2020.

In addition to the previously mentioned pension accounting impact, the quarter included warmer weather in DC, a $4 million negative impact from foreign exchange, which was partially offset by positive impact of Maryland and DC rate cases and continued ARP investments. SEMCO and ENSTAR’s combined normalized EBITDA was $25 million in the third quarter, down $3 million from the same period last year, due to warmer weather in Michigan, partially offset by colder weather in Alaska and slightly higher one-time costs and foreign exchange.

And finally, normalized EBITDA from the retail energy marketing business was $23 million in the quarter, an increase of $3 million year-over-year, driven by higher gas margins due to favorable pricing and the timing of certain in the money hedge settlements in Q3, partially offset by lower power margins. The corporate and other segment reported normalized EBITDA loss of $4 million compared to $19 million earned in the same quarter of 2020.

The $23 million year-over-year decrease was driven by the combination of higher expenses related to employee incentive plans, as a result of AltaGas' rising share price over the course of 2021. The monetization of Pomona Energy Storage and AltaGas 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 $111 million, compared to $108 million for the same quarter in 2020.

The increase was mainly due to new assets placed in-service and the consolidated of the Petrogas assets. Interest expenses was $69 million was up slightly over last year's comparable period of $65 million as a result of modestly higher average debt balances, partially offset by lower average interest rates and a lower U.S.

dollar to Canadian dollar exchange rate. Looking ahead, AltaGas continues to be focused on many of the same priorities the company has over the past 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’s stakeholders. AltaGas continues to focus on delivering durable and growing ETFs 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 to $1.80 per share.

2021 normalized EBITDA guidance is $1.475 billion to $1.525 billion. And AltaGas’ 2021 capital expenditure plan is being reduced from $910 million to $850 million.

The largest drivers for the reduction are a lower forecasted Utilities spend, which is partially driven by a stronger Canadian U.S. dollar exchange rate, which reduces the cost of capital expenditures in Canadian dollar terms, and select Midstream spending now expected to rollover into early 2022 instead of 2021.

The capital expenditures program remains heavily weighted towards the lower-risk Utilities business and is comprised primarily of ARP and system betterment projects that are anticipated to deliver stable rate base growth and strong risk-adjusted returns. These investments are directed at delivering improved long-term customer, safety and environmental outcomes.

Finally, we are looking forward to hosting our first Investor Day over the past five years, which will be held virtually on December 15. 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?

Good morning, everyone. First question just on the 2021 guidance and you’re reiterating kind of the upper end of the band.

Now just taking a look at Q4, are there anything specifically we should watch out for just given the strong results year-to-date. And I guess aside from that $20 million LPG headwind in Q4.

It seems that the top end of the range is relatively conservative unless there’s some other things that are settling out in Q4.

Rob, it’s James here. Yes, look, I think that when you look at Q4 of 2020 and you try to extrapolate that into Q4 2021, there’s a few things that contributed to 2020 results that are not going to repeat in Q4 of 2021.

So you touched on obviously the hedge loss, which has already been telegraphed, but we had AFUDC that we were recording on MVP in Q4 of 2020 that’s not contributing anything in 2021. We obviously sold the U.S.

storage transportation business that, that contributed in 2020. There was FX headwinds just given a higher exchange rate on the U.S.

dollar front that also helped Q4 of 2020. And then obviously on the retail side of the business, we do have higher PGM costs throughout 2021 relative to the comparative period in 2020.

So those are some of the items that would probably push us a little bit lower than where we were in Q4 of 2020, but we still feel comfortable that the top end of our range is achievable.

I appreciate the color. And then just as we take a look out to 2022, FEI propane pricing has been strong, but we’ve seen a real catch up in kind of North American propane benchmarks.

How are you looking at that exposure and maybe speak to kind of the potential to kind of move more butane over few over propane in that year?

Yes, I mean, I can provide some comments and then maybe Randy Toone can jump in there too, but I mean if you look at propane spreads throughout 2021, we’ve really started to see them strengthen heading into Q4. And then when we look at the forward curve into 2022, they’re – the FEI Mont Bellevue spreads almost $10.

So we do expect some strength there and we will start to actively hedge some of that position heading into 2022 as well. And for 2021, we’re already high hedge, but we continue to layer in hedge – our hedging program above the 65% that we exited Q3 at just given the strengthening in the curve.

Yes. And this is Randy Toone.

We know North American LPG prices are high, especially heading into the winter. So it all depends on what kind of winter North America, but FEI is always they’re also going into winter and we feel that the FEI will strengthen as well.

And that, that margin will be there.

I mean from September 30 to probably yesterday, when I got the last report, we have seen the spread on propane expand by about $1 from an FEI to Mont Bellevue standpoint dollar barrel.

Appreciate it. All right.

Excellent. Thank you.

Yes, thanks. Good morning, everyone.

Maybe a question on the utility side of things. Could you just discuss the commentary I guess in the MD&A about just the natural gas quality service standards and will there be any cost associated with the efforts there?

Sure. Hi David, this is Randy.

I’ll let Blue just make some comments on that, but with respect to the service levels, we’ve been working with our regulators and very proactive in our approach to addressing some of the shortcomings of our former service provider. And so we took very strong proactive actions and we’re trending to service levels that are at pre-pandemic levels.

So we’re certainly addressing that directly. Blue, I’ll let you go ahead and comment.

Yes. Thanks, Randy, and thanks, David for your question.

A as Randy mentioned, we had been in regular communication with our commissions all the way through as we were aggressively transitioning from our original service provider to the new one. So it’s always tough to predict that.

We don’t expect it will be anything that looks like in the read through on the request, but it’s always hard to say, but we feel very good about where we are and where we’re headed and good conversations along the way. And we have weekly conversations with them and they can see the progress.

So we’re quite optimistic on where that lands.

Great. Thank you for that.

That’s helpful. And then maybe just one more for me, the RNG project that you announced just curious if there’s any color you can provide on like the capacity or the cost, capital cost 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, I – this is Randy. I’ll Blue make his comment, but 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.

And this is just the first step in the direction in our announcement today. And there’s going to be more and we’re going to continue to invest in reducing our carbon emissions intensity, which includes products to help our customers to do the same.

But I’ll let you comment specifically on the project.

Yes, thanks, Randy. The scale of this one is not big.

What it does provide is that first working relationship as we build out all of the materials, so transfer stations and meters gas quality analyzers, pressure regulation, SCADA systems, motorization equipment, all those things that come through that RNG process working with a very strong partner here. All of that gas stays in region in fact will be used for generation on site for that particular facility.

So it’s really a win-win for the region and for us and for WSSC. As Randy mentioned, lots of other things going on in the hopper, so more to come, this one is really are dipping our toe in the water, as we design build those facilities and get comfortable on how to handle those type of opportunities.

Excellent. Thank you for that.

I’ll get back in the queue.

Export license. Would you be looking to expand capacity at RIPET and or Ferndale to accommodate that incremental 40,000 barrels a day?

What would that capital cost look like, the expected build multiple. And then from a timing perspective, when do you think you might receive regulatory approval and be in a position to have that incremental capacity in service?

This is Randy Crawford. A lot of exciting things happening in our midstream business and leveraging our export network 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.

And we’re being proactive in terms of our licensing and move more products into both of those facilities. So I think we’d be optimistic about approval.

And I’ll let Randy add some commentary.

Yes. So the butane license like Randy says is this kind of secures our future to be able to export butane.

And right now, we’re exporting butane out of Ferndale around 20,000 to 25,000 barrels a day. We do think that we can develop an expansion out at Ridley Island with our partner.

And the timing of that is still yet to be determined, but we think we’ll have regulatory approvals here soon with our partners. And we can probably talk more about that in the coming future.

Okay. And you use the term proactive here to describe the application, I mean, perhaps you could just share some insights into the level of customer demand for this additional butane export capability both from existing and prospective customers.

And perhaps, which customers might be more inclined to support any capital investment needed upstream versus downstream.

Yes. Hi Patrick.

Great question. We’re seeing robust demand for our services in Asia on both the butane and propane front.

So that clearly is a big opportunity as we continue to demonstrate our ability to consistently deliver clean burning energy into Asia. So I think what you’ll seeing as we look toward these expansion opportunities is to – is at the direct market we’re reaching back and locking in longer term agreements.

And so, well, we’re certainly moving forward with producer push and some firm long-term agreements with some of the larger producers in the basin to get them access to FEI pricing in global markets. But we’re really seeing robust demand on the market side.

And it goes to our strategy of reaching further with our ships 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 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 from a variety of customer locations.

And so, yes, we would see expansion opportunities. And we think that we’ll talk a little bit more about that on the Investor Day, but we source a product clearly from the Montney, but also in due the Bakken and such and through our customers.

So tremendous opportunities to be able to give access to our customers to premium global markets. It really is a differentiating factor for us.

Got it. Thanks for that.

I’ll jump back in the queue.

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. And related to that around your 8% utility rate based growth target, should we be thinking about, as we look out ahead over the next couple of years.

Should we be thinking that would be a sequential 8% or could there be some variability in there perhaps from year-to-year?

Hey, Dariusz. It’s James here.

So with respect to your first question, the capital shift that we talked about or the reduction obviously that we discussed in the call was primarily driven that the lion share of it was driven just by the foreign exchange rate, being lower relative to what we had set for the budget. So of the $60 million reduction, I’d say about $40 million of that was FX related.

The balance was obviously us just shifting some midstream capital for turnarounds into early 2022 versus 2021. That being said, I don’t anticipate that that would materially shift the proportion of capital that would – that we have earmarked in 2022 for utilities versus midstream.

I still think that that percentage is going to stay relatively stable as we head into 2022. With respect to your comments around growth rate, I mean, obviously December 15, we’re going to be sharing a lot more information in terms of our rate based growth over the next a little while.

But we would expect the 8% that we’ve cited in the past is a CAGR. So you might see a little bit of variability, but that’s what we would average in terms of rate based growth over the next four to five years.

Excellent. Thank you.

That’s very helpful. And if I can stick with utilities for one more question.

I think I heard at the opening remarks and maybe just a point of clarification that you are on track to exit 2021 at a run rate of achieving your authorized ROE at the WGL utility specifically, but just maybe if you can clarify that. And maybe just talk about some of the efforts there on, I know, you discussed ARP, but also maybe on the OpEx side as well, if you could.

Sure. This is Randy.

As I said in the prepared remarks, we are on track and we intend to earn our allowed returns. And now just give you some color on the opportunities ahead and that we think that there’s just continued focus on optimization across our utility business, and that’s what really what we do as a company is to look for those opportunities to bring efficiencies to the business.

And of course in best capital to take out costs in lower cost over time and one of the great ways that the utilities doing it is to continued execution of our ARP program. Because as you well know, that not only does that have clean energy benefits to reduce emission, but it lowers operating costs, which will be quite frankly a great offset to some of the inflationary pressures and keeping costs low for our customers.

So our teams are committed to that. The digitization, the improvement of process, reduction of activities and the renovation and reinvention that’s going on in our utility that Blue and his team are leading is very exciting.

And last James had said, we’ll get into some more detail in our Investor Day and we’re looking forward to it. But I think you’ll see that they’re well positioned to continue the growth going forward.

Excellent. Thank you.

I’ll leave it there and congrats again on the quarter.

Thank you. Appreciate it.

Thank you. Just want to get some more understanding of how you’re thinking about blocking 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?

Yes, Linda it’s James here. Obviously, I think you touched on an important factor, which is significantly higher frac spread heading into 2022 than what we’ve seen in 2021.

So we’ve already been out there hedging part of that and locking in that cash flow. I think we already addressed how we’re approaching FEI at Mount Bellevue given where we see cal 2022 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, as we get visibility and certainty around supply volumes, as we get closer to 2022, that’s where we start to layer in those hedges and protect those cash flows.

So we’ll update obviously the markets as we move through our reporting cycle and with year end, but we’d also probably have a little bit of an update at our Investor Day in terms of how we’re going to approach that going forward. But typically what we want to wait and do is get some certainty around supply.

And then we’ll go into the markets if we like where those spreads are to lock in those cash flows.

Okay. That’s helpful.

And just in terms of tolling understanding that we’ll probably get a more fullsome 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 questions.

It’s a good question. We’re in constant discussions kind of consolidation that’s gone on in the basin with our larger producer customers.

And clearly, I think as the pricing and some of the environment has improved, I think that’s actually looking toward longer term commitments that our producers is something that that we’re having pretty extensive discussions on. And as you alluded to, we’ll get into a bit more detail in our Investor Day about that.

But I think that it’s the continued execution by our team, which has been tremendous is encouraging as well to our producer community. And so, in terms of term and consistency, I think those are the types of things that are driving increased tolling.

And it’s a big driver for us. And I also alluded to Linda that we’re also seeing demand from the market as well for longer term and to be able to reach back.

So I think as you look at us going forward, as we continue to grow this business, and de-risk the platform, you’re going to see a combination of both producers locking in longer-term, as well as the market.

Thank you. And maybe while – 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 re-contracted? And how that the attributes around and sort of commercial arrangements might differ from what is in place currently?

Linda, I think it’s under a current tolling agreement or two more, I believe, right. Two more years and that we’re in discussions to extend that arrangement with the California commission, as well as the Southern California.

And so I think that again, the key drivers there is, that’s a very critical asset in California. So again, I don’t want to run those negotiations, but overall, I think you’ll see a similar aspect of tolling like an extended term.

Thank you. I’ll jump back in the queue.

Good morning. If I can just go back to guidance and James, you listed a number of things that you saw as headwinds year-over-year.

I’m just wondering, what are you seeing in terms of all those things were already baked into the Q3 results, other than the $20 million hedge timing. Outside of that one piece what are you seeing anything to be the concerned or headwinds wise just kind of rolling Q3 forward minus that hedge adjustment.

So when you say, and I just want to clarify Robert, when you say rolling Q3 forward, in terms of basically reducing the positive contribution from the hedge and having the same kind of results on the midstream platform or just overall?

Yes, sorry. Yes, just on the midstream platform, you listed a bunch of other things that I think you were just trying to frame for Q4, and I think almost all of those things were already baked into the Q3 number.

Yes. So I just – so great question if you’re just focusing on the midstream platform.

And obviously the midstream platform moved 18 ships in Q3. And part of that was a bit of a spillover from ships that were Q2.

That’s kind of slipped into Q3. I think it’s the capacity of the export facilities also increases in the summer months because we’re able to move more product via pipeline out of the refineries into the Ferndale facility, which gives us the ability to move more export volume.

So Q4, we don’t expect to do 18 ships as a result of that. We’re now relying again on rail.

We don’t have that pipeline capacity because the refineries are using that. But we would be looking to do 13 to 14 ships in the quarter, which would put us on track for the expected ships that we had for the entire year.

So that is another factor that you can’t just extrapolate Q3 into Q4 on the midstream side.

Okay. That’s fair.

And then just on the utilities, FX will be like year-over-years with the seasonality, you can make the most sense, but you got the FX offset by or not offset, and then on the positive side that you’ve got new rates/rate base. Anything else, obviously weather can be a swing, but anything else risk to think about on the utility side for Q4 2021?

Yes. You touched on one, it was weather that’s definitely a risk.

But the other one that I touched on in my response to an earlier question was just PGM charges on the retail side. They were a lot lower in Q4 of 2020 versus what they’ve been averaging throughout 2021.

And Q4 is going to be a higher PGM charge on the retail business. So we will see some variability year-over-year as a result of that as well and...

Are you able to quantify what that year-over-year impact might look like?

Yes, probably in the neighbourhood $15 million to $18 million.

Okay. That’s great.

Thanks. I guess just to finish on just the NGL setup into 2022.

And you touched on hedges I guess just first, are you able just to quantify what the realized losses on the frac spread hedges were this year? I.e., what should reverse out into 2022 and then the uncertainty on the volumes.

Are there any early thoughts? I know the NGL here is a little bit far out to talk about, but anything just on the upcoming gas year and what extraction premiums might look like for 2022 versus 2021?

Do you want to comment on that Randy?

Robert, it’s Randy Toone here. So I can't comment on the frac hedge losses.

But as far as volumes go, we're very confident we'll have similar frac spread barrels as we did in 2021 is close to 10,000 barrels a day. And that would be similar for 2022.

Are you talking about export volumes?

Well, you got comments or both, but I was largely looking about what you think you can secure on the frac spread side of things. But if you've got comments as to what you might be seeing on the export volumes for 2022 that'd be great too?

Yes. So sorry, Robert, it's James again.

So are you looking for what we've already locked in terms of hedges for 2022?

Well, actually the hedging question was just trying to 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 – just reverse itself out if you've got similar volumes for next year?

So I mean, if I understand your question, I think it was about $5 to $6 is what we had in Q3. And obviously the frac spread heading into 2022 is higher than where we were in hedge for pretty much the entire 2021 calendar year.

So we are hedging right now well above the $26 that we've been enjoying throughout 2021. I mean, we've seen frac spreads go out to about as high as $40.

So right now we're probably averaging closer to the low 30s in terms of some of the hedges that we've executed for 2022.

Okay. I can take that offline, I guess, just Randy though on the extraction premiums, is there anything that we should we be expecting material up less than extraction premiums in 2022, just getting where frac spreads are?

No, we, from where we have our extraction facilities this, we won't be impacted by higher extraction premium. So I'm sure there will be, but it's not going to be material for us.

Perfect. Thank you.

Hi, thanks. Good morning.

On [indiscernible] and your comments around sheltering, the commodity price over the next few months. I'm wondering if you can maybe comment on what percent of the commodity bill is comprises the consumer bill.

Also curious around is there – like impact between earnings and recovering that commodity price and cash flows, and also, can you comment on historical sensitivity consumers to these higher gas prices in the past?

I'll let Blue address that.

Yes. Hi Ben.

So a couple of comments. One of the things about both our Washington gas and our SEMCO utilities is about half of our flowing supply in the winter comes out of storage on a normal winter.

And that – of course that storage cost this year is maturely lower than the winter strip. So that's a built in protection for the customer base right out of the get go.

In terms of what percentage is the commodity of the overall bill, obviously that varies by jurisdiction. Remember for us the commodity's just a pastor, right?

It's just a recovery. So obviously you have a little bit of, you have a little bit of risk on higher bills, I mean a higher level of bad debt in collection and some of that, but overall, we expect the bill to be up about 20% on an annualized basis due to commodity cost, all in, which is very consistent of what we're seeing nationwide.

In terms of sensitivity to colder weather, again, you always get a little bit of energy efficiency that comes, it would have to be materially colder across the jurisdiction and what we've seen, we think a big impact on throughput, but those are kind of the data points if that helps.

Yes, it does. And I was also curious more the consumer sensitivity in the past, and we've seen low gas prices for some time, but it was a period of time where gas prices were quite elevated or consumers pushing back a lot at that time.

And also it sounds like there's not really a huge like impact, I mean, recovery your commodity price quite quickly. It's not a deferral mechanism where you recover over the next couple of years?

That's correct. Yes, that's right on the commodity recovery.

That's right.

Okay. And maybe the consumer side of things, I mean, maybe not commenting historical, but you hearing or expecting any pushbacks on this 20% increase?

No, well, I mean, none of us like higher bills, right. So the good news is I know that maybe that's the wrong term.

The – it's well covered in both the regional and national press in terms of energy prices across the country. And so it's not a surprise.

We too of course put out information in press releases to our consumers so they can plan accordingly. We also have energy efficiency programs and we offer help them, winterize their home, do some of those things point them to energy assistance funds and those type of things.

And so we we're very public about that opportunity as well. The other thing that we talk about that I think is understood may not be understood at the individual consumer level, but it certainly understood at the commission level is while natural gas prices are up.

So is every other commodity. And when you look at the cost of actually heating a home for the winter, natural gas is still the lowest cost option compared to the other alternatives, which obviously include electric, home heating oil, propane, et cetera.

It's still materially cheaper against all of those. So, those things are all balancing points when we have those conversations at both the commissions and the consumer level.

All right. That's great.

That’s very helpful too.

Thanks. Good morning.

Guess the questions for Randy, and it's more of a strategic bent, and it's really looking at the big picture perspective of the turnaround that you've already gone part way through maybe not fully there for restoring all the value in the company. But when you look at the utility business where you still have some ROE restoration, some CapEx catch up and some other stuff going on, and then the lumpiness on the midstream side where you've had some incremental capital got deployed, big step ups in EBITDA contributions and then overall deleveraging other company.

Like how do we – how do you think about just pace of growth and strategic for AltaGas overall with the business mix that you have, and just some of those underlying issues associated with the differences of the business?

Yes. Thank you for the question, Andrew.

I appreciate it. As I've stated in the past, we remain focused on operating our long live infrastructure assets, right?

That we're committed to our long term strategy, building a diversified utility in midstream business and when I came here in December of 2018, I talk about the restructuring as you pointed out, and the enviable opportunity for growth that I felt for our company. And I would tell you that our diversified model and strategy is working and see it in our performance and our operational results as well as our performance in our stock price.

So I think that as we sit here today, we're going to continue to remain focus on executing our strategy, de-risking, de-leveraging and optimizing the immense upside that we have in both businesses. And so at this point, that's our primary focus and I think it's working

Appreciate that. And then I guess if we sort of look back at RIPET in particular, and then what you've done with Ferndale thus far, I clearly RIPET there's 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 three to five 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 and the question. I completely compare, I have been more excited about the opportunities that we've in front of us and what we've demonstrated, Randy, and his team.

RIPET becoming an energy logistics and export company and the team has done an outstanding job to validate that model going forward. In terms of your question in the next few years, yes, I think you're going to see us continue to invest in increasing the scale of this business and locking in longer term contracts with customers both on in Asia and beyond.

And so I think that you'll see that continue to accelerate and we'll talk a little bit more obviously in the upcoming Investor Day. But yes credit to the team, but again, I think the future is about moving this cleaner energy and fuels to Asia out of this tremendous Montney basin.

And I think that we are also, there's tremendous option value as you look ahead toward alternative fuels. And as we continue to move the cleaner LPG fuels into the future we think we're well positioned through our ports and access to move the fuels of the future as well.

So again, we're going to continue to invest, increase that scale and I think we're going to drive real value. I know we are to our customers into Canada as well.

Okay. Thanks, Randy.

Appreciate it. Thank you.

Robert Catellier from CIBC. I just wondered if you could elaborate on the comments it has in the MD&A about the pace of activity recovery specifically the impact of the interim resolution between the government of B.C.

and the Blueberry River First Nation. And maybe you could also talk about the relatively modest stated drilling intentions from the major producers and the B.C.

royalty review as well?

Thanks for the question. I'll let Randy Toone specifically with the Blueberry River.

Hi, Robert. Yes.

So the – we've always had a very collaborative and strong relationship with the [indiscernible] First Nation members. And when we look at development, we've always took a balance between environmental and with economic needs.

And when you look at the [indiscernible] and what they've publicly talked about was that they're not – they're not – they don't want to stop development. They want a say in development, and I think AltaGas has always worked collaboratively with them to give them a say in how we develop.

And so they – we're encouraged by some of the discussions they're having with the B.C. government.

And we think that they're going to come up with a process going forward that will continue to have development because that, that resource is so valuable. And when we look at our customers, a lot of our customers have been proactive and they already have permits in place and some of our customers are not slowing down.

And so we do still think that that resource is going to be developed and we think that we're in a good spot to work with our customers to help develop it.

And just the royalty review too early to tell, I know. But any indications since that causing any variability and drilling attention?

Well, what we know about the royalty review is that they're taking a look at the process and seeing if they can make it simpler. And I do – what we know is that they're looking quite a bit at the Alberta royalty process.

And we're very familiar with that and so we're not – we're not worried that it's going to have a huge impact on-site development in that area.

Okay. And I know quite early days, but there's an update to the B.C.

climate plan. I wondered if you see any impact on that to your business specifically, methane emission targets and requirements there?

And also there's some indications that the new projects have to have enforceable plans to meet at 0.250. Do you see any – any immediate impact that you can talk to with respect to how you might develop a midstream business there?

Yes. We've took a look at the B.C.'

s new climate plan, and when we look at our facilities, we're always looking at reducing our carbon footprint. And so we are looking at electrification of our facilities or carbon capture and working with our customers to do that.

And we just don't think that that's going to slow down anything, it's just going to change the way we might develop.

Okay. That's fair.

Last question for me; I wondered if you could – there's a couple of comments about growth in G&A both in the utilities and in the corporate segment. I mean, I wonder if you could attribute that between just the growth you're seeing as an enterprise and the effects of inflation?

Yes. I think the growth is in, and others is to a large extent this quarter related to accruals in that long-term incentive.

But overall, I think the growth and the cost is consistent with the growth in the business. And I think the team's done an excellent job of managing its cost and implementing the digitization and new technology for productivity overall.

And I think that's generally, in this quarter it's particularly related to the long term incentive plan.

Okay, fantastic. Thank you.

Thanks, Kelsey. And thank you everyone, and once again for joining our call today, and for your interest in AltaGas.

And as a reminder the Investor Relations team will be available after the call for any follow-up questions that you might have. That concludes our call this morning.

And I hope everyone enjoy the rest of their day. You may now disconnect your phone lines.