Avista Corp
NYSE:AVA
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Avista Corp
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Good day. Thank you for standing by, and welcome to the Avista Corp. Q2 2021 Earnings Conference Call. [Operator Instructions].
I would now like to hand the conference over to your speaker today, John Wilcox. Thank you. Please go ahead.
Good morning, everyone, and welcome to Avista's Second Quarter 2021 Earnings Conference Call. Our earnings were released premarket this morning and are available on our website.
Joining me this morning are Avista Corp. President and CEO, Dennis Vermillion; Executive Vice President, Treasurer and CFO, Mark Thies; Senior Vice President, External Affairs and Chief Customer Officer, Kevin Christie; and Vice President, Controller and Principal Accounting Officer, Ryan Krasselt.
I would like to remind everyone that some of the statements that we made today are forward-looking statements that involve assumptions, risks and uncertainties, which are subject to change. For reference to the various factors which could cause actual results to differ materially from those discussed in today's call, please refer to our 10-K for 2020 and 10-Q for the second quarter of 2021, which are available on our website.
To begin this presentation, I would like to recap the financial results presented in today's press release. Our consolidated earnings for the second quarter of 2021 were $0.20 per diluted share compared to $0.26 for the second quarter of 2020. For the year-to-date, consolidated earnings were $1.18 per diluted share for 2021 compared to $0.98 last year.
Now I'll turn the discussion over to Dennis.
Well, thanks, John, and good morning, everyone. I hope your summer is going well and that you're staying safe. On June 30, Washington State officially lifted most of the remaining restrictions that have been in place during the pandemic. We're excited to see our local economies continue to recover. We're experiencing increased loads, and customer growth is steady. Like many other businesses, we continue to monitor the pandemic very closely and watch what's happening with variants and case count in our communities. We're ready and able to successfully adjust our business as needed and also continue to provide care and compassion for those who are struggling.
Now let's look at some highlights from our second quarter. We had a challenging second quarter, which included an unprecedented heat wave that brought with it several consecutive days of triple-digit record-breaking temperatures across the region. On June 29, Spokane temperature soared to 109 degrees, setting new record -- a new record high temperature and was even higher in many of our neighborhoods. That same day, Avista experienced a major increase in customer usage, which resulted in the highest energy usage in our company's 132-year history. The intense temperatures, combined with record high usage, strained parts of our electrical system and caused some of the equipment that runs our electric grid to overheat. Six of our 140 distribution substations were impacted.
To prevent the equipment from overloading and to avoid extensive and costly damage to our electric system, we implemented protective outages for customers served by the equipment that was most impacted by the heat. Over the course of the event, we were able to reduce the impact to customers through system modifications. We appreciate our customers' patience for those who experienced outages.
Higher customer loads, related to the extended heat wave, were the primary driver for an increase in net power supply cost to serve our customers, which negatively affected the Energy Recovery Mechanism, or ERM. Overall, we've experienced hotter and drier-than-normal weather across the Pacific Northwest, which contributed to lower-than-normal hydroelectric generation and increased power prices. For these reasons, we had to rely on thermal generation and purchased power at higher prices to serve those additional loads. As a result, Avis Utilities' earnings were below expectations for the second quarter.
AEL&P's earnings met expectations in the second quarter, and they are on track to meet the full year guidance. It was a strong quarter for our other businesses, which exceeded expectations due to gains on our investments and the sale of certain subsidiary assets associated with Spokane steam plant.
Wildfire resiliency continues to be a focus for Avista. Our region has experienced extremely dry conditions all spring and summer. And combined with high temperatures, wildfire risk is high. In response to these conditions, Avista has been operating in, what we call, dry land mode since late June, and dry land mode decreases the potential for wildfires that could occur when reenergizing a power line.
Normally, under normal conditions, these lines, located in rural and/or forested areas, are generally reenergized automatically. However, during the current dry weather conditions, Avista's line personnel physically patrol in outage area before a line is placed back into service. This can require more time to restore service, but it decreases a potential fire danger.
This practice is in line with Avista's wildfire resiliency plan, which was released last year, building on prevention and response strategies that have been in place for many years. Avista has committed to a comprehensive 10-year wildfire resiliency plan that includes improved defense strategies and operating practices for a more resilient system.
In regards to regulatory matters, we are pleased to have reached an all-party settlement in our Idaho general rate case. The new rates are fair and reasonable for our customers, the company and our shareholders and will allow Avista to continue receiving a fair return in Idaho. Our Washington general rate cases continue to work their way through the regulatory process. Our hearings have been held, and we expect a decision by the end of September.
In Oregon, we expect to file a rate case in the fourth quarter of 2021. We are confirming our 2021 earnings guidance with a consolidated range of $1.96 to $2.16 per diluted share. While we are confirming our consolidated range, we are adjusting our 2021 segment ranges to lower Avista Utilities by $0.10 per diluted share and raise other by $0.10 per diluted share.
For 2022, we are lowering consolidated earnings guidance by $0.15 per diluted share to a range of $2.03 to $2.23 per diluted share. For 2023, we are confirming our earnings guidance with a consolidated range of $2.42 and to $2.62 per diluted share. Although we expect to experience headwinds in 2022 from regulatory lag, we are confident that we can meet our earnings guidance for 2023 and earn our allowed return.
Looking ahead, we'll continue focusing on our utility operations, while prudently investing in the necessary capital to maintain and update our infrastructure to provide safe, reliable and affordable energy to our customers and our communities.
Now I'll turn this presentation over to Mark.
Thank you, Dennis, and good morning, everybody. I know everybody is sitting on the edges or seat waiting for the Blackhawk's next acquisition, which is a Spokane native. We got Tyler Johnson, a 2-time Stanley Cup Champion, who is a Spokane native. So we're pretty excited about that. There's your Hawks update.
As Dennis mentioned, we're confirming our 2021 earnings guidance, lowering our utility guidance for '21 and also '22 and confirming '23 consolidated guidance. Our guidance -- I'll spend a little time on that. Our guidance assume, among other things, a timely and appropriate rate relief in our jurisdictions. That's very important as we need -- Dennis mentioned, we settled our Idaho case. We're still awaiting approval from the commissions, which we expect before those rates go into effect September 1.
For 2021, we expect Avista Utilities to contribute in the range of $1.83 to $1.97 per diluted share, and the lower end of our guidance in '21 and '22 for the Avista Utilities is primarily due to increased regulatory lag. That's due to increase capital expenditures primarily due to growth and higher-than-expected depreciation expense. But that is, we believe, all timing, and we begin -- as we begin to plan for our next Washington general rate case to be filed early in the first quarter of '22, we expect that to be a multiyear rate plan as required under the new law. We will seek to include all capital investment through the end of the rate plan period in rates in an effort to earn our allowed return by 2023.
In addition, we have experienced an increase, as Dennis mentioned, in actual and forecasted net power supply cost. Although the midpoint of our guidance range does not include any benefit or expense under the ERM in Washington, the increase in power supply cost has reduced the opportunity for us to be in the upper half of the guidance range. And our current expectation for the ERM is a surcharge position within the 90-10 sharing -- company sharing band, which is expected to decrease earnings by $0.08 per diluted share. And recall, last quarter, our estimate for the ERM for the year was in a benefit position, which was expected to add $0.06 per diluted share. In addition, we are also absorbing more net power supply cost under the PCA in Idaho.
For 2021, as Dennis mentioned, we expect AEL&P to contribute $0.08 to $0.11. And we increased the range in our other businesses by $0.10, which really offsets the utility reduction, and that's largely due to a range of $0.05 to $0.08 of diluted share because of investment gains and the gain we experienced from the sale of Spokane Steam Plant. Our guidance generally includes only normal operating conditions and does not include unusual or nonrecurring items until the effects are known and certain.
Moving on to earnings for the second quarter. Avista Utilities contributed $0.11 per diluted share compared to $0.26 in 2020. Compared to the prior year, our earnings decreased due to an increase in net power supply costs, as Dennis mentioned, mainly due to higher customer loads from the heat wave, and we had lower-than-normal hydroelectric generation because of the hot and dry conditions. Our hydroelectric generation is about 91% of -- our expectations are normal for this year.
The ERM in Washington also moved significantly. Had a pretax expense of $7.6 million in the second quarter of '21 compared to a pretax benefit of $0.4 million in 2020. Year-to-date, we've recognized $3.3 million of expense in '21 compared to $5.6 million in benefit in 2020.
In addition to the higher power supply cost, we also had higher operating expenses in the quarter, mainly due to the timing of maintenance projects, as many of those maintenance projects were delayed in 2020 because of COVID-19, whereas in 2021, we returned to our original schedules and performed that maintenance in the second quarter. The higher maintenance costs were partially offset by lower bad debt expense as we are continuing to defer bad debt through our COVID-19 regulatory deferrals.
Moving on to capital. As Dennis mentioned, we're committed to be continuing to invest the necessary capital in our utility infrastructure. We currently expect Avista Utilities to have increased capital expenditures up to $450 million in 2021 and $415 million in 2022 -- or $445 million in '22 and '23. That's a $35 million and $40 million increase in '21, '22 and '23, $40 million in '23 as well.
And this is really to support continued customer growth. Our customer growth's about 1.5%, which is up from 0.5% to 1% in prior expectations. We expect to issue approximately $140 million of long-term debt and $90 million of common stock, including $16 million that we've already issued through June on the common stock side in 2021. The increase in long-term debt and common stock is to fund the increased capital expenditures.
I'll now turn the call back over to John.
Thank you. And now we would like to open this call for questions.
[Operator Instructions]. And your first question comes from the line of Julien Dumoulin-Smith of Bank of America.
It's actually Kody Clark on for Julien. So a couple of questions here. I guess first, on the guidance reduction in '22. I'm wondering if there's anything else that's driving that outside of just greater regulatory lag and power supply costs? I mean it seems like those factors wouldn't drive that much of a delta. Are you making any assumptions on the Washington rate case that's kind of contributing to that dynamic? Or are you seeing any increased insurance costs just on the wildfire side?
Well, there's some other nominal costs. We really highlighted the big drivers. There are some other nominal costs on O&M, but it really is in power supply. But it's really largely depreciation and lag. Some of it is in some of our capital as well as we deployed capital. It's been in shorter-lived assets that didn't get into the case. So we expect -- we still expect a fair outcome in our existing case, but realize, as we move forward with how we spend our capital and the type of capital we're seeing is that will really get pushed into the next case, which we expect to file like we said in early '22 -- early in the first quarter. And so no, it has nothing to do with -- we continue to expect a fair outcome in our current Washington case.
And it is largely additional capital due to growth and depreciation. There are some other small things. That's the main driver.
Got it. And then just on '23 guidance, I guess, all else equal, you're investing more in '21 and '22, and then you're going to file that case in early '22, but you kind of reaffirmed that guidance range for '23 and also stated that you're still assuming that you're going to get to your authorized in '23. So I'm just kind of wondering what's contributing to your reaffirmation of that '23 guidance range? I guess from my perspective, it should be a little bit higher but...
No, it wasn't a significant move. And the capital assets over long lives have some impact, but it's not a significant impact. So we're still within the range. So rather than have the nuance of moving it a few cents, we just said we've maintained our range. We expect the confidence -- we want to have the confidence that we expect to get back to earning our allowed return on the capital that we deploy. That will be within that range. It wasn't -- the capital move wasn't significant enough to move it. It is improvement, and it's a positive, but it wasn't enough to move our range for '23.
And your next question comes from the line of Sophie Karp from KeyBanc.
So maybe to build on the previous question a little bit here. So you're talking about increased regulatory lag that's partially due to higher CapEx, I suppose, in 2022. Are you correspondingly increasing your CapEx outlook? Or maybe I'm missing it here somewhere?
I'm not -- so are you asking -- we are increasing our CapEx outlook. Is that your question? And that is impacting our...
Yes, yes.
Yes, we are increasing our CapEx outlook. So we're going to go to $450 million for this year and $445 million for '22 and '23. That compares to $415 million previously and $405 million and $405 million. So it is a $35 million, $40 million and $40 million increase. And it's largely due to growth in the cost of really doing the same projects that we have and just the cost of doing those projects as materials have gone up. We believe those projects are very important for our customers. And actually, the growth is good as well for the company.
So that's really -- it's not a fundamental. We don't have any new power plants in there or any other major projects we've added, it's just incremental capital to continue to do what we need to do for our system.
Got it. So okay. That's very helpful color. And so then could you maybe give us a little bit more color on the guidance revision on the other segments this year for 2021. So that goes from negative 5% to 2% to positive 5% to 8%, kind of a little bit more color on what accounts for that would be?
It was really largely driven by the second -- I mean the second quarter -- we had strong earnings in the second quarter, and it was due to investment gains in the funds that we're -- and we're in with the Energy Impact Partners and also the sale of Steam Plant. We had a small gain on the sale of Steam Plant Square as well. So that's really hooked into our actual results, and then we just look at that forward. We're not expecting more significant gains. It's really based on the actual results we had in the quarter.
Yes. Do you disclose what you have on those funds? Is it kind of similar to energy venture portfolios that some of your peers have?
I don't know what the peers are invested in, particularly. But no, the -- we don't disclose what the particular investments of the fund are, just that we have invested in Fund I and Fund II, and we committed $25 million to each fund. And we are investing in those funds continuously. So we don't -- but we don't -- we expect to invest about $15 million in our other businesses in '21 and I believe also in '22. Yes, '22.
Got it. Got it. Okay. And then before I pass it on, maybe on the power supply situation, so clearly, I understand hydro was an issue. What is -- how do you think this is going to stack up in the second half? Is hydro going to become less of a factor in the second half? Maybe if you can give us some color on that? And also remind us how the mechanism kicks in here.
So when we do our estimates for -- and we said $0.08 negative surcharge position, that is for the year. So that does include our expectations for the year of what hydro will be. Now what we do assume is normal hydro. In the summer months and in the fall, we don't expect much rain typically. But in the winter, we do. So we do expect normal hydro conditions for the rest of the fall and into the winter. So that could have some variability, but most of the variability typically, again, occurs in runoff. And that's why we were also down because we got such heat early that it used all the water. And so our hydro is down. Like I mentioned, we're 91% for the year. It's about 50 average megawatts for the year is what the impact is.
And so we -- could we have continued adjustments going forward? Yes, but we incorporate current conditions into our forecast. So it would have to vary from the current condition.
Got it. And so your ability to recover those costs is basically limited by the rate structure there, correct?
Well, the ERM, it's what our power supply cost is. So if the cost of natural gas and our loads and our hydro changes, that would change, but we're in the 90-10 right now. So that's where -- if it gets worse, we only have a 10% impact. It does impact the customers that 90%.
Your next question comes from the line of Vedula Murti from Hudson Bay Capital.
A couple of things. I guess, one, in terms of 2022, you've indicated about depreciation and regulatory line, but you also referenced power costs. So is there like an ERM negative that you're incorporating for 2022 that we ought to be aware of?
Well, the power cost actually reset in our rate cases. So when we come out and give '22 guidance, we will put that expectation in, but our power costs will reset in our rate case, which in Washington, which we expect to be effective October 1. Again, we still need commission approval and all that in order, but we expect that to be effective October 1. And in that case, we expect to reset power supply costs, and then we will have a forward look on what impact that could have in our '22 expectations.
Should we -- okay, that should be fair to say then that the revision downward for 2022 really is not tied to cost at all, it's more tied to increased CapEx and plant and service that's not yet reflected in rates that type of thing?
Correct. There's some minor impacts. Minor. It's really depreciation and capital.
Okay. In terms of equity, you're up to 90. I heard you've done 1-6, 16, such that there's like a 74 left to do?
Correct.
Okay. Now given the elevated capital going forward, is $90 million now a better level on an annual basis? If I recall properly, we were at $50 million on an annual basis kind of every year going forward. Is now $90 million the new number?
We've been in the $50 million to $75 million on average over the past several years. I don't remember the exact numbers. And so -- and it will depend on the cash flows that we have because it's -- also operating cash flows helped offset our needs for equity. But we'll be in our normal ranges adjusted for the additional CapEx.
So if you just assumed, a good assumption would probably be if you assume 50-50 on the additional $40 million, $45 million -- $40 million going forward, that's an additional $20 million to our historical levels. So I don't know that we necessarily get to 90, but we could. We'll have to look at that, and we issue that guidance when we come out in future years.
Okay. Because I guess that you would still be kind of like in a range where needing to do any type of a block or a public type thing as opposed to your various stock plans and at ATM type of program that still looks to be sufficient?
Absolutely. The current ATM program that we have with 4 banks would be sufficient to cover any of our equity needs, we believe. That doesn't mean we don't have the opportunity to do a block under that agreement, but typically, we do it under that program.
Okay. And as I recall, in the past with the discussions coming out increasing CapEx and dealing with just system issues, my recollection is that the $400 million level approximately kind of triangulated with what you felt was an appropriate level of increase in cost to customers that balance things out. Now I'm wondering with increased CapEx here, whether to the extent that there might be -- that there's pressure there because that's a little counter to what I recall previous discussions over the last, say, 18, 24 months?
Well, we've been at the $405 million level for many years. I don't know if it's 8 or 9 years. I don't remember the exact year we went up, but we've been at that level for a long time. So given that, we looked at it and said, "We have more -- we just came out, as Dennis mentioned, with our new wildfire resiliency plan. That added some capital we need to spend over the next 10 years in that plan, and we have our -- we had our plan consistently for a long time. So we decided -- and growth capital has gone up as we continue to add customers and we're joining the energy imbalance market as well.
So there's a number of different needs outside of our regular capital need that we felt now was the time to continue to manage that and increase it slightly. Again, it's about a 10% increase that we felt was prudent, while still understanding that we do have to manage and work through the cost pressures and affordability to our customers. So we didn't -- we've identified that if you look at our regulatory filings, over $500 million of projects we could spend money on every year. And as we have these new things added to that, we still try to maintain our capital at a prudent level, but felt now is the time to move up to the $445 million in the next few years.
And with the 1Q '22 rate filing, can you talk a little bit about the multiyear abilities and some of the other facets that legislation provided you? And how you are thinking about using those to be able to collapse the regulatory lag for '23 and be able to earn whatever return it is?
You bet. This is Kevin Christie. I wanted to describe that a little bit for you. We have, starting with 2022, the requirement to file a multiyear rate plan. It can be as few as two years and as many as 4 years. And in that legislation that moved forward the ability to have the multiyear or the requirement to have the multiyear rate plan, it sets a process or the ability to get the first year right. That's, of course, my words, not how it reads exactly in the legislation. And so that means getting all the capital, assuming that it's prudent capital, and we think we are spending prudent capital in at the rate effective date and then also the transitions from year to year.
I can't say for sure, the duration of the rate plan will file. Some of -- all of this depends on the outcome of the current case, which Mark described, and we expect an order here before October 1. So again, it's -- the legislation provides for the opportunity to bring in good capital up until the rate effective date, and then make transitions based on the capital spend from year-to-year going forward within the rate plan.
And one last question. Can you remind me there's -- you always have structural items that simply are not permitted recovery such that if you're giving a headline number of authorized return, there's a certain number of basis points, you will be underneath it simply because they are fundamentally not permitted. I'm trying to recall whether it's like about 70 basis points or something like that, that's been a consistent policy of regulation for you in Washington?
You're spot on, Vedula. It is -- 70 basis points is our expectation there. And it's really largely costs that are not allowed to be recovered from customers.
[Operator Instructions]. And we do have another question from the line of Julien Dumoulin-Smith.
Kody here again. Just a couple of very quick follow-ups. So just wondering if you could share what you're assuming in terms of earned ROE for '21? I think previously, you pointed to 7.7%, but wondering if that's updated with the guide here?
We're off from that. I didn't really do that calculation. We are -- I mean we're lowing our utility guidance $0.10. So I don't have that. It is lower than the 7 -- 70. You can do the math if you want.
Got it.
Just to project earnings.
Yes. Got it. And then just wondering if there's any updates on the claims from the DNR on the Babb Road fire? Any updates from when we last spoke?
Yes. This is Dennis. Yes, really no updates on that. We're continuing to engage with the Department of National -- Natural Resources constructively. We've had a few minor claims, but nothing material. And the DNR report has come out, and we continue to stand by our position and believe that it was not -- the fire was not caused by any of our equipment deficiencies or any concerns around that. It was just an unprecedented storm that knocked down a tree outside right of way and started the fire. So nothing new from what we've talked about in the past.
Okay. And then are there any fires in your service territory now that we should be aware of?
Yes, well, you can tell by watching the nightly news. If you do that, there's fires all over the Northwest. And there's been a few in and around our service area. Nothing that is material at this point. So at this time, no concerns.
Obviously, as I mentioned earlier, it's really peak fire season, and we -- they are smoky with all the fires in the Northwest. We continue to monitor and manage our system accordingly to mitigate any adverse impacts. But the short answer is really nothing material at this point.
And the ones -- Kody to add to what Dennis was saying, the ones that have started, there's been some lightning -- as some things have come through and lightning again, has caused it, not any deficiencies in our equipment or anything with respect to our equipment.
Yes, that's correct.
And you do have another question from the line of Vedula Murti.
In terms of the reaffirmation of 2023, can you remind us kind of what the -- in terms of that range, what the earned ROE was assumed to be in that period?
Again, we're getting to our allowed ROE minus the 70 basis points. So we're allowed about 9.4% in our jurisdictions. And assuming approvals from the different -- Idaho still pending commission approval. But assuming approvals of the Idaho Commission and no change in Washington, assuming we get our current ROE, it's 9.4% in each of those jurisdictions with 70 basis points of lag, it would be about 8.7% from an ROE perspective.
And there are no further questions at this time. Mr. Wilcox?
I want to thank everyone for joining us today. We certainly appreciate your interest in our company. Have a great day.
This does conclude today's conference call. Thank you for your participation. You may now disconnect.