Avista Corporation (AVA) Q1 2019 Earnings Report, Transcript and Summary

Welcome to the Q1 2019 Earnings Conference Call. My name is James. I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] And also note this conference is being recorded. I'd now like to turn the call over to John Wilcox, Investor Relations Manager. John, you may begin.

Thanks, James. Good morning, everyone, and welcome to Avista's first quarter 2019 earnings conference call. As an introduction, I've been with Avista since 2001 and have spent most of my time with the Company in SEC reporting and energy resources accounting. I'm a proud University of Washington graduate, and I'm excited for my new role. Our earnings were released pre-market this morning, and our first quarter 10-Q was filed on Wednesday. They are both available on our website. Joining me this morning are Avista Corp. Chairman of the Board and CEO, Scott Morris; Senior Vice President and CFO, Mark Thies; Vice President, External Affairs and Chief Customer Officer, Kevin Christie; and Vice President and Controller, Ryan Krasselt. I would like to remind everyone that some of the statements that will be made today are forward-looking statements and 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 2018 and 10-Q for the first quarter of 2019, 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 first quarter of 2019 were $1.76 per diluted share compared to $0.83 for the first quarter of 2018. Now I'll turn the discussion over to Scott.

Thank you, John, and congratulations on your new role as the Manager of Investor Relations. I'm excited that we recently announced the goal to serve our customers with 100% clean electricity by 2045 and have a carbon-neutral supply of electricity by the end of 2027. This commitment bolsters our longstanding history of providing clean, reliable and affordable energy to the customers and communities that we serve. We announced this 100% clean electricity goal as an important step forward in caring for our environment while continuing to meet the energy needs of our customers and communities today and well into the future. We've already begun working toward our goal because in the last three years, we've implemented three renewable energy projects on behalf of our customers, two solar projects and one wind project, all located in Washington State. In addition, last week we announced an agreement with the California Independent System Operator to participate in the Western Energy Imbalance Market, which furthers our commitment to integrate renewable energy into our electric generation resource mix. We expect to begin implementing new processes to enable participation in the EIM in the second half of 2019, and we expect to be full participants in the market by April of 2022. In late April, the Washington State Legislature passed Senate Bill 5116. The bill establishes three standards applicable to us. First, on or before December 31, 2025, we'll no longer be allowed to use output from coal strip to serve loads in Washington. Second, by January 1, 2030, we must serve no less than 80% of our load with conservation and renewable and non-emitting generation. And three, by January 1, 2045, we must serve our entire load with renewable and non-emitting resources. The legislation also contains provisions that we believe provide the Washington Commission tools for constructive regulatory decisions that may allow us to reduce regulatory lag while providing more future rate certainty for customers. With regards to our quarterly results, our consolidated earnings were below our expectations for the first quarter. However, we remain on track to meet our guidance for the full-year. Our first quarter 2019 earnings were positively impacted by the receipt of the termination fee from Hydro One. AEL&P and our other businesses each had a good start to the year. In addition, we're excited to announce that during April, we sold our subsidiary, METALfx, for the net proceeds of about $17 million, and we expect to recognize a net gain of about $2.4 million during the second quarter of this transaction. We want to thank the entire team at METALfx as it has been great to work with them over the past 20-plus years, and we wish them well into the future. Regarding regulatory matters, on April 30, we filed general rate cases in Washington that are two-year rate plans. If approved, the electric general rate request is designed to increase annual base revenues by $45.8 million effective April 1, 2020, and $18.9 million effective April 1, 2021. For natural gas, if approved, the general rate case is designed to increase annual base revenues by $12.9 million effective April 1, 2020, and $6.5 million effective April 1, 2021. The electric and natural gas rate requests are based on our proposed rate of return on rate basis of 7.52% with a common equity ratio of 50% and a 9.9% return on equity. We also filed general rate cases in Oregon in March. And if approved, the request is designed to increase annual base revenues by $6.7 million. The request is based on a proposed rate of return on rate base of 7.55% with a common equity ratio of 50% and a 9.9% return on equity. We are evaluating filing in Idaho in the second quarter. The purpose of all our general rate cases requests is to recover the costs associated with our capital investments to replace aging infrastructure and for reliability, resiliency and technology improvements. So now I'll turn it over to Mark.

Thanks, Scott, and good morning, everyone. With my normal Blackhawks comment, we didn't make the playoffs for a second year in a row. But to make pour salt on the wound, when we go down to AGA, I will have to wear a garish New York Rangers tie, so that's going to really hurt. So if I see any of you down there, please don't comment. For the first quarter of 2019, Avista Utilities contributed $1.70 per diluted share compared to $0.84 in 2018. The increase in earnings for the first quarter was primarily due to the receipt of the termination fee, as Scott mentioned, from Hydro One as well as a positive impact from general rate cases and customer growth. The increases were partially offset by transaction costs and taxes associated with the terminated acquisition, increased net power supply cost, transmission and distribution operating and maintenance costs and depreciation and interest. The ERM in Washington was a $2.5 million pretax expense in the first quarter of 2019 as opposed to a $4.9 million pretax benefit in the first quarter last year. With respect to capital, we continue to remain committed to investing the necessary capital to maintain the vibrancy of our utility infrastructure. We expect Avista Utilities capital expenditures to total about $405 million in 2019. As of March 30, we have $220 million of available liquidity under our committed credit lines at Avista Utilities. And in 2019, we expect to issue approximately $165 million of long-term debt, and that includes repayment on a $90 million maturity we have later in the year and up to $50 million in equity in order to refinance maturing long-term debt, fund our planned capital expenditures and maintain an appropriate capital structure. With respect to guidance, as Scott mentioned earlier, we're confirming our 2019 guidance for consolidated earnings to be in the range of $2.78 to $2.98 per diluted share, which includes $1.01 per diluted share related to the termination fee and the payment of remaining transaction costs. We anticipate continued regulatory lag during 2019 through 2021. And as Scott mentioned, we filed rate cases in Washington and Oregon and are evaluating filing in Idaho in the second quarter. We expect these cases to provide rate relief in early 2020 and to begin reducing this regulatory lag. Going forward, we expect to continue to reduce that lag and get our authorized returns back to earning our authorized level by 2022. To achieve this, we anticipate annual earnings growth rate of 9% to 10% from 2020 and 2022 with a return to normal 4% to 5% growth rate following 2022. The growth rates are based on the midpoint of our 2019 earnings guidance as the starting point, excluding the $1.01 per diluted share related to Hydro One. These growth rates also assume timely and appropriate rate relief in all of our jurisdictions. Our 2019 earnings guidance range encompasses unrecovered structural costs estimated to reduce our return on equity by approximately 90 basis points. And in addition, our range also includes regulatory timing lag of approximately 105 basis points. This results in an expected return on equity for Avista Utilities of 7.5% in 2019. We expect Avista Utilities to contribute in the range of $2.72 to $2.86 per diluted share, again, including $1.01 related to the Hydro One cost, net of transaction costs. The midpoint of our guidance at Avista Utilities does not include any expense or benefit under the ERM. Our current expectation for the ERM is a benefit position in the 75%, 25% band, which is expected to add approximately $0.05 per diluted share. This is a reduction of about $0.02 per diluted share from our call at the end of the year in February. Our outlook for Avista Utilities assumes, among other variables, normal precipitation temperatures but below-normal hydroelectric generation for the remainder of the year. For 2019, we expect AEL&P to contribute in the range of $0.09 to $0.13 per diluted share. And our outlook for AEL&P assumes, among other variables, normal precipitation and hydroelectric generation for the remainder of the year. We expect other businesses to be between a loss of $0.03 and a loss of $0.01 per diluted share, which includes the costs associated with exploring strategic opportunities. Our guidance includes only normal operating conditions and does not include unusual items such as settlement transactions or acquisitions and dispositions until the effects are known and certain. I'll now turn the call back over to John.

And now we will open up this call for questions.

Thank you. [Operator Instructions] Our first question is from Andrew Levi of ExodusPoint.

Hi, I never get the first question.

Well, you did this time Andy.

I might be the only one. So how you guys doing?

Good.

By the way, your new IR Director was very, very helpful to us. Just FYI on that.

That's good.

Good choice. I just wanted to go over a couple of things. I guess just first, I mean for this year, I kind of understand. As you get into next year, I guess as I kind of built my model, I was getting a little confused on the 9% to 10% for 2020 relative to - off of the 2019 number. So just a couple of questions around that. Are you guys assuming that you get your full asks in the three jurisdictions? Or is there another assumption in that 9% to 10%?

Andy, historically, we have never gotten everything full ask that we've ever asked for. You can go back historically, and we'll get a varying range between maybe 50% and 70%, and it just depends on where we are with different things, but the commission does their work and they cut back some of that from our full ask. So our expectations are - what our expectations are, we don't put the full ask. We put what we expect to get in our forecast and in our guidance. That's why we gave you the range of the guidance and the midpoint of where we're starting from. And then it's just math from your perspective. But we don't give you the breakdown of what assumptions are by jurisdiction or by service. It's just included in the total.

Got it. Okay. And then I guess kind of just around that as well. When you came out with the 9% to 10%, again, for 2020 and 2021, does that assume that rates would only begin in April of each year? Because the first quarter is like 40% or something like that of your total earnings. And so you're not going to capture that in the rate increases in 2020 and then the second step in 2021. And I'm wondering if that was incorporated or that could end up in...

Yes, all that's incorporated. And that's really just solely for Washington, which is our largest jurisdiction. Should we file in Idaho, historically, those have gone into effect on January, and Oregon will be close. We filed in March, so we should be close to January for the rate increase. And assuming, again, the commission approves it and we go through that process. So it's really Washington that's the one that's in April. And that's just where it will be. So yes, that would cause some of that lag as we start.

Okay. I guess I'll have to speak to IR again and figure that out because O&M is supposed to grow, what, 2%, 3% a year? Is that right?

Yes, around inflation, that's what we look at historically.

Okay. And then you have 90 basis points of structural lag. Is that what you said?

Yes.

Okay. I think I got all the numbers right. Okay. And then just as far as this year, the last question on the first quarter. You mentioned it was below your expectation, so I'm just wondering what your expectations were for the quarter.

Well, we don't give quarterly guidance, Andy. But if you look at it, just looking at where the ERM was, it came in a lot lower. We had lower hydro, and that was more - it stayed colder in the mountains, so we didn't get the runoff in the first quarter. We expect our hydro to be about 93% for the year, so we do expect our hydro to be off a little bit. And gas prices were higher in the first quarter due to the colder weather and some problems in moving gas in our part of the country, so we were off in the first quarter about $0.09. But for the year, we expect to be just $0.02 different in the ERM. We still expect to be positive in the ERM, $0.05, than we were - last quarter when we provided guidance, we expected it to be $0.07 positive. So we do expect in our forecast to just be off $0.02 from that.

Got it. I'll let someone else go in. Assume there is someone else. Thank you very much.

Thanks Andy.

Next question from Chris Ellinghaus of Williams Capital.

Hey, guys. How are you?

Hi, Chris.

Hi, Chris.

Scott, can you just talk about the METALfx transaction, what led to that? What was the rationale?

I'll let Mark do that because he led the team on that, and he did a great job. So Mark, why don't you go ahead and take that?

Thanks, Scott. So Chris, it was really a couple of things. It was a non-core asset, and we had long worked with the leader there, Gordon Short, who has been the President who ran that for almost 20 years. Gordon was getting ready to retire. We had targets to get to a certain level, and then we felt it made sense to exit and redeploy that capital into other things that made sense for us. And this was just the time to do that. So it worked out. We had a good process, and the team is set up to continue to grow and run that business, and we'll get the capital and redeploy it to our other businesses. So it's just the time was right for us to sell it.

And was that $2.4 million gain part of the original guidance?

No. We don't include acquisitions or dispositions in that. So that will be additional - that will be included in our guidance. We're not changing. That's all within a range.

Right. Also, one of the things that surprised me in the quarter is when I was keeping an eye on precipitation in Spokane, it looked like it was a little bit above normal. So with your sort of below-normal hydro, was that a function of the type of precipitation or different kinds of precipitation in different tributaries? What's the difference between what I could see visibly on precipitation and what your hydro conditions were?

Again, it's also when it melts, right. If it's coming to snow and not rain, it's staying up in the mountains, and it doesn't really matter as much. Spokane is about 20% of our generation, and then the Clark Fork is 80% of our own generation. So it really matters more there. And in the current forecast, like I said earlier when I was opening, we expect to be about 93% hydro. So we were off in the first quarter because it actually was cold in February, and it stayed up in the mountains. It didn't melt. It didn't come down in the first quarter as it normally does. Again, first quarter is not a significant quarter for hydro. It's really second quarter that is. But it all depends on how it melts. And so we expect to be down, and that's all included in our forecast and our expectations for the year.

And Chris, I would just add, if you recall, it was - we had kind of a warmer, drier December, January. We had a great February. March was cold, but there wasn't as much precip in March, quite as much as normal. So February was great. But from an overall perspective, the region is down a little bit on precip.

Okay, great. Thanks. Appreciate it.

Thank you.

Our next question is from Shar Pourreza of Guggenheim.

Hi, good morning. It's actually Constantine here for Shar, had to shuffle through a couple of calls. How are you guys?

Okay. Good morning.

And just a quick question just to follow-up a little bit on kind of the modeling and some higher level ideas. So you mentioned that there is about 200 bps of kind of lag between structural and something that's more of a timing nature. So the current rate case that's filed in Washington, that kind of closes the gap to that number, and that's the two-year plan that takes you through the 9%, 10% EPS growth. And then I guess the question - just to confirm that. And the question would be - so with the new kind of regulatory advances through the bill, through the SB 5116, is there any way to think about how that would change in the future kind of once that gets implemented and once the kind of commission - if you go back to the commission with some of these rules are there? Is the 200 bps the right way to think about the lag?

Well, you're rounding. It's 90 basis points of structural lag and really when we file our rate cases - that's a structural component that doesn't get affected by the rate cases. The 105 basis points is what we're really filing to reduce when we file our rate cases.

Right.

And yes, we do expect as we get work through the commission process and get orders in Washington, Idaho - Washington and Oregon, and if we choose to file in Idaho and Idaho as well, then that would help reduce that lag over the next couple of years. And it will be part of that. So that is correct, and that is our expectation. And with respect to Senate Bill, I'll turn it over to Kevin Christie to talk about that.

Good morning. This is Kevin here. We believe the Senate Bill from a rate or regulatory perspective, offers support for us and our ability to reduce regulatory timing lag. It expressly acknowledges the commission's existing authority to approve multi-year rate plans and other flexible mechanisms. It provides the commission authority to allow for the recovery of cost of property, which becomes used and useful during the period of up to 48 months after rates have been approved. So between those two components, that gives us a support from the commission, a chance of moving up to earn our authorized return.

Okay. And a quick follow-up on the bill as well, how are you guys thinking about the power purchase agreements return? So that - I know there was some language in the bill around that.

Yes. We have the opportunity to the extent that we signed a PPA going forward, so future PPAs, to earn on the cost of that PPA, the cost that we're incurring as the PPA plays out over time. And that's at our weighted average cost of capital.

And the cost that's being incurred is kind of just overall kind of level at which the PPA is being signed, right?

Yes, exactly, on the expense.

Okay. And I guess the last one. Kind of given the regulatory and legislative developments in Washington, how do you view kind of the projected CapEx potentially beyond kind of 2022 as some of the targets start approaching kind of 2025 in terms of replacement of capacity and kind of implementation of energy efficiency and the clean energy programs? How are you thinking in terms of the CapEx and rate-base profile?

Well, one thing - I'll let Mark talk a little bit about that, too. But I would just say that we have a very robust, integrated resource planning process, where we're going to be looking at what best fits our customers from a - whether we build it, whether we do PPAs, how we focus on conservation, what we need from both the energy and a capacity perspective. So there's a lot to think about. We've got a great team that's looking at that, and we'll be able to - we're confident we'll be able to address all of those needs and do it in the best, most cost-effective and affordable way for our customers and what's best for the region. So we don't have exact plans beyond 2022 right now. We're still in the planning process, but we're confident that we'll be able to meet the needs.

And in that process, what's the time line for kind of starting that process once the kind of bill and all the new targets effect?

Well, we do integrated resource planning every other year, so we are in the midst of that planning right now. And as we get through our integrated resource planning process, we'll put together a 20-year forecast of how best to meet those needs. And we have both a near-term and a long-term plan, and then we execute around those plans.

Okay, perfect. And then that answers all my questions. Thank you, guys.

Thank you.

Next question from Vedula Murti of Avon Capital.

Good morning.

Good morning.

I'm wondering now, you filed the rate case in Washington as a two-year proposal. I'm wondering with - given that's a two-year proposal and having that flexibility going forward, it doesn't appear though, that at least right now, having that ability is going to compress the time period over, which the current lag of 105 basis points would be addressed. It sounds like it's more something that once you are able to true that lag up post 2022, that in the future, that that lag simply will have the opportunity to not recur to be minimized. Is that the right way to think about it?

I'm not exactly sure I understand, Vedula, what you're saying. We're filing the rate cases that we expect to reduce our lag over time. Some of that lag, by the fact that - as mentioned earlier on the call, that in Washington, our largest jurisdiction, we won't, in the first year, have the opportunity to have rates go into effect prior to April 1. And with the first quarter being one of our larger quarters in the year, we do expect to have continuing lag in 2020. And we may not get everything we ask for, so it may take some time in that 2020 timeframe. And the commission, we have to work with the commission and all the parties to get that into effect. So that could be spread over those two years. And then we also have the opportunity in 2022 to have another case filed at the end of the two-year plan. So it's a combination of things. If we get treatment that is more favorable early, we can reduce the time frame of that lag. But we don't - what we are anticipating is, by 2022, we'll have our opportunity to get that lag to zero or the 105 basis points. And we will continue to work to make that sooner if possible, but that's not our expectation in our guidance.

Okay. And are there any specific items - there was a discussion about the IRP and some other things in terms of - that we ought to pay attention to that could be a material uptick to, I think it's $405 million approximately CapEx run rate that you currently have through the 2022 timeframe.

I would say not in the near-term. I think those are much more longer-term items that we may have opportunities for looking at our capital, and we'll look at that. But in the near-term, I would look through 2022 and expect us to continue to spend our $405 million of capital at Avista Utilities as well as the capital we spend at Alaska and our other businesses.

Okay, thank you.

Thank you, Vedula.

[Operator Instructions] Question from Chris Ellinghaus of Williams Capital again.

Hey, guys. One more thing on SB 5116, it seems to be encouraging of acquisition of resources. Did you interpret it that way as well?

Chris, this is Kevin Christie again. It's simply providing for that possibility to the extent that that's what makes the most sense as we move forward with our resource planning and the opportunity to keep costs as low as possible for our customers.

So do you see the language of the bill being incrementally an opportunity along the acquisition front?

Sure. It is in the sense that we would be able to earn on the PPA, forward PPA. And that wasn't possible in the past, so that is an opportunity.

Okay, thanks a lot.

Thanks Chris.

[Operator Instructions] And it looks like we have no more questions.

I would like to thank everyone for joining us today. We certainly appreciate your interest in our Company. Have a great day.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now disconnect.