Avista Corporation Aktie

Good day, and welcome to the Avista Corporation Second Quarter 2026 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker, Stacey Walters, Investor Relations Manager. Please go ahead.

Good morning. Thank you for joining us. Joining me today is Avista Corp. President and CEO, Heather Rosentrater, who will speak briefly in a few moments on current events. Senior Vice President, CFO, Treasurer and Regulatory Affairs Officer, Kevin Christie, is also here and will be available for questions.

As I'm sure you can appreciate, we are going to focus this earnings call on the fires that occurred in Spokane over the weekend. Please refer to our earnings press release and second quarter 10-Q for information that was filed premarket this morning relating to our financial results for the quarter. You can find this information online.

Heather, please go ahead.

Thank you, Stacey. As you may have seen in our press release yesterday and the related Form 8-K filed this morning, multiple wildfires are burning near Spokane, Washington. Fueled by dry and windy conditions, these fires spread rapidly and have devastated our community. Thousands of people, including many of our employees, have been displaced and many are still facing great uncertainty.

Our hearts are with everyone who has had to evacuate their homes, everyone who has suffered loss and all who continue working on the front lines. Our facilities were not involved in starting any of these fires in the Spokane area. We have restored service to customers whose outages were solely related to the public safety power shutoffs. However, we still have electric and natural gas outages in parts of our service territory because of damaged infrastructure, evacuation restrictions and ongoing safety concerns associated with the fires.

At this time, about 7,300 of our 429,000 electric customers are out of power and about 5,300 of our 386,000 natural gas customers are without service. And to reiterate, in areas that were part of the public safety power shutoff event, any remaining outages are no longer tied to that event. They are related to active wildfire conditions and the damage those fires caused. As a result of the fires, we have identified significant impacts to our transmission and distribution infrastructure serving parts of West Spokane.

Multiple transmission lines in the area sustained damage from wildfire activity, and the transmission system was operating with reduced capacity due to the damage. I am happy to share that our crews repaired and energized a key transmission line earlier this morning that significantly reduces the risk of new customer outages due to system capacity constraints. However, we are still assessing the full extent of the damage as emergency responders provide access to impacted neighborhoods and fire conditions allow.

The situation is still very dynamic and the fires in the Spokane area have yet to be contained. We have shared as much as we currently know. And right now, our primary focus is on assessing damage to our facilities, planning for restoration and supporting our customers and employees have been impacted by this tragic event. We will work to provide additional information as it becomes available. Our first priority throughout these events is the safety of our customers, employees, contractors and the communities we serve. We remain focused on assisting impacted communities, coordinating with emergency responders and community partners and restoring electric and natural gas service as quickly and safely as conditions allow.

At this time, we will take questions.

[Operator Instructions] Our first question will come from the line of Shar Pourreza with Wells Fargo Securities.

This is Whitney Mutalemwa on for Shar. Yes, definitely, our thoughts are with the Spokane people. Just to -- can you give us a sense of the extent of the damage to the transmission system? How are you thinking about the cost recovery and insurance treatment while this cause is still under investigation?

I can talk about the extent of the damage. We still have -- we have had repairs, like I said, to one of the critical lines and then a couple of other lines that were damaged, we've been able to repair. But we still have a couple of lines that are out, and we do have access to the areas now. And so our crews are starting that repair on the transmission system. That shouldn't take as long as the repair likely to the distribution system. So that damage is still being assessed, and we'll know more in the upcoming days, the extent of that damage and how long it will take.

And then I'll build on that, Whitney. Of course, many of these assets are long-lived assets. And so from a regulatory lag perspective, there shouldn't be significant impact there. And as we look forward and once the assessment is complete, we can make some determination of whether we file a petition with the UTC. If that ends up making sense, we'll let you know.

One moment for our next question. And that will come from the line of Michael Lonegan with Barclays.

So on the wildfires, I was going back to the cost recovery. I was just wondering, the legislation in the state allows for securitization of wildfire-related costs, correct? Just wondering, anything you could share about that would be helpful.

Yes, they're in the 2 legislative sessions ago, there was a bill that was passed that ultimately allows for securitization. And again, we've said it's too early to assess. Securitization would be for, I would say, much more impactful events than what we're experiencing now. Of course, I don't want it to seem like it's not impactful to all of us that have been involved in the fires or having the fires around us. But from a sheer monetary perspective on the infrastructure, I wouldn't see us being any remotely close to that need.

Okay. And then shifting to the data center negotiation pause. Just wondering if there's anything you could talk about whether there's been any progress that's addressing customer community member and local leader concerns. And I know the MOU remains in place, but you removed the 500-megawatt project as upside to your capital plan. Anything you could share there would be helpful.

Yes, I appreciate the question. And I know there's a lot of questions about the data centers, and I want to take the opportunity to just be clear in how we're viewing it. I do appreciate that customer affordability is a shared priority with our investors, our customers and ourselves. And the shared -- that shared interest to support affordability has been front and center to our response to these data requests that we received.

And as we've consistently communicated, we will not move forward with a new large data center customer unless we're confident that they will make significant contributions to support affordability for existing customers. And we won't move forward with them unless we are confident that our current customers' reliability will be maintained or enhanced. We expect that there needs to be a net benefit for our current customers, and we want to ensure that there are protections in place for our current customers. And so those things have guided the conversations that we have been having internally related to potential updates to our internal processes.

They've guided the conversations that we've had externally with those other stakeholders because as we shared, we know that we are just one part of multiple entities that are required to consider these kinds of requests. And so we have been participating in a broader process, engaging with regulators. There's workshops going on in the Washington regulators, commissioners are holding those. We've been engaging with local partners who are also working through just appropriate new considerations for planning and coordination because the scale of these projects is so unprecedented. So we've appreciated the customer questions that we've gotten.

And again, as you noted, that pause in the MOU has helped us to have more time to explore those internal and external processes. And so we are also working on related to ensuring -- providing the appropriate assurances for customers that they will not -- existing customers will not cover any costs. We're considering updates to potential tariffs, hybrid tariff special contract potentially at the regulatory level that we think could provide additional assurances to customers and potentially working at the state level through policy that has already been brought up last year and will likely be brought up this year. And we think it's a good thing to have those assurances for our customers. So those are the kinds of things, kinds of conversations we're having that will inform how we might move forward with any of those large data center requests that we have.

And then lastly for me, on the Washington rate case, just wondering if you could share how you're feeling coming out of staff testimony in the settlement conference, key debates, where they could head, likelihood of a settlement. Do you think it's going to be hard to reach a settlement because it's the first 4-year plan filed in the Washington state?

Mike, it's Kevin. Thanks for the question. Yes, we've been saying all along that there's pretty key or fundamental differences in points of view on the term of the case. We feel strongly about the 4-year. Others, as you can see through their testimony, do not. And so I think that's proving out that settlement will be quite difficult. But as we look forward and see the positions of the parties, for example, if you look at staff and where they're at, there's a discrepancy on how we got there, but they're not that far from where we're at. And so we think that's constructive as the commission contemplates how to resolve the case at the end of the regulatory process.

And even if you look at the position of public counsel, which seems very stark when compared to where we're at, the lion's share of the difference, there are 2 items. One is return. We think they have a return level that is unacceptable. We think the commission will likely see it the same way based on past practice or history. And then they also did not go along with any adjustment to power supply, which, again, I think power supply is proving that over the last several years, unfortunately, we've got pretty clear knowledge of what's been going on.

And so with all that data in mind, I think the commission is in a good spot there. Staff's perspective on power supply, again, a little bit of a discrepancy on how we get there, but it's relatively close to where the company is at. So again, I don't believe we'll see a settlement take place. We will go ahead and file our rebuttal case here on the 7th, so Friday. And then we'll have a hearing in September -- September 17 through 18, likely. And then the commission will think about the case, and we'll get an order towards the middle of December.

And again, I just want to reiterate that I think from our position, how we position the case overall, the data that we've provided throughout the pendency of the case and as we think about rebuttal and what will be publicly available to you, it's a strong case. And again, the parties for a couple of key issues aren't that far apart from us.

Our next question that will come from the line of Chris Ellinghaus with Siebert Williams Shank.

Do you have any sense from what you've been able to ascertain so far, how long you think it will take to normalize your infrastructure?

It's hard to tell right now. Again, we're still getting into the areas that have been affected. And our first priority is the transmission, and we think that we have a good sense of the damage there. And so that should be -- in the near term, we should be able to get that restored. And then with the distribution and there's a significant structure losses has been shared. And so working through how we support the areas that remain, that's what we're trying to understand better right now and how long that will take. So it's still to be determined.

Okay. Kevin, vis-a-vis the quarter, can you give us any color for the nonregulated benefit for the quarter? What was going on with presumably mostly funds?

Yes, absolutely, funds. And again, Chris, thanks. I appreciate the question. We had a good quarter from a nonregulated perspective, and it really gets back to what we said 1 year ago on the call where we had some headwinds that materialized for various reasons. And we said that the market needed to levelize. We thought that, that would likely happen. And then once again, we would be -- and an expression you know we've used is to get paid a little bit to learn.

And so it's through EIP. We've been clear about that. There is an investment within EIP that went public. And so we acknowledged or had a gain leading up to that IPO. And then as you can see in our documents, we would expect another gain due to the lag that would show up next quarter and it will introduce volatility into that particular investment because that company, ERock has -- is publicly traded, and you can see what's transpired since then.

Most of what will be the gain that we're expecting to recognize next quarter, if you look at current stock price, would then reverse. I'd also share that, that's just one fund in amongst that particular or one investment within that fund, and there will be gains and losses within all of those as well. So there's a netting, but you can take a look at ERock stock price and get a reasonable proxy about what might happen in that fund.

We do think that net-net, it's beneficial to us, obviously, when we can exit and we can exit or EIP cannot exit due to the lockup that typically happens with an IPO for some time. But when they can, that will be beneficial from a cash flow perspective and will help to alleviate some of our equity needs.

Okay. That's helpful. Lastly, this workshop next week at the UTC, is that going to be particularly helpful to inform your MOU situation? And is that part of the reason why you withdrew so that they could hold this workshop?

Here's what I would say is that, that process has been underway for a bit. And it is something that absolutely should benefit us as we go forward. And working with the community will also be key to all of that. So the commission can help, Heather highlighted the fact that we've historically used the concept of a special contract for any large load, and that has worked for us, but we need to give better clarity to others that we are properly protecting them.

And I think the process that will happen with the commission will define that to some extent. And we'll -- if it doesn't, we will make sure we define it. So everybody can have good trust in the process and the protection for existing customers and benefits for existing customers. So again, it will absolutely be helpful. We've said net benefit. I know it's a term that's used mostly in M&A, but we've been using the net benefit expression in both Washington and Idaho for quite some time about how we view large loads and existing customers.

One moment for our next question. That will come from the line of Julien Dumoulin-Smith with Jefferies.

It's Brian Russo on for Julien. Most of my questions were asked and answered. But just maybe you could just talk a little bit about the wildfire mitigation plan and the initiatives, and the benefits that you were able to capture and offer the community over these last couple of days. And then with the PSPS, it seems like they performed very well or as planned, et cetera.

Yes, absolutely. Thank you. I appreciate that question. And that's what we've been sharing is that we believe that our proactive measures have demonstrated that they've been providing value and have been effective. We know it's really hard to -- for the community to be experiencing proactive outages in the public safety power shutoffs. But we did find on at least one of those lines that had been proactively deenergized. We found several trees that fell into the line during our patrol of those lines that we do on every -- on those theaters before we reenergize.

And so that's what we've been able to share, and I think it does give our community a better understanding and appreciation, maybe not appreciation, but a better understanding of why we're doing that. And there's been a lot of conversation about prevention. And that's how we see that tool is it's a tool to prevent the start of wildfires. And that's what we've shared as the situation could have been worse. And we're looking to and appreciate the work that our teams have done to put those things in place, and we do think that they were effective in this really high-risk situation, and that is nice to be able to reinforce the work that we've done there.

So yes, the work -- all the work we've done around vegetation management, all the work that we've done around these real-time situational awareness and then operational changes that we've made do seem to be demonstrating their value.

Our next question will come from the line of Sophie Karp with KeyBanc Capital.

This is Michael on for Sophie. Does the wildfire and related costs make you rethink seeking a 4-year rate case, specifically around the difficulty with forecasting such events?

I think it's just too soon to say about that. Right now, based on what I know, I think the 4-year continues to make sense for us for all the reasons we've previously elaborated. And as a reminder, if we have some kind of extreme event or situation arise during the 4-year rate plan, we can with not something we want to do, but we can go ahead and refile and replace years 3 and 4. So if something were to occur, and I don't think it's this event, but something else were to occur, then we could go ahead and do that. That assumes the commission sides with the company and does, in fact, put in place the 4 year.

Got it. And then do you expect there will be some opportunity to introduce additional wildfire legislation in the next session?

I don't think we're actively looking at this session. I think we'll have the opportunity to work with our other utilities in the region and other stakeholders and maybe in the future. And there is work at the federal level for legislation that we think would be likely the focus area probably, but in the near term, but that's just more of an ongoing effort to explore what might make sense.

I'm showing no further questions in the queue at this time. I would now like to turn the call over to Stacey Walters for any closing remarks.

This does conclude our call today. Thank you all for joining us.

This concludes today's program. Thank you all for participating. You may now disconnect.

Good day, and thank you for standing by. Welcome to Avista Corporation Q1 2026 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Stacey Walters. Please go ahead.

Thank you, and good morning. Thank you all for joining us for Avista's First Quarter 2026 Earnings Conference Call. Our earnings and first quarter Form 10-Q were released premarket this morning. You can find both documents and this presentation on our website.

Joining me today are Avista Corp. President and CEO, Heather Rosentrater; and Senior Vice President, CFO, Treasurer and Regulatory Affairs Officer, Kevin Christie.

We will be making forward-looking statements during this call. These involve assumptions, risks and uncertainties, which are subject to change. Various factors could cause actual results to differ materially from the expectations we discuss in today's call. Please refer to our Form 10-K for 2025 and our Form 10-Q for the first quarter of 2026 for a full discussion of these risk factors. Both are available on our website.

On this call, we will also discuss non-GAAP utility earnings. Our first quarter earnings presentation is posted on our website and includes definitions and reconciliations for all non-GAAP disclosures, including non-GAAP utility earnings. Our non-GAAP utility earnings are comprised of results from our Avista Utilities and AEL&P segments. The unrealized gains and losses that have historically made up the majority of our nonregulated other business earnings can be significant, but they are difficult to predict and outside management's control. Discussion of non-GAAP utility results and earnings guidance reflects management's focus on the core utility business.

And now let me begin with a recap of the financial results presented in today's press release. Our consolidated first quarter 2026 earnings were $1.11 per diluted share compared to $0.98 in the first quarter of 2025. Our first quarter 2026 non-GAAP utility earnings were $1.10 per diluted share compared to $1.01 per diluted share in the first quarter of 2025.

Now I'll turn the call over to Heather.

Thank you, Stacey. It is hard to believe the first quarter is already behind us. The year began with real momentum and the pace of activity across our business has only accelerated. In a short amount of time, we've taken meaningful steps to strengthen reliability and resilience, move forward with our growth opportunities and continue delivering value for our customers and shareholders. We continue to advance important grid hardening work, pursue load growth opportunities and support resource adequacy for our customers into the future, all of which contribute to the long-term strength of our utility.

Our ongoing investment in grid hardening and resilience, including vegetation management, is helping to prevent outages that can occur periodically during inclement weather. Although much of the work is driven by our wildfire mitigation programs, we have experienced benefits resulting from these efforts through enhanced system resilience and storm response preparedness year-round. We found that the predictive tools we developed to monitor wildfire weather conditions also help us better anticipate other weather-related outage risks.

That means we can stage crews and materials earlier and when appropriate, alert potentially affected customers so they can prepare before outages occur. The work we are doing to build a more wildfire resilient system also benefits us day-to-day and smoother operations and results in better outcomes for our customers and the communities we serve. And we saw directly how being better prepared through predictive tools and material pre-staging enables faster restoration work just a couple of months ago.

In March, nearly 60,000 customers were impacted by outages from high winds. And I commend each of the employees and partners who joined us in the restoration efforts, replacing poles, reconnecting lines, and rebuilding infrastructure to successfully restore power to all customers. And I'm happy to say that our grid hardening and resilience efforts improved the overall response to the storm. Related to the work underway to advance our growth opportunities, we remain optimistic about the opportunities ahead. We're planning for the growth identified in our most recent integrated resource plan and potential new large load customer growth in a way that supports customer affordability system reliability and compliance with clean energy requirements.

A key part of this work is strategic resource planning, making sure we have the right mix of resources at the right time and in the most cost-effective way, so we can meet reliability and clean energy requirements without taking on unnecessary expense. And negotiations continue with one of the prospective data center developer customers looking to locate in our service territory with a projected incremental load of up to 500 megawatts. Ensuring appropriate protection for our current customers is a key element of our negotiations as we expect the new large load customers to return a significant contribution to support affordability for our existing customers. We are currently targeting a signed memorandum of understanding with this new customer by May 31.

In addition to negotiation discussions with the potential data center developer, we continue to discuss these opportunities with community leaders and other stakeholders. We are also engaging with policymakers and the Washington Commission regarding data centers to advocate for policies that ensure appropriate allocation of costs and benefits associated with the integration of these large loads. To support resource adequacy for our customers into the future, resource planning is a crucial task. As we work with potential new large load customers, we also continue to work toward final contracts with the projects selected from our recent request for proposal, including the build transfer for a battery energy storage project included in our base capital plan and targeted to come online in 2028.

At Avista, several related processes together inform our decision-making about these future resources as we consider the timing of integrating potential new large loads. Work has already begun on our 2027 Electric Integrated Resource Plan, or IRP. We've made progress with key data points for the IRP like our clean energy implementation plan, which was recently updated and approved by the Washington Commission. Long-term affordability is central to our planning practice as we evaluate the resource needs into the future. And overall, I'm optimistic about the opportunities ahead.

And now I'll hand the call to Kevin for additional discussion of earnings.

Thank you, Heather, and good morning, everyone. Our focus on delivering results at the utility is fundamental to our success. Our performance this quarter reflects the continued commitment of our teams to disciplined cost management. We began the year with solid execution across the business and we're well positioned as we move forward. Alongside our other initiatives, regulatory outcomes are key to our progress. The first settlement conference for our Washington GRC takes place on the 22nd of this month, and we'll continue to work through the regulatory process if no satisfactory settlement is reached.

We continue to invest in our utility infrastructure to support customer growth and to maintain safe and reliable service. Based on updates to project costs, we now expect capital expenditures at Avista Utilities of $615 million in 2026. We expect capital expenditures from 2026 through 2030 of $3.4 billion. We continue to estimate potential capital investment of up to $350 million associated with integrating a new large load customer that would be incremental to the $3.4 billion 5-year capital plan. Integrating that investment in our 5-year projection would result in a rate base growth of 8%.

Our base capital plan also does not include incremental transmission projects like regional grid expansion, and any large load customer additions beyond the customer previously mentioned.

Turning to liquidity. We expect to issue $230 million of long-term debt and up to $90 million of common stock in 2026, which includes $14 million issued in the first quarter. This morning, we are affirming our non-GAAP utility earnings guidance with a range of $2.52 to $2.72 per diluted share for 2026. Our guidance includes expected negative impact from the energy recovery mechanism or ERM of $0.10 in 90% customer, 10% company sharing band. Our current hydro forecast shows above normal levels of generation for the year, we do not expect a material change to our position in the ERM.

The ERM resulted in $0.01 expense in the first quarter, and we expect to recognize the remaining $0.09 to be spread evenly over the second and third quarters expected long-term return on equity at Avista Utilities is approximately 9%, excluding the impact on the ERP. This reflects expected structural lag of 0.6%. Over the long term, we continue to expect that our earnings will grow 4% to 6% from the midpoint of our 2025 earnings guidance. Our first quarter results are a strong start to delivering on our commitment to financial strength.

Heather and I are excited to build on this strength as we look ahead. Now we'll be happy to take your questions.

[Operator Instructions] Our first question comes from Shar Pourreza from Wells Fargo Securities.

This is Whitney Mutalemwa on for Shar. On the electric margin, how should we think about electric utility margin from here now that the quarter has lapsed the Colstrip-related revenue effect? Does 1Q represent a cleaner baseline for the rest of '26? Or are there still a few unusual comparison items we should keep in mind?

Yes. Thank you, Whitney. Good question. We would consider the first quarter a more clean quarter as we go forward, but we'll have to go through the whole year as we compare quarter after quarter from '25, which had Colstrip in it for the entire year and of course, '26 will not. But I think the first quarter of the year is a pretty good representation.

Okay. And then on the regulatory side and in Oregon, just in relation to the FAIR Act transition and as Oregon moves towards the multiyear rate plan, what is the most important element in these discussions that you need to preserve during the transition? Is it the ability to file in late '27 for '28 rates, continued access to interim recovery tools or some form of indexing to avoid a larger first year catch up?

That's another good question, and it's hard to prioritize the 3. They're all very important. If we're going to need to stay out longer while we're working through the proceeding, we, of course, would need some interim rate relief as we continue to make capital investments. And then as we look forward, we've had a lot of success with multiyears in other states like Idaho and Washington to have a quality first year with a strong -- a quality multiyear with a strong first year starting point. That is also equally as important as we look forward. And then, of course, earning a fair return for our shareholders.

Our next question comes from Michael Lonegan from Barclays.

Regarding the large load customer that put on a deposit, how are you feeling about reaching an MOU? Or when can we expect that? I think you said 90 days or so on your last earnings call. And then subsequent to that, how long would the process take to reach an ESA and potentially formally enter your capital program?

Yes. Great question. Thank you. So we shared that by -- we're working towards a May 31 date for an MOU. And so the next step time line would be identified through that agreement. So I don't think we have a clear understanding of what that next step will be, but we're looking towards that May 31 date.

Okay. And then you highlighted previously 1.7 gigawatts remain in your queue, previously of potential large load customers. How are you feeling about that pipeline? Is there an update to that number?

Yes. So we do continue to vet through those opportunities. And we're at, I think, about 1.1 gigawatts now in the queue. And we do think as we continue to work with these customers, then we have higher confidence in what may come to be. So we're excited about the opportunities that are still out there and again, specifically the one customer, but there are other opportunities as well that we're working.

And we're continuing to plan as well to be able to go out and have curated opportunities for customers once we continue to have better understanding of where geographic -- the best geographic locations are that have available capacity. And we do have some of those areas on our system. And so we're also looking to be more proactive also.

And then lastly for me, regarding the Washington rate case, I know later this month [indiscernible] how are you feeling about the prospects of reaching a settlement or given that it's like your -- or given that it's your first 4-year plan, you're filing in the state, do you expect it to be fully litigated?

Michael, Kevin here. Thanks for the questions. We appreciate that. And with regard to the Washington GRC, we're deep in the discovery process, which helps the parties formulate their positions as we enter into settlement. And of course, we're prepping for settlement. And I'd like to think there's an opportunity for us to settle at least some, if not all, of the case. And that being said, as you highlight, this is the first 4 year that any utility as far as we know has filed in the state of Washington.

And so there's a number of issues to work through from a party perspective that might engage in settlement. It's hard to say how constructive or how well we can come together given that they're going to view risks in a certain way, and we're going to view risks in a certain way. So I can't give you a probability of settlement, but I think everybody is going to give it a shot.

Our next question comes from Julien Dumoulin-Smith from Jefferies.

It's Brian Russo on for Julien. Just a follow up on the 4-year multiyear rate plan in Washington. Just remind us of your confidence or ability to kind of manage within the revenue requirements and the return requirements over the 4-year period, albeit with an off-ramp, I think, after 2 years, especially given lately the geopolitical backdrop, fuel inflation, et cetera. How do you -- how can you derisk this plan, if at all, relative to what's been filed?

Yes. Thanks, Brian, for the question. We have -- I guess, I'll start with the off-ramp that you referred to. We have the ability after the first year to file a replacement for years 3 and 4, given the 11-month process. And that would occur if some form of inflation or if we were able to see additional investments beyond what's built into the case, any additional expenditures. We've been very successful in Washington over the last several years, adding deferral mechanisms that help to hedge some of our risk. And in this particular case, we have a new mechanism that we're requesting which is around employee benefits.

That's one of the remaining more volatile, harder to control items for us. And if we were to have success with building that mechanism in and the other mechanisms that we have in place, we should be in pretty good shape. Now when I say that, of course, that's barring some kind of extreme inflationary activity. And then we would have to use that mechanism where we refile if that were to occur. So we feel like we're in a good position to manage the risks that we might see materialize and the company is very, very focused on managing our costs, and we see some opportunities as we look forward. So all of those things, again, combined, so we're optimistic.

Okay. Great. And understanding that you're reporting the non-GAAP utility EPS going forward. I noticed other businesses, there really wasn't any noncash mark-to-market gains this quarter. Just wondering if there's any insight there relative to what we're seeing in the broader market? And then also any additional thoughts on monetizing any of the investments that are more liquid than others?

No, it's nice to see that things have leveled off or appeared to level off a bit from about a year ago. And we think with that coming, we would see relatively minor adjustments overall, you're referring to the bioscience company when you talk about monetization. And to the extent we're excited about the opportunity there. It's a noncore investment, and we'd exit at the point in time that makes sense. If there was value created through that exit, then that would help us with our overall equity needs. And hopefully, we would be issuing low or no equity for a period of time, and that would help, of course, boost our overall earnings.

Okay. Great. And then just you mentioned regional transmission opportunities possibly that would be upside to the CapEx. Can you discuss those some more? Understanding North Plains Connector would likely be post 2030. Just trying to get a sense of if there's incremental upside to the CapEx relative to that $350 million that you highlight.

Yes, I'm happy to cover this one, Brian. So as you mentioned, obviously, the North Plains Connector, which we've talked a lot about, has that opportunity probably beyond the 5-year capital budget. But we are continuing to work with peers and just other regional organizations to identify other opportunities for transmission investment that might make sense for us and our customers. And as you -- we see a lot, we see there's a lot of reports out there acknowledging the need for more transmission in our region, and we do feel that we are geographically blessed where we're in between where a lot of the load growth is and where a lot of the new resources are. And so we do see opportunities potentially in the future for additional investment there and just continue to participate in those activities.

I am showing no further questions at this time. I would like to turn it back to Stacey Walters for closing remarks.

Well, thank you all for joining us today and for your interest in Avista. We hope you have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Good day, and thank you for standing by. Welcome to Avista Corporation Q4 2025 Earnings Conference Call. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Stacey Walters, Investor Relations Manager. Please go ahead.

Good morning. Thank you for joining us for Avista's Fourth Quarter 2025 Earnings Conference Call. Our earnings and 2025 Form 10-K were released premarket this morning. You can find both documents on our website, along with the presentation that accompanies our remarks this morning.

Joining me today are Avista Corp. President and CEO, Heather Rosentrater, and Senior Vice President, CFO, Treasurer and Regulatory Affairs Officer, Kevin Christie.

We will be making forward-looking statements during this call. These involve assumptions, risks and uncertainties, which are subject to change. Various factors could cause actual results to differ materially from the expectations we discuss in today's call. Please refer to our Form 10-K for 2025 for a full discussion of these risk factors, which is available on our website.

On this call, we will also discuss non-GAAP utility earnings. Our fourth quarter earnings presentation is posted on our website and includes definitions and reconciliations for all non-GAAP disclosures, including non-GAAP utility earnings. Our non-GAAP utility earnings are comprised of results from our Avista Utilities and AEL&P segments. The unrealized gains and losses that have historically made up the majority of our nonregulated other business earnings can be significant, but they are difficult to predict and outside management's control. The shift to discussion of non-GAAP utility results and earnings guidance reflects management's focus on the core utility business.

And now let me begin with a recap of the financial results presented in today's press release. Our 2025 consolidated earnings were $2.38 per diluted share compared to $2.29 in 2024. Our 2025 non-GAAP utility earnings were $2.55 per diluted share compared to $2.38 per diluted share in 2024. For the fourth quarter of 2025, our consolidated earnings were $0.87 per diluted share compared to $0.84 per diluted share for the fourth quarter of 2024. Our non-GAAP utility earnings were $0.88 per diluted share for the fourth quarter of 2025 compared to $0.89 per diluted share for the fourth quarter of 2024.

And now I'll turn the call over to Heather.

Thank you, Stacey. And as I reflect on my first year as CEO of Avista, I am struck by how it combined exciting opportunities for growth and investment with an unprecedented level of uncertainty. Yet, just as we have for the last 136 years, our teams leaned in and sustained their focus on executing our strategies.

Before I get into the details, I want to start with how we're thinking about this last quarter. While our results were impacted by a few specific items, our sustained focus led to progress on key priorities, that includes progress on our request for proposal, or RFP; continued discussions with potential large load customers; and steady regulatory activity. All of this supports the strength of our utility over the long term.

We remain committed to delivering safe, reliable energy to the communities we serve and creating value for our shareholders. As we closed out 2025, Avista Utilities results were impacted by both the onetime adjustment of coal strip related investments, which on its own decreased our earnings per share by $0.07, and other timing-related items. Even with those headwinds, we were able to land within the original utility guidance range. And excluding those factors, utility results would have been above the midpoint of our 2025 utilities earnings guidance.

With 2025 concluded, we're excited to look ahead to 2026. Last month, we filed a 4-year rate plan with the Washington Utilities and Transportation Commission. This filing reflects how we're thinking about supporting safe and reliable service over the long term. Among other considerations, our proposal addresses rising costs related to grid modernization, clean energy compliance, purchased power, hydropower infrastructure investments and emerging risks such as wildfires and extreme weather. By filing a 4-year case rather than a 2-year case, we aim to reduce the frequency of regulatory proceedings, provide greater stability and our cost recovery and shareholder returns and provide more transparency and predictability for our customers.

Last month, we announced the projects we selected from our RFP process. The first selection is an upgrade to existing natural gas turbines which will add 14 megawatts of capacity without increasing carbon emissions. Second, we selected a 100-megawatt battery energy storage system to be located in Eastern Washington and to be built and transferred to Avista under a build transfer agreement.

Finally, we selected a 200-megawatt power purchase agreement for wind from Montana and approximately 40 megawatts of demand response programs across our service territory. These projects will bring valuable resilient energy solutions to our portfolio. Since we first reported on our queue of interest from potential new large load customers last year, we've continued to work through conversations with these potential customers. And I am happy to announce that we've received a significant deposit from a data center developer intending to locate in our service territory in Washington.

The initial load is expected to be 125 megawatts, quickly ramping up to a maximum of 500 megawatts. We expect the initial load to come online by 2030, and we'll keep you updated as we make progress. As expected, as we have worked with customers in our queue to evaluate their projects, we are narrowing in on the most feasible opportunities. At present, including the customer just mentioned, approximately 1,700 megawatts remain in our queue of potential large load customers.

We continue to receive inbound interest, and we expect to begin curated recruiting to attract additional interest that could align with specific geographic and electric infrastructure areas of the system that are best suited for large load interconnections. We know affordability is critically important. And as we look to add new large load in our service territory, it's our expectation that agreements we reach, both with our current negotiations and future prospective customers, would make a significant contribution to customer affordability.

We've also made significant strides in expanding our energy assistance programs for our customers in need. These programs help make energy bills more affordable for those that most need the support. Recent enhancements to our best-in-class programs have expanded our reach for energy assistance to as much as 4x as many customers need in the last 2 years. These programs are fundamental to how we think about serving our communities now and into the future.

The opportunities that were a highlight of 2025 continue into 2026. The Washington Commission has encouraged Avista to explore early acquisition of resources to capitalize on tax credit opportunities. We are still evaluating several other RFP bid projects, exploring the acquisition or long-term contracting of these projects to take advantage of tax credits, serve large loads and enhance flexibility until Avista has a need for serving more load.

Beyond generation, additional transmission is needed to move energy from generation resources to load centers. The North Plains Connector is one such project that supports this need, and we have significant additional opportunities closer to home that would improve regional grid reliability and resilience as customer demand evolves.

Finally, earlier this month, the Board of Directors raised the dividend for our shareholders to $1.97 per share. Our dividend is an important component of shareholder return. And for 24 consecutive years, the Board of Directors has raised the dividend for our shareholders resulting in compound annual growth of more than 5% over that time period.

We remain committed to the importance of returns for our shareholders and to the financial strength of our company. We are now targeting a competitive payout range of 60% to 70%, which is in line with our peers. And for the last few years, we've been a bit above our target payout range, which was 65% to 75% during that period. As a result, we expect that our dividend growth rate will be less than the growth in our earnings per share until we reach our target payout range.

And now I'll hand the call to Kevin for additional discussion of earnings.

Thank you, Heather, and good morning, everyone. In each of the last 4 quarters, I've shared with you how strong our utility performance is and how our utility earnings form the foundation of our business and future plans, and that's still true today. We're focused on delivering results at our utility. Of course, we're disappointed by the order we received late in December from the Washington Commission requiring us to adjust recovery of needed investments at Colstrip. .

Were it not for the impact of that order, Avista Utilities would have reported earnings above the midpoint of our 2025 earnings guidance for the segment. I want to emphasize that our utility earnings in 2025 reflect the strength of our operational execution and the continued diligence in the cost management that we've reported in each of our 2025 earnings calls alongside constructive regulatory outcomes, with the exception of the Colstrip order in December.

We've had a quiet fourth quarter in our nonregulated business results, and it appears that valuations have steadied from earlier in 2025. Alongside our other initiatives, regulatory outcomes are key to our success. As Heather mentioned, in January, we filed a 4-year rate plan with the Washington Commission. The single largest driver of our requested rate increase in rate year 1 is power supply cost. Setting an appropriate baseline for power supply cost is pivotal to the success of our rate plan.

We believe the workshops undertaken with the parties after our last rate case provided an understanding of the shifts in our regional power markets. We will continue to work through the regulatory process beginning with the initial settlement conference set for May 22 and the evidentiary hearings on September 17 and 18. We continue to invest in our utility infrastructure to support customer growth and maintain safe and reliable service.

Capital expenditures at Avista Utilities were $553 million in 2025 and are expected to be $585 million in 2026. From 2026 through 2030, we expect capital expenditures of $3.4 billion, a base capital compound growth rate of 5%. This reflects the addition of $164 million to our capital plan associated with the self-build natural gas combustion turbine upgrades and build transfer battery energy storage system selected from our 2025 RFP.

We continue to estimate a potential capital investment of up to $350 million associated with integrating a new large customer that would be incremental to the $3.4 billion 5-year expenditure plan. Integrating that investment in our 5-year projection would result in a compound capital growth rate of 12%. Our base capital plan does not include incremental transmission projects like regional grid expansion or additional generation pulled forward from our 2025 RFP.

In 2025, we issued $120 million of long-term debt and $78 million of common stock. For 2026, we are updating our funding plans and now expect to issue approximately $230 million of long-term debt and up to $90 million of common stock compared to $120 million of debt and $80 million of common stock disclosed in Q3. This increase reflects higher capital expenditures in 2025 as well as additional debt to support liquidity, given the recovery timing of deferrals while maintaining a prudent capital structure.

We are initiating non-GAAP utility earnings guidance with a range of $2.52 to $2.72 per diluted share for 2026. As Stacey mentioned, utility earnings include earnings from our Avista Utilities and AEL&P segments with no other adjustments. The closest GAAP measure is consolidated earnings, and since we are removing the impact of our nonregulated businesses, we are required to refer to utility earnings as a non-GAAP measure.

Last year, we set guidance for these other businesses at 0 and indicated that we expected variability in results due to ongoing cost, dilution and periodic valuation updates. As a management team, we can't control public policy and the valuation losses we experienced in 2025 were the direct result of shifts in public policy and sentiment due to the administration change. By discussing our non-GAAP utility earnings and giving you guidance that is focused where we as a management team are focused, we're striving to limit the noise in our results and communicate with you about where we're headed as a business.

In 2024, a large industrial customer in our service territory contracted with us for electric service. This customer owns transmission rights and has access to procure their own energy. They sought relief in a period of high market power prices through service with us. As market prices have since declined, they notified us earlier this year of their intent to return to procuring their power independently in the power market sooner in '26 than what we had expected. Our 2026 non-GAAP utility earnings guidance reflects a onetime decrease of $0.12 as a result of this departure.

Our guidance includes an expected negative impact from the energy recovery mechanism of $0.10 at the midpoint in the 90% customer, 10% company sharing band. While our current hydro forecast shows normal levels of generation for the year, even if we were above or below normal, there would be no material change to our position in the year.

Over the long term, we expect that our earnings will grow 4% to 6% from the midpoint of our 2025 consolidated earnings guidance. We are raising our long-term expected return on equity at Avista Utilities to approximately 9% excluding any impact from the This reflects expected structural lag of 60 basis points.

Now we'll be happy to take your questions.

[Operator Instructions]. Our first question comes from the line of Shar Pourreza of Wells Fargo Securities.

This is [indiscernible] on for Shar. So just to take a step back and think about the financing, there's just multiple moving pieces in 2026 from the customer departure to the headwind, the variability and obviously the Washington rate case, how are you sequencing financing decisions? What would cause you to pull forward or push out equity issuance? How much flexibility do you have to bridge with debt or hybrids without pressuring the credit profile?

Well, for the guidance that we've expressed here for 2026, we've incorporated the base plan that we've described. So that includes the capital investment and to the extent that we had additional capital investment opportunities, we would need to reassess how much debt and equity we would issue. We issue our equity through a periodic offering program. And so you would see steady progress throughout the year towards that $90 million, again, barring some kind of additional investment opportunity, which would be a positive thing if we had that opportunity.

As far as using other mechanisms, again, we would likely stick with our periodic operating program unless we had a much more significant investment opportunity, and then we would have to reassess whether we'd visit other mechanisms or vehicles.

Understood. And then just following up on the incremental CapEx, I think it's $350 million to integrate a new large load customers. So what's the internal go or no-go threshold before you commit to that type of incremental build? How do you ensure existing customers are insulated if the large load doesn't fully materialize?

Yes. I would start by saying that the next step, now that we have a significant deposit on board from that potential customer, is moving towards an MOU. And we'd expect to move towards that MOU in the next 90-or-so days. And as we work forward there, we would likely have ongoing conversations where -- with the customer. And we -- again, I want to emphasize a point to the extent that we're able to add this customer, they would make a significant contribution back to the system and our existing customers such that it would help with affordability.

And we would ensure that those same customers would not be negatively impacted to the extent that the customer were to start conversations with us, maybe even go to construction and then walk away. We would have in place, in addition to the deposit we would have collateral and security to protect our business and our customers significant amount such that we would expect no impact if they were to walk away. Now that's not the intent. We would expect them to go forward and contribute revenue to the system on an ongoing basis for many years into the future.

Our next question comes from the line of Julien Dumoulin-Smith of Jefferies.

It's Brian Russo on for Julien. Just a follow-up on the financing plan for the potential $350 million upside CapEx. Should we kind of generally model that as 50-50 debt and equity and would you possibly consider hybrids?

Yes. To be clear, we'd expect that spending to start maybe in earnest to the extent that we're able to proceed sometime later this year, but really in '27, '28 and into '29. And we would expect a 50-50 cap structure or funding approach with incremental capital beyond what we've described here.

And to your question around hybrids, we would consider that option if we were able to move forward with that much additional capital beyond the base plan.

Okay. And would you also consider monetizing the other businesses, which, according to the 10-K, have an equity interest value of $148 million as of December 2025? I'm wondering because of your shift in reporting, it just seems that there's a much bigger focus on the utility and are any of those investments considered noncore, so to speak?

Yes. I appreciate you noticing all of that, Brian, and that's exactly the intent here. We would look to monetize some of our nonregulated investments to the extent that there's an opportunity to do so with a material gain. And if that were to take place, that would help affect our equity, meaning that we would issue less equity on a go-forward basis. That would be the likely plan.

Okay. Great. And one more question. Just to be clear, the 4% to 6% EPS -- long-term EPS CAGR correlates to the 5% rate base CAGR; therefore, this 12% hypothetical rate base CAGR would, in theory, be accretive to the 4% to 6%, correct?

Yes. Let me walk you through that. So the way I think about it is, so the 5% CAGR on our capital investment plan over the next 5 years, you'll notice from the graphic that we were displaying that we have an increase in the middle due to the RFP. And so to call it 5%, I'd say that's a bit conservative. We have a significant increase from year 1 through 3 when we execute on the investments related to the RFP in 2028.

And then in the back end, we would expect that we have additional investment opportunities, hopefully, the large load and more, and then that would pull us up to the 12% rate base CAGR. If we had that opportunity, and all those investments came to fruition, that would help pull us up to the top end of the 4% to 6% range. I don't have exact figures, and we don't know yet all the investment opportunities that we might have, whether we could get above the 6%, but we would talk to you about that in subsequent quarters.

Okay. Great. And then one more lastly, on the large customer, would you look to file a large tariff or an ESA?

Yes. We call it a special contract, and we would file that special contract with the commission in both Washington and Idaho. And when we file those special contracts, which is a pretty standard approach in our states for large customers, we would expect the commission to look favorably upon a large load special contract to the extent, as we've said before, we would be providing significant benefit back to existing customers from an affordability perspective. So I think that the commission would carefully review, but we're encouraged by the fact that it could help with affordability.

[Operator Instructions]. Our next question comes from the line of [ Chris Hark ] of Mizuho.

I just have a follow-up question on the CAGR there. Just given the low result in 2025, do you still expect to be in the 4% to 6% range? And then what kind of ROE are you using to get to the midpoint of the 2026 guidance?

Yes. We certainly believe that we can get to our 4% to 6% growth. 2025 was our baseline. And although we fell short there over the next 3, 4 or 5 years, we'd expect to be in that 4% to 6% range. So that is the plan, and we think we can get there. What was your second question, [ Chris ]? .

And then the ROE that you're using to get to 2026 guidance, assumed ROE?

Well, again, we've expressed here that we expect to be at on a long run basis at 9%, which is an increase from 8.8%. And that incorporates the or does not include the I should say. So in 2026, as we've described to you here, we're going to have pressure on that 9% due to the fact that we're likely to be, as we've said here, $0.10-or-so negative and then we continue to have structural lag around 60 basis points. We also lost that large customer, which has an impact. So overall, we would expect to be in the low to mid-8s in 2026 from a utility ROE with the

Okay. Super helpful. And then just one last thing, just looking for some clarity on the rate base CAGR. Have you included that upside CapEx in the CAGR at all?

The upside CapEx is not included. We're using the incremental $350 million related to a potential large load as a proxy for what -- how it could help from an overall investment opportunity. And to the extent that we are able to pull forward additional items from or investments from the RFP, and we have the opportunity to invest in additional transmission, that would all be incremental to that base.

I am showing no further questions at this time. I would now like to turn it back to Stacey Walters for closing remarks.

Thank you all for joining us today and for your interest in Avista. Have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Good day, and thank you for standing by. Welcome to the Avista Corporation Q3 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Stacey Walters, Investor Relations Manager. Please go ahead.

Good morning. It's great to have you with us for Avista's Third Quarter 2025 Earnings Conference Call. Our earnings and third quarter Form 10-Q were released premarket this morning. You can find both documents on our website. Joining me today are Avista Corp. President and CEO, Heather Rosentrater; and Senior Vice President, CFO, Treasurer and Regulatory Affairs Officer, Kevin Christie. We will be making forward-looking statements during this call. These involve assumptions, risks and uncertainties, which are subject to change. Various factors could cause actual results to differ materially from the expectations we discuss in today's call. Please refer to our Form 10-K for 2024 and our Form 10-Q for the third quarter of 2025 for a full discussion of these risk factors. Both are available on our website.

I'll begin with a recap of the financial results presented in today's press release. Consolidated earnings year-to-date in 2025 were $1.51 per diluted share compared to $1.44 year-to-date in 2024. For the third quarter of 2025, our consolidated earnings were $0.36 per diluted share compared to $0.23 per diluted share for the third quarter of 2024. Now I'll turn the call over to Heather.

Thank you, Stacey. I want to start by highlighting that our third quarter results underscore the strength of our core utility operations and our disciplined approach to cost management. Year-to-date results at Avista Utilities of $1.63 per diluted share reflects a nearly 15% increase over 2024's year-to-date results. This reflects the constructive regulatory outcomes and diligent capital deployment that continue to enhance our financial performance and advance our long-term strategy. As we pursue our strategic initiatives, including the project shortlisted in our 2025 request for proposals or RFP, we remain firmly committed to supporting reliable and affordable customer service, community investment and shareholder value.

Today, we are affirming our earnings guidance with Avista Utilities expected to be at the upper end of its guidance range and consolidated results expected at the lower end of the range due to valuation losses in our other businesses during the first half of the year. The 2025 wildfire season has ended, and I'm pleased with the significant progress we've made with our wildfire resiliency program. We concluded the season without needing to initiate a public safety power shutoff, fortunately, but we were well prepared to elevate our system into risk responsive levels as conditions warranted. This success is the direct result of strategic grid and process improvements, continued collaboration with communities and first responders and the dedication of our team.

This summer, we completed pilot projects for both strategic undergrounding and installation of covered conductor. We'll be building on this work going forward. With the lessons learned and forming our key decision-making about where and how to deploy these technologies as we advance towards our grid hardening goals. In addition, we began installation of weather stations throughout our service territory. These stations bring critical real-time data to our operations team and inform future system design decisions. Our goal is to have a weather station installed on every circuit by 2029. We also expanded our network of AI-enabled cameras, giving our teams and first responders greater access to wildfire monitoring and early detection tools. By the end of 2026, we expect to have coverage of a majority of our high-risk areas through these technologically advanced cameras. All these tools continue to improve and expand the data that goes into our fireweather dashboard, which enables us to react faster to changing conditions and better understand and mitigate risk.

This month, we will submit our wildfire mitigation plan to the Idaho Public Utilities Commission. We've been filing our wildfire mitigation plans with the commission for many years now. However, this will be the first wildfire mitigation plan filed after the Wildfire Standard of Care Act was passed by the Idaho legislature earlier this year. The new legislation establishes a standard of care for wildfire risk mitigation and utilities reasonably implementing their plans will now have protection against liability for wildfire in Idaho. And in Washington, we're working through the rule-making process with other stakeholders following the Washington legislation also passed earlier this year around filing and approval of wildfire mitigation plans.

We kicked off our 2025 all-source RFP back in May, looking for up to 425 megawatts of new capacity and at least 5 megawatts of demand response. As I mentioned in last quarter's earnings call, we saw a positive response to the RFP receiving over 80 bids with 69 supply-side bids totaling nearly 14 gigawatts of capacity and 17 demand response projects offering almost 300 megawatts. We've narrowed the responses down to a short list and these bidders sent in more detailed proposals in October. There's 1 final chance for bidders to refresh their prices this month. From there, we'll make our final project selections and start negotiations before the year-end. The shortlist has diverse options with supply-side resources like wind, solar, storage, stand-alone and hybrid and thermal as well as demand response projects.

There's a mix of ownership options, too, including self-builds, build transfer agreements and power purchase agreements, which gives us more financial flexibility. Some projects are in Montana and could leverage our existing transmission resources in the state as modeled in our integrated resource plan. A big focus is on taking advantage of federal tax credits before they expire. To fully qualify, selected projects need to begin construction by July 2026 and be online by 2029 to 2030. We are working with shortlist bidders to make sure everyone is on track to meet those deadlines and get the most out of any applicable tax credits.

I continue to be optimistic about the opportunities ahead, particularly as we engage with potential large load customers. These conversations are increasingly central to our long-term planning and investment strategy. Our RFP is helping us evaluate new generation resources and system capacity and is playing a key role in informing our discussions with large industrial customers who are exploring expansion opportunities within our service territory. We're working closely with several of these potential customers to assess how incremental load can be integrated into our system in a way that supports reliability, affordability and long-term value.

Serving this level of demand will require not only new generation but also regional grid expansion. System impact studies show we have capacity to accommodate a portion of these requests. With these near-term opportunities best suited to serve customers with scalable implementation capability. We are committed to being competitive in attracting these loads and we view them as an important tool to support customer affordability and as a catalyst for innovation, infrastructure investment and long-term value creation. We'll continue to update you on our progress in future calls. Now I'll hand the call to Kevin for more discussion of our earnings.

Thank you, Heather. I'm pleased to report a beat to market expectations with our third quarter financial results. Our third quarter results reflect significant growth from the same period in 2024. The strength of our consistent operational execution, including constructive regulatory outcomes, customer load growth and our continuing commitment to cost discipline drive our success. Alongside our other initiatives, regulatory outcomes are key to our progress. And in the third quarter, we implemented constructive, approved settlements of both our Oregon and Idaho general rate cases. We expect to file our next Washington general rate case in the first quarter of 2026. In Washington, we were required to file multiyear rate plans of at least 2 and up to 4 years.

While many of the details of the case are still in development, we are evaluating whether we file a 2-year, 3-year or 4-year rate plan. With good regulatory alignment, we are confident that a longer rate plan can be beneficial for us and our customers. The law also provides us with the ability to file a new plan during a 3- or a 4-year rate plan, if necessary. We continually invest in our utility infrastructure to support customer growth and maintain our systems so that we can safely and reliably serve our customers. Capital expenditures at Avista Utilities were $363 million in the first 3 quarters of 2025. We expect capital expenditures of $525 million in 2025. From 2025 through 2030, we expect capital expenditures of $3.7 billion, resulting in an annual growth rate of 6%. In addition to this base capital, our current estimate of the potential capital opportunity for both our RFP and the addition of a potential large load customer is up to $500 million from 2026 through 2029.

If these opportunities materialize, we expect the potential capital to be weighted approximately 75-25 between a potential new large load customer and self-build opportunities. We also expect that this potential investment would be spread somewhat evenly throughout the 4-year period. These estimates do not include any incremental capital requirements that could result from incremental transmission projects like regional grid expansion. In July, we issued $120 million of long-term debt and we do not expect further debt issuances this year. We expect to issue up to $80 million of common stock in 2025. That includes $45 million, which was issued during the first 3 quarters of the year. In 2026, we expect to issue approximately $120 million of long-term debt and up to $80 million of common stock.

We are confirming our consolidated earnings guidance with a range of $2.52 to $2.72 per diluted share for 2025. As a result of the $0.16 of losses associated with our investment portfolio year-to-date, we expect to be at the low end of the consolidated range. We expect Avista Utilities to contribute toward the upper end of the range of $2.43 to $2.61 per diluted share. Our guidance for Avista Utilities includes an expected negative impact from the energy recovery mechanism of $0.14 in the 90% customer, 10% company sharing band. We have incurred $0.12 under the ERM year-to-date. Due to the staggered timing of rate cases throughout our multiple jurisdictions, going forward, our expected return on equity at Avista Utilities is 8.8%. AEL&P continues to perform well, and we expect it to contribute $0.09 to $0.11 per diluted share. Over the long term, we expect that our earnings will grow 4% to 6% from the midpoint of our 2025 guidance. I'd like to finish by saying that at Avista, we have positive momentum, our core business is performing per our expectations, and we have much to be optimistic about as we look to execute upon our business plans. Now we'll be happy to take your questions.

[Operator Instructions] Our first question comes from the line of Shar Pourreza with Wells Fargo.

It's actually Alex on for Shar. So just on the $80 million equity needs you have out there for '26, you have a lot of incremental CapEx opportunities you've highlighted. So I just want to get a sense on additional funding sources. Would you look at other avenues? And maybe what about a divestiture of your other business to fund the growth at the utility? Is that something you'd consider?

Yes. Thanks for the question, Alex. Yes, we're indicating that an expectation of up to $80 million for 2026 as we mentioned. And if we are fortunate enough to have additional spending opportunity or capital investment opportunity for the RFP, large customer or both, then that might change the equity needs, but not significantly so. And I would continue to expect that we would use our periodic offering program as the vehicle. It's not a significant enough increase in equity needs that we would need to do something more dramatic by making a sale of some business or something like that.

Okay. Got it. And just sort of just the messaging just around looks like the rate base outlook from 5% to 6%, you're now expecting that 6% at the utility. Can you just remind us if that includes the incremental CapEx opportunities you've highlighted or would that push you past that 6%? And can you just walk us through what that means to your 4% to 6% earnings range over the long term?

As we continue to have opportunity to add to our capital plan and if it comes in the form of the items we highlighted and/or additional transmission, that would help take us towards the top end of our growth range that we stated at 4% to 6%. I don't believe it would take us above that, but let's see what happens with large loads. And there's -- as Heather indicated, there's a lot of great conversation going on with potential developers.

[Operator Instructions] Our next question comes from the line of Julian Dumoulin-Smith with Jefferies.

It's Brian Russo on for Julian. Just on the upcoming Washington MYRP filing. You mentioned that you're evaluating the 2- or 3- or 4-year plan. Just curious, how do you manage around external risks of inflation and interest rates and even power costs while under more than the 2-year plan that you're currently in. Would you need to seek ERM modifications to kind of insulate yourself from power costs?

Well, there's a few aspects here that I want to get into with you, Brian. First, after a 2-year period. So let's say, hypothetically speaking, that we file a 4-year. And we move our way through the first couple of years or even just the first year, and we find that we're off track either because of inflation or we've had additional investment opportunities that aren't reflected in the case. Then we have the opportunity to refile, so that case then becomes a 2-year and you, in essence, start over. So we've got a wonderful set of optionality to move forward if we need to by, in essence, cutting that case back from 3 or 4 years to a 2-year case.

In addition, as we think about how we would proceed, and again, these pieces are all coming together. So it's all preliminary. We would expect to have power supply resets in each subsequent year, at least that would be our objective as we go into the case. So when you ask about the ERM, that's how we would address that. Now I'll just proactively answer a question about the ERM. We have talked about how the outcome from the last case wasn't quite what we had hoped it would be in Washington. And we've gone through that workshop process that we felt we were obligated to do. We had great conversations with the parties that involve -- get involved in these workshops. And our approach going into this next case is to likely not try to modify the ERM itself. And that's because of the order that we heard from or in our last case in the commission, the words that they used and Puget is still out working on a proceeding that comes well I think, towards the middle of next year, we'll have a better idea of whether or not Puget had success modifying their ERM-like mechanism.

So we're going to set the ERM aside for now, and then we're going to look to see if Puget has success and if they do, then we'll try to move forward with something similar. And what we're going to focus on is resetting power supply cost at a more appropriate level. And we think we have a path to setting power supply at that more appropriate level. And if we're able to do that, then the impact of the ERM is somewhat muted.

Okay. Great. I think are we still assuming a power cost drag in 2026 per your most recent disclosures?

Yes. We're -- I think our disclosures have covered that pretty well. I'll reinforce that without a change to the ERM and given how power supply was set in the last case that we would expect a drag from the ERM. Now hopefully, because of weather and other factors, it won't be as severe as it is in 2025. but it's too soon to be able to predict that.

Okay. Great. And just can you remind us again on the other businesses, how the mark-to-market works. I think there's a quarter lag, right? So this September quarter actually reflected June mark-to-market values. So it's possible, hypothetically, in your year-end update that could capture September clean -- mark-to-market clean energy investment values, which arguably were well off their lows following the old BBB and executive order, et cetera.

Yes, you're following it pretty well, Brian. And yes, there is a quarter lag for some of our investments, a fairly significant amount of the investments. And so this quarter reflects second quarter for those investments, and we'll see how it turns out for the rest of the year. We're, as we've mentioned before, not able to call the bottom, but we're encouraged that we saw the impacts in the first half of the year. And then this quarter, it flattened out to some extent. And the dust seems to be settling around some of the clean energy narrative that had been out there. So we're optimistic. But again, it's hard for us to be able to call whether or not that will completely turn around by the time we are talking to you next quarter.

Okay. Great. And then just lastly, on the increment -- potential incremental CapEx. How should we think about kind of the mix of debt and equity financing? Is it 50-50 or something different than that?

Well, our base capital plan that we've described and the amount of debt versus equity for base capital for this year and as now we're describing for next year is $120 million debt, $80 million equity and then if we have incremental spending opportunities after that, there's, of course, a lot of complexities that we would have to work our way through. But generally speaking, I'd expect incremental capital to be in roughly 50-50.

I'm showing no further questions at this time. I would now like to turn it back to Stacey Walters for closing remarks.

Thank you all for joining us today and for your interest in Avista. Have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.