IDACORP, Inc. Aktie

[Audio gap] Mike Kennedy, Scott Madison, Karen Miller, Susan Morris and Dr. Mark Peters. All of our directors and nominees with the exception of myself qualify as independent directors. All of the current directors have been nominated for reelection at today's annual meeting, and we have one new nominee as candidate for our Board, Sharon Miller. Sharon recently retired as President North America of Lamb Weston. She brings a wealth of global business sales, customer operations and supply chain insights to our Board, along with strong ties to Idaho Power service area. Information on each director and nominee can be found in the proxy statement for this annual meeting.

Before I move on, I'd also like to recognize our officer team. Their leadership and service make us the successful organization we are today. Their impressive and varied biographies are on the IDACORP website. We have an outstanding leadership team that is excited about our business and committed to serving our customers, employees and you, our owners.

For today's meeting, we'll start with the formal business, and then Brian Buckham and I will provide additional comments about our company. We'll end with a Q&A session. And of course, our management team welcomes questions from our owners outside of this meeting as well. Today's presentation contains forward-looking statements that relate to future events or expectations. I'd like to remind everyone that the company's future results could differ from those discussed at this meeting. Factors that could cause future results to differ materially can be found in our filings with the Securities and Exchange Commission, including our 10-K and 10-Q reports. I encourage you to review those documents, other documents we file with the SEC and our press releases for material information about our company.

It is now my pleasure to officially call the 2026 Annual Meeting of IDACORP shareowners to order. The annual meeting is being held to address three items: To elect 10 directors for a 1-year term, to address an advisory resolution to approve executive compensation, and to ratify the appointment of Deloitte & Touche as our independent registered public accounting firm for 2026.

IDACORP has approximately 139,000 shareowners located throughout the United States and internationally. The results of shareowner voting for the annual meeting are typically determined by the return of proxies from shareowners who are not present, and we have those results today.

Before moving on, there are a few administrative matters that need to be addressed. First, a majority of the shareowners voting power outstanding is represented at this meeting by proxy. Consequently, we have a quorum. Second, in accordance with the IDACORP bylaws, no matters other than those stated in the proxy statement or that have been properly raised by a shareowner in advance can be considered at this meeting. Finally, if you have not already voted your shares, you may do so now by following the voting instructions provided in the virtual meeting e-mail sent to you this morning.

The first item of formal business is the election of directors. 10 director nominees are up for election at this meeting. All 10 have been nominated for 1-year terms to expire at the 2027 Annual Meeting. The second order of business is the advisory resolution to approve executive compensation commonly referred to as the say-on-pay vote. The third order of business is to ratify the appointment of Deloitte & Touche as IDACORP's independent registered public accounting firm for 2026. The company's Board of Directors has unanimously recommended a vote for each of these proposals.

The IDACORP proxy holders have voted all shares represented by proxy as submitted on all three matters. Based on the proxies, the preliminary results of voting indicate that each of the 10 director nominees named in the proxy statement has been elected for a 1-year term, and all proposals have passed. At this time, the voting has now closed.

This concludes all items scheduled for action at this annual meeting. The business portion of the meeting is now adjourned.

As we move to the informal portion of the meeting, I'd like to start by thanking our employees for the great work they did during an especially busy and exciting year for IDACORP and Idaho Power. Their dedicated service continues to drive strong results for our customers and our owners. During 2025, our company produced its 18th consecutive year of earnings per share growth, sold a record amount of energy to customers, broke ground on the Boardman to Hemingway Transmission Project and achieved the best reliability scores in Idaho Power's history. I'm so impressed with the incredible work our team is doing to help build a secure energy future for our company and our customers.

Customer growth remains strong for Idaho Power. Our customer base grew by 2.3% in 2025. We now serve more than 660,000 customers and a population of more than 1.4 million. The growth across our region is robust, and it's happening across most customer classes, spurred by extensive residential, commercial and industrial construction. We expect this growth to remain strong as our local economy continues to outperform national trends.

Notable large customer projects are making significant progress. Micron's new semiconductor facility is advancing towards completion, and we're also working through the details of Micron's second fabrication facility announced last year. Meta's Data Center has reached the testing and commissioning stage. We're starting to see loads and revenues increase from these projects, which will continue throughout this year.

Idaho Power brought several additional industrial projects online in 2025, including the new Tractor Supply distribution warehouse and a major expansion of Chobani in yogurt production facility. We continue to see steady interest from many of our core industries of food processing, manufacturing, distribution and warehousing as well as inquiries from other energy-intensive customers looking to operate within our service area. We work closely with prospective customers to set realistic time lines to meet their energy needs while ensuring they are not shifting costs to other customers. As we serve one of the fastest-growing areas in the nation, we're doing it thoughtfully to ensure that growth pays for growth.

As we work to meet growing energy needs, affordability remains a top priority. We work hard to keep our costs down and provide exceptional value for our customers, and our rates remain 20% to 30% lower than the national average. Our rates are also increasing at a slower pace than many other utilities, 23% over the past decade compared to 41% nationally. Our price history also compares favorably to the consumer price index, which has gone up 36% over the same period.

The benefits of our low-cost system and hydro generation, in particular, helped with our affordability focus. We also work with our regulators to help keep rates low. Our 2025 general rate case in Idaho reached a constructive outcome via a settlement. The new rates are helping us to recover costs to support our operations, and based on current projections, we are not planning to file a general rate case in 2026. We are full speed ahead on the major transmission projects we are building to serve our customers. After breaking ground on B2H last year, 260 towers have been completed, representing about 20% of the towers for the project.

In addition, we have completed nearly half the access roads and structure pads for the project. We expect B2H to be in service by late 2027, and we're excited to add this important transmission resource to our system. Permitting is nearly complete on the SWIP-North transmission project, and we expect construction on that line to begin this year. We anticipate SWIP-North will be done as early as 2028. We're also working with PacifiCorp on the Gateway West Transmission project. We anticipate a critical section of that line between our Hemingway and midpoint substations will come online as early as 2028.

Permitting transmission lines takes a lot of time and effort, and I want to recognize the great work that teams across our company have done to move these projects forward. We continue to add generation and storage resources that will help us maintain excellent reliability as demand grows. In 2025, the 200-megawatt Pleasant Valley Solar project came online as part of our Clean Energy Your Way program, and we added 230 megawatts of battery storage to Idaho Power's resource portfolio. We are adding another 250 megawatts of batteries and 125 megawatts of solar this year. Both of those projects are nearly complete.

Idaho Power has announced plans to construct 167 megawatts of natural gas fuel generating capacity next to the existing Bennett Mountain Power Plant, which is slated to be online in 2028. We're proud this company-owned project was the most cost-effective resource in the RFP. We're also working hard to solve the generation needs in 2029 and 2030, and we're working to procure additional resources to solve those deficits.

We filed CPCN for two additional natural gas plants. We plan to bring the 222-megawatt South Hills project online in 2029 and the 430-megawatt Paragon Project is slated for operation in 2030. Both units of the Valmy plant have been converted from coal to natural gas and are ready for our summer peak this year. This February, Idaho Power entered into an agreement with the Oregon Trail Electric Cooperative for the sale of our distribution system with some transmission assets in Oregon. If the transaction is approved, we would have no regulated retail operations in Oregon, so we provide power to OTEC for some time under a power purchase agreement.

Base purchase price is $154 million, and the deal is subject to approval from state and federal regulators. Oregon represents a small portion of our service area, projected to be less than 3% of total sales by 2030. We're confident OTEC will provide a strong local focus and dedicated service for Eastern Oregon, while Idaho Power concentrates on supporting our rapidly growing Idaho community. While Idaho Power would no longer directly serve the Oregon customers, we would retain ownership of our Oregon generation facilities and most of our Oregon transmission, including B2H. We're working closely with OTEC to prepare for a smooth transition.

I will now turn the time over to Brian for a financial update.

Hi, thanks, Lisa. We spent a lot of time talking about the financial side of the company on our recent earnings call. So I'll be brief in my comments today on that. I'll start by pointing out that we had another strong year in 2025. We achieved the unprecedented 18th consecutive year of earnings growth that Lisa mentioned earlier. The customer growth, constructive regulatory outcomes and our Idaho earnings support mechanism have all helped the company continue this impressive trend, all while maintaining affordability for our customers. We just spoke about what we're doing on the operational side to address growth and the continued reliability of our system.

On the financial side, we're working in parallel, executing our plan to finance and earn our return on the investments that we're making. On the fourth quarter earnings call, we noted that we're forecasting spending around $1.4 billion per year on average over the next 5 years and a total 5-year CapEx plan of $7 billion. As was the case last year, we're again doubling our average annual spend compared to the past 5 years. In fact, our 2026 to 2030 forecast is a 26% increase in CapEx compared to our prior 2025 to 2029 forecast of CapEx. And I note that there's still potential upside to the forecast. It depends on the outcome of our latest RFP and potential resource needs from prospective incremental industrial projects.

Financing and building, the needed infrastructure is just one element of our execution. We also have to convert it to rate base to keep the utility financially healthy and to provide returns to the debt and equity holders that are funding our growth. Coming out of our most recent Idaho case, our rate base at the end of 2025 was about $5.3 billion. And a similar story to last year, we estimate rate base more than doubling over the next 5 years, increasing to around $11 billion by the end of 2030.

That will require us to be thoughtful about frequent regulatory actions and also balancing the financial needs of the company and customer affordability. As we look ahead to funding our growth, we have a strong balance sheet, and we intend to keep it that way through this growth cycle with an average 50-50 debt equity capital ratio target as of now. The external financing, we noted on our fourth quarter call, we estimate we need for 2026 to 2030. Just for the capital that we have in the plan as of right now is about $2 billion in equity, about $2.9 billion in debt today at that ratio.

We already executed or settled on forward sale agreements on around plus $750 million of that equity need as of the end of the first quarter. So we're well on our way to executing on the plan. I want to reiterate something else Lisa mentioned, as we progress through the growth cycle, we're remaining focused on maintaining affordability for our customers.

Our approach to contracting with new large industrial projects is focused on protecting the existing customers and our shareholders from potential negative financial impact as well as being transparent and responsive to the new customers. Customer growth in the denominator of our regulatory equation helped to absorb what might otherwise be larger rate increases for our existing customers. And we're fortunate that the Idaho regulatory process has a growth-pays-for-growth methodology. This year and more so next year, we anticipate some notable industrial revenue growth, and that's a large part of why we're not planning to file a rate case this year.

It demonstrates that the growth-pays-for-growth construct in Idaho works. As we've noted in the past, when we continue to believe IDACORP is among the leading earnings growth and earnings quality profiles in the industry. We have a demonstrated CapEx needs for our growing customer base. We have a path to affordable conversion to rate base and earnings. Our commitment is that we'll keep focusing on solid execution.

I'll close with a quick note on our dividend, which increased 2.3% last year, that was our 14th consecutive year with dividend increase with cumulative growth of 193% during that span. We're proud our company has paid a dividend every quarter since 1944.

And with that, I'll turn the presentation back over to Lisa.

Thank you, Brian. As we conclude, I want to reiterate my thanks to our outstanding employees and leadership team. These are exciting, challenging times in the energy industry and thankfully, this is where we thrive. IDACORP and Idaho Power are committed to balancing safe, reliable energy with affordable prices as we grow. Our employees are dedicated to our core values with safety first, integrity always and respect for all as we work to support the communities we serve, the environment we share and the places we call home. Their hard work and innovation -- innovative problem solving continues to drive strong results for our company, our customers and our owners.

Thank you for your continued trust in IDACORP as an investment, and thank you for joining us for this annual meeting.

With that, we're ready to begin the question-and-answer session. You should see a QA icon near the bottom of the webcast screen. You can click that and submit a question, and we'll take as many questions as time permits on a first come basis.

So we'll start with a question about really the growth-pays-for-growth methodology, just given the increase of all these big data centers and big loads, what is that doing to rates for customers?

And again, in Idaho, we actually are very careful. We've talked about that in our comments. We want to make sure that there isn't the cost shift and our regulator requires us to conduct a no-harm analysis when we submit the energy services agreements for approval. So as Brian mentioned, that is showing that it works. And that the costs are being appropriately directed to who's causing the cost. And so we're -- we feel really good about that.

Another question -- there's a couple of questions sort of asking about what's going on in the Middle East, and how is that affecting our business and our plans?

And certainly, in general, inflation and some of the supply chain constraints have impacted us over the past few years, not just the Iran conflict. So we've been sharing that in our quarterly calls and update. It is worth noting, though, that we have a very large fleet of vehicles because we drive 10 million miles a year. But certainly, we're seeing the increased cost in O&M there, just from the increased gas prices as an example.

Another couple of questions are really asking about our portfolio, our generation portfolio, our clean energy goal and just sort of how we're navigating through this large load -- large growth cycle?

So it is true that we set a goal for -- to be 100% clean into 2045, but it's a goal, and it's an aspirational goal. And we have said all along that we would really need technology to produce resources that we could afford that are commercially available and at competitive prices to reach that goal. And again, we set that goal prior to this growth cycle. We still -- our primary business goal is our obligation to serve. So we have to serve this load, and we have to do it in a way that is safe, reliable and affordable, and clean, if we can manage the first three first. It has to be in that order. So we are working through all of that. And as we work through our IRP, that is where we look at the portfolio, and we produce the least cost least risk portfolio, and that is what binds our decision making.

And right now, gas is about the only thing that you can build in the time frames we need that have the operating characteristics that -- to serve this load reliably. So it isn't -- we continue through the IRP process to model a 100% clean portfolio. The world has changed a lot. And so we are still navigating through it. And we will continue to still look at it, and we're hopeful that things like SMRs or hydrogen or some other fuel cells, something will show up that would be able to -- we could add to our portfolio so that we can continue to serve in a safe, reliable, affordable way. So it isn't that we're backtracking. It's just simply that we're moving forward and adapting to the world we live in. So -- and we will continue to do so.

So I think that pretty much closes out the questions that that are -- we've seen so far. So I think with that, I will say thank you again for attending the annual meeting and for your questions, and we appreciate your investment in IDACORP, and we look forward to connecting again at future annual meetings. And hope you have a great day. Thank you.

All right. Thank you, everyone.

Good afternoon, everyone, and welcome to IDACORP's First Quarter 2026 Earnings Call. Today's call is being recorded and our webcast is live. A replay will be available later today for the next 12 months on IDACORP's website. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides will reference during today's call are available on IDACORP's website. As noted on Slide 2, our discussion today includes forward-looking statements, including things with earnings guidance, spending forecast, financing plans, regulatory plans and actions and estimates and assumptions that reflect our current views on what the future holds. These are all subject to risks and uncertainties. Those risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements. .

We've included our cautionary note on forward-looking statements and various risk factors in more detail for you to review in our filings with the Securities and Exchange Commission. As shown on Slide 3, also presenting today, we have Lisa Grow, President and CEO; Brian Buckham, EVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager. Slide 4 for a summary of our first quarter financial results. IDACORP's diluted earnings per share were $1.21 compared with $1.10 last year. Our key operating metrics and guidance are unchanged, except for our hydro power generation forecast as we reduced the top end of the range.

We're reaffirming our full year 2026 IDACORP's earnings guidance estimate in the range of $6.25 to $6.45 diluted earnings per share, which includes our expectation that Idaho Power will use less than $30 million of additional tax credit amortization to support earnings. These estimates assume historically normal weather conditions and normal power supply expenses for the rest of the year. Now I'll turn the call over to Lisa.

Thank you, Amy, and thank you all for joining us today. I'll start my remarks with a look at our continued growth on Slide 5. We've seen an overall customer increase of 2.3% since last year's first quarter. with growth across all customer segments, including 2.4% for residential. From a load perspective, Industrial Energy sales grew by 5.7% over the same period. After years of thoughtful planning and execution, we're starting to see the ramp-up in loads and revenues from some of our large industrial customers, and that ramp will accelerate during the year. Two of our industrial customers, Micron and Meta are examples of that. As you can see in our latest photos on Slide 6, construction of Micron's first fabrication facility continues to progress. And Micron has started ground preparation for the second fab.

Meta's data center has reached the testing and commissioning stage. We've worked tirelessly to be ready to serve their needs as they ramp up operations. In addition to these large industrial projects, we continue to see significant interest from core industries of food processing, manufacturing, distribution and warehousing as well as inquiries from other large customers in other industries looking to operate in our service area. As we serve one of the fastest-growing areas in the nation with what we view as a leading rate base growth, we're doing it thoughtfully, so that growth pays for growth to help protect our existing customers from cost shifting.

As you can see on Slide 7, our approach to contracting with new large industrial projects is focused on protecting both existing customers and shareholders from potential negative financial impact as well as being transparent and responsive to the new customers. We provide clarity in how we will serve the new load, including time lines, rates and other terms. We've used take-or-pay provisions, certain upfront payments, credit and security requirements, termination or exit payments, customized pricing terms and other contractual features in some cases. Like everything we do, we take a thoughtful approach to our customer pipeline.

Turning to Slide 8. We remain focused on affordability. We work hard to keep our costs down and provide exceptional value to our customers, and our rates remain 20% to 30% lower than the national average. Our rates have increased at a much slower pace than national averages, increasing by 23% over the past decade compared to 41% nationally. This increase also compares favorably to the Consumer Price Index, which increased 36% over the same period. The benefits of our low-cost system and hydro in particular, help with our affordability focus. Our regulatory model in Idaho, a growth pace for growth system also helps us retain that affordability, and it has been working.

Legislation was passed in Idaho this year that effectively codified the way we currently develop large load contracts with 1 change. It established a deadline of 9 months for the PUC's contract approval process, which had previously been more open ended. As we discussed on our last call, Idaho Power is not planning to file a general rate case on June 1. And at this point, we're unlikely to file one at all this year. While we're seeing higher depreciation and interest expense associated with growth in our infrastructure build-out as well as wildfire mitigation costs, we expect that revenues from new large load contracts will help offset those additional costs. We also continued to benefit from careful and thoughtful spending.

As we move towards summer and moving to Slide 9, I'm happy to report that the Idaho Commission approved our 2026 wildfire mitigation plan earlier this month. As a reminder, the commission-approved plan establishes the standard of care in Idaho under the Wildfire Standard of Care Act beginning this year.

Moving to Slide 10. Idaho Power continues full speed ahead on major infrastructure projects, including 3 major transmission lines that will add critical flexibility and reliability to our system. Work is progressing quickly on our B2H transmission project, which we expect to be in service in late 2027. Nearly half of the access roads and structure pads have been completed, along with 200 structures, about 15% of the total structures to the project. On the Swift North transmission project, we received our CPCN from the Idaho Commission. Several project authorizations remain in progress, including final construction authorization from BLM. The construction contractor plans to break ground this June in Nevada and the September in Idaho, and we expect to port to be complete as early as 2028. We're also continuing to work with PacifiCorp on the Gateway West transmission project, and we recently filed a joint request for a CPCN with the Idaho Commission.

We anticipate a critical section of that line between our Hemingway and midpoint substations will come online as early as 2028. If all continues to go as planned, customers will be served by 3 new large transmission lines on our system by 2028, bringing with them the benefits of access to diverse markets and transmission wheeling revenues.

Turning to Slide 11. I have some updates on the new gas plants we discussed last quarter. We've received a CPCN from the Idaho Commission for the company-owned 167-megawatt plant that will be -- natural gas plant that will be next to the -- to our existing Bennett Mountain power plant. We've also secured an EPC contractor as we continue to work toward an in-service date of summer 2028. Since our last call, we've also filed 4 CPCNs in Idaho for 2 additional natural gas plants. As a reminder, both were included in the CapEx forecast update we shared at year-end. We plan to bring the 222-megawatt South Hills project online in 2029 and the 430-megawatt Paragon project in 2030. These natural gas projects will provide firm dispatchable resources we need to meet growing customer demand, and we view these projects as affordable low-risk solutions to our near-term capacity deficit. We also have 250 megawatts of new company-owned battery storage that will come online this quarter, and we'll be adding 125 megawatts of third-party owned solar generation to our system later this year.

We remain on track to complete the conversion of Valmy Unit 2 from coal to natural gas before the summer peak this year. These resources support our efforts to add capacity, flexibility and affordable energy to help serve our customers. As you can see, we're continuing a major expansion cycle and Idaho Power is an exciting place to be.

Turning to Slide 12. Idaho Power recently received approval of the 2032 RFP from the Idaho Commission. The RFP is aimed at solving a projected capacity deficit of at least 200 megawatts. Idaho's new procurement rules will allow us to complete a timely and competitive resource evaluation, and we'll have additional details about potential resources and projects to meet these energy needs on future calls. I'll close my remarks by following up on last quarter's announcement regarding the sale of our Oregon service area. The transaction continues to progress ahead, and we plan to make filings in the next couple of months with the Oregon and Idaho commissions and FERC for the approval of the sale. And with that, I will turn the time over to Brian.

Thanks, Lisa. A lot going on operationally, which is exciting for us. On the financial results side, I wanted to summarize the company's strong start to the year by highlighting that we saw strong results even with unusually mild weather and several expected headwinds. Our expected headwinds were higher share dilution, higher depreciation and interest expense and lower accelerated amortization of ADITCs. The use of fewer ADITCs is technically a headwind when you're comparing Q1 of this year to Q1 of last year. Admittedly, that might be counterintuitive. So I'll talk more about that as I go through the reconciliation, which is next on Slide 13.

IDACORP's first quarter net income increased over $8 million compared to last year. higher retail revenues from the January rate increase and from customer growth combined for a $23 million benefit. Usage on a per customer basis decreased operating income by $10.7 million, the results of particularly mild weather that reduced residential and commercial usage. Keying off something that Lisa noted though, industrial use per customer increased notably in part from a new large industrial customer that ramped up its usage during the quarter. As part of our last general rate case, we updated the FCA mechanism. Now it's for both the rates and the usage per customer base. Combining those updates with lower usage per customer in the residential and small commercial classes from the mild first quarter, we saw increased FDA revenues of over $19 million compared to the first quarter of 2025.

As expected, O&M expenses were higher in the first quarter. The primary drivers were higher welter mitigation program expenses and amortization of previously deferred costs associated with the Jim Bridger plant. A large portion of those items we recover in customer rates, so they're reflected in revenues. In total, O&M expenses were up $13.1 million compared to the first quarter of 2025, but again, with offsetting revenues for much of it. Depreciation and amortization expense increased around $6 million for the quarter, and that was expected from our ongoing infrastructure investment. Other changes in operating revenues and expenses increased operating income by a net $13.6 million, that resulted from lower net power supply costs, a decrease in property taxes due to legislative changes in Idaho last year that became effective this year and updates to the PCA mechanism based from last year's rate case that were not unlike the changes to the FCA basis.

Nonoperating expense increased about $4 million, which was mostly higher interest expense, interest expense recorded on the new finance lease, which is our battery tolling agreement also contributed to the increase. Partially offsetting those items was increased AFUDC from a higher construction work in progress balance, which we still expect will be sustained for some time. Idaho Power amortized $6.3 million of additional tax credits under the Idaho earnings support mechanism in the first quarter. That was $13 million less than what we reported in the first quarter of 2025. So last year's Q1 benefited from additional ADITC usage much more than this year's Q1.

As I alluded to you, that's actually good news from a financial strength and performance perspective for this year. It means we expect to use or need less support from the ADITC mechanism this year to reach the floor level of year-end return on equity in Idaho. And that's despite what we predict to be a considerably higher year-end book equity balance. I tend to look at that as 1 helpful barometer of operating performance.

Our next slide, Slide 14, reiterates what we discussed about CapEx on the fourth quarter call. I'll just note that the forecast doesn't include any resources that could result from the 2032 RFP and/or does it include some of the projects that often till the last 2 years of that plan as we move ahead. So there could be some upside to what's shown on the graph.

Moving to Slide 15. I want to point out that we've made a small update to this slide since our last call. You can still see that net cash flow from operations is funding over half of our CapEx needs in the 2026 to 2030 window and hopefully more than that. Either way, we'll still need our growth capital, which we've estimated at around $2 billion in equity and $2.9 billion in debt to stay near our target 50-50 capital ratio. What we've updated it in the equity section under FSAs and equity to be issued in the first quarter this year, we executed on $165 million of forward sales through our ATM program. And we settled nearly $52 million from prior forward sales through the ATM program. So around $2 billion of equity shown as needed on the slide. When you combine the ATM program with our follow-on from last year, we've now settled or executed forward on over $750 million of the need, which we've broken out separately on the chart.

That gets us the equity we need into 2027 and leaves the remaining amount that we think is within relatively conservative ATM issuance ranges. We have a $300 million ATM that we put in place a couple of years ago, and we've not used that one in full. So we're planning to establish a new ATM program in the near term. Not surprisingly, any additional CapEx needed to serve loads would require some level of financing. If that were the case, that funding would likely be more heavily weighted at the back end of the 5-year forecast, where operating cash flow should also be higher to offset financing needs in part.

I threw a lot of numbers and detail pretty quickly there. And on Slide 16, you can see the forward sales agreements that we have available and the forwards that we've settled to date. It offers a little better, easier picture of where we stand on equity and financing generally. With that, I'm going to wrap it up there. I'm going to hand it over to coach, John Wonderlich.

Thanks, Brian. Turning to Slide 17, you can see our 2026 full year earnings guidance and key operating metrics, not much change from the fourth quarter call. This guidance assumes normal weather for the remainder of 2026 and normal power supply expenses. We expect IDACORP's diluted earnings per share this year to be in the range of $6.25 to $6.45. We still expect that Idaho Power will use less than $30 million of additional investment tax credit amortization in 2026, so less than the $40 million we amortized in 2025. We continue to expect full year O&M expense to be in the range of $525 million to $535 million. We still anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026.

As the 5-year forecast showed, we continue to expect higher CapEx numbers as we continue to focus on safe and reliable service and to respond to strong growth in our service area. Finally, given our current forecast of hydropower operating conditions, we expect hydropower generation to be within the range of 5.5 million to 7.0 million megawatt hours for the year. So we trimmed the top end of our guidance. Water storage in our system is near or above average across the Snake River Basin. However, low overall snowpack conditions will result in lower water supplies from spring snow melt. Record wet April conditions with more than 3x the average precipitation for the Boise area has helped to increase spring season stream flows and hydropower production but will not completely offset the lack of winter snow head. With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question comes from the line of David Arcaro from Morgan Stanley.

Well, thanks for the comments on the timing of the rate case. I was just wondering, what are you, I guess, currently thinking or what should be the maybe base case expectation. Could it potentially be next June, June 2027 in terms of when a full rate case might be possible? Or how are you characterizing that?

I think that has been sort of our traditional cadence, but we'll keep doing the math and figuring out when the right timing of the next general rate case would be just depending on how this year shapes up and what we see coming for the next year.

Yes, David, a couple of factors we're looking at just following on Lisa's comments. One is the conversion of equipped plant in service becoming eligible for rate base treatment, some of the timing of that dictates when we do rate cases. And then the other aspect is largely revenues, timing of those coming in and the magnitude of those revenues, those can both dictate timing of rate cases.

Yes. Got it. That makes sense. And then I was wondering if you could comment on what you're seeing in terms of new customer, new large load inbounds, the pace of demand in that pipeline? And also just when could you deliver new power, when could you handle new large loads coming into the system at this point?

Well, it continues to amaze me how strong the pipeline is. There is just an incredible amount of interest in our service area, again, from many different industries. Certainly, there are some data centers included in that. And I will have Adam give some more color on it. But I would say for what we have ahead of us right now between now and, say, 2028, we're probably at what are just maximum capacity to actually get work done. But if there was someone that was going to come on with modest ramps, perhaps it could go a little bit towards the end of that time period. But we're seeing a pipeline that goes well into the 2030s now. And so we're really excited about sort of the sustainability of this growth as we look to the future. But Adam?

Yes, David, I don't have a ton to add. In addition to the data centers, we're seeing a fair amount of movement in the dairy area biodigesters, base manufacturing, warehousing. So it's pretty diverse in that regard. In terms of keeping up, we feel good about where we're at. We've been able to reserve turbines where needed. Obviously, we have these RFPs that are going out the door to make sure we'll continue to meet at moving forward. So as of right now, we feel good we're staying ahead of it. Obviously, we've got to get our transmission lines built and in place too. Those are all on track. So we feel good about the transmission side, too. So far, so good, but it's a constant effort, and we're continuing to focus on it really every day. .

Your next question comes from the line of Shar Pourreza from Wells Fargo.

It's actually Whitney Mutalemwa on for Shar. So obviously, as we're thinking about freight case cadence, we're also thinking about the credit outlook. So time back, Moody's downgraded holdco to BAA3 as well as Idaho Power -- so it cited heavier CapEx cycle on just weaker near-term credit metrics, but it also acknowledge supportive offsets like additional parent equity or more frequent general rate cases. So from your perspective, is the focus now on simply rebuilding the metrics within the new ratings category? Or do you still see a path over time to improve it credit positioning as recovery cadence catches up with spend?

Yes. Whitney, thanks for the question. This is Brian. So in terms of where the credit metrics stand right now, we don't issue debt at the holding company level. I mean we do all of those debt transactions at the OpCo level. And so the move to Idaho Power or BAA2, part of the rationale for that was just when you look at sector credit metrics at the Moody's level, a lot of the Baa1 ratings, which is where Idaho Power was at before, have somewhat of a CFO preworking capital to debt of around 18% on average, maybe even slightly higher in some instances. -- ours, as we've talked about in the past, while we met our prior threshold of 13%, both 2024 and 2025.

Going forward, we aren't looking to have a credit metric of 18%, at least not for this year and not for next year at Moody's at the OpCo level. And so Moody's report had some of the details on that. But just from my perspective, if there was a lot of peer benchmarking that went into that decision. So perhaps the downgrade isn't a surprise in that regard, but that negative watch covered out there for quite a while. The new part of the upside of that is stable ratings, right? And a new downgrade threshold at 12% for Moody's. We've received a lot of questions in the past on the negative outlook, but some pause remarks on the new stable outlook.

So the IDACORP side, you mentioned BAA3, that's part of Moody's notching policy. And as I mentioned, we have a higher CFO preworking capital to debt at IDACORP and no holding company debt. So that really is just the Moody's policy on notching. We've talked before about the need or desire to keep our balance sheet strong at 50-50 and a simple and straightforward balance sheet. Still very focused on that. To your point, that does require some equity issuances that we've signaled for quite some time and actually executed on those equity needs over time. So maintaining that balance sheet structure for us does require the equity. It keeps us closer to the thresholds for S&P and our prior threshold for Moody on that 13%, 14%, 15% zone for a while, but expecting to naturally grow off of that with large load revenues and rate cases over time.

So we don't have an intent to immediately equitize the 18%, for example. We'll continue to blend debt and equity. We did a debt offering earlier this year. we'll have some equity that we'll do later in the year pull down from forward to help blend that in. And so our financing strategy does take into account those credit metrics, but balance sheet strength is the most important thing for us as we look to continue our financing.

Great. And just as many follow-up. Obviously, this is also in the remarks, but how are you moving towards just -- how are you thinking about the current CapEx cycle? What is more frequent rate relief practically mean from here? Are you moving towards a regular cadence that we can underwrite? Or is there still more opportunistic based on capital timing and obviously, the regulatory conditions?

Yes. We just take a very pragmatic view of sort of where we are in our spend, and where revenues come in. And to the extent those aren't matching up, especially during this growth cycle, we will go in for rate relief. But like this year, where we're able to stay out given that those revenues are starting to come in, we will use that as the sort of cadence, I guess. Anything that you would add, Brian?

I think that's right, Lisa. One of the things I mentioned from an earlier question is this idea of looking at the conversion rate of QIP to plant in service and there's the financial impact that, that actually has if you don't do rate cases around that. So some of them will be just weighing the impact of that conversion to reg and taking that into regulators versus filing rate cases. when you've got large load revenues coming in. So the larger revenues to really cover a lot of what would otherwise be rate cases. So I can't say at this point that we'd file every year. I think the word you used was opportunistic. When we need to go in, that's when we'll go in. That's how I'd look at it.

Just customer affordability, right? I mean that's important to us, and we can maintain that through these large load revenues long-lived assets and other features of the company with a growth pace for growth mentality that really do bring about an affordability aspect. We will look each year at what our rate app would be. We don't want to go in and make really large rate requests, and it's this growth pace for growth mentality. And really the way we operate our business from an O&M and affordability perspective that help us stay out and use those revenues instead of rate cases in some years.

Your next question comes from the line of Chris Ellinghaus from Seibert Williams.

So Brian, I thought you were going to get into this, I don't remember what you said in your comments, but I kind of thought you were going to talk about this. But can you just talk about how you foresee ITC recognition through the years? Do you have some visibility there?

Yes. For ITCs, we're actually a cash taxpayer, and so we have a tax credit appetite on our returns each year federal income taxes. So we're actually monetizing those ITCs every year. That appetite continues. I will say there's some diminishing availability of ITCs in the future when you look at some of the legislation that's out there now. We're getting it from our batteries, for example, now, and that will go on to our tax returns. So over the long term, I think things could change. We've also looked at PTCs as another avenue for us as well to look at. Right now, I think one of the important features of the ITCs that we generated that they do go into the mechanism. So we could have a fairly sizable balance of ITCs that are available for what I'll call ADITCs for use in the mechanism going forward. But no planned external monetization through sale of the tax credits, it would be recording them on our tax returns.

Okay. So directly. So in the guidance, you talk about normal weather, but just looking at sort of the traditional now a forecast that you guys usually show, it's going to be far from normal. So can you give us any sense of what you're seeing particularly irrigation as usual, but it's supposed to be super hot with pretty well below normal precipitation. So what have you seen so far in the spring what's the soil condition look like? And sort of what are your thoughts about what the summer will look like?

Well, it's a great question, Chris. And certainly, those of us that enjoy winter sports were really bumped out about not having much snow in Hills. But we did have some good storage, and we did catch up a little bit with the rain that we had in this last month. but still is a little bit short of what we would normally see. And certainly, we like it to be stored up in the mountains of snow and come over -- come down on a slower pace. But all that being said, irrigators are -- have been trying to figure out what's their strategy, just given some of the commodity prices, and so that may have some impact. But I think overall, with hot and dry conditions, our folks on the ground are thinking it could be actually closer to normal than some of that might indicate. And I know that Adam has some additional color for that as well.

Yes, Chris, we've been debating this issue with the folks on ground because and it's interesting to see their take. What we've been looking at is that low water years have not correlated to less sales because there's just so many other factors involved and this summer, I think you mentioned some of the factors. The factors pushing towards more sales are projected warmer weather. You mentioned NOA. Lisa mentioned our reservoirs were actually at average. So that's a good sign. And the other thing that's interesting is when surface water users do get cut off a little bit. They tend to use ground pumps to make some of that up when water is scarce.

So those things would all push towards more sales. On the other side, obviously, with low water, you can have the risk of curtailments, which could happen. We've had that in the past. But as we debated these things and went back and forth to look at what we thought irrigation sales were going to look like in the future, we can get to kind of this net-net normal position that Lisa mentioned in that is really from the folks that are on the ground talking to farmers trying to get a feel for what the year is going to look like.

If I could paraphrase, you're suggesting that you're expecting sort of normal water resources, but the demand could be high.

It does feel like the demand if the weather turns out like it's predicted, like you mentioned, could be higher in terms of the need for energy pumps, the water side to be a little bit low. But again, we see no correlation in the past between low water and low sales. In fact, a lot of times, we've had a low water years that have had higher sales because the temperatures have been higher. So there's just puts and takes as we look at both sides of it. .

Right. Did you get any sort of feedback about the impact that the Iran situation is having on your agricultural customers?

We did not get feedback on that. We got a little feedback as Lisa mentioned, on the commodity side, some of the pricing for potatoes and beats are a little bit lower than I think our farmers would like. And so there are some cases when they plan to maybe slightly less of those products, which could impact water use. But at the end of the day, [indiscernible] touched on the Iran issue directly. .

Okay. And I guess, lastly, you touched on the strength of the pipeline. Can we assume that your Q is basically unchanged from what you talked about on the fourth quarter?

Chris, I think we've even had a few more inquiries since the fourth quarter. I think it seems like it's never ending, honestly. And certainly, a few new ones come into the queue. A few others might drop out. But I would say, overall, it's up.

I think that's right, Chris. And just a quick reminder, we've been hanging at that 8.3% IRP growth for a while now. I think we're going to update that as part of the next IRP in Q4. So I think when you see that update, there should be some upside in that.

Yes. And it's important to just remember that we don't put any load -- prospective load into that number until we have either a sizable financial commitment or a signed contract or something that feels a lot more than tire kickers. So while the pipeline and the 8.3% aren't exactly correlated, there's some lag in between.

Sure. It just kind of helps that when you quoted that 4,000-megawatt queue, it just sort of kind of put things into perspective. So I'm just kind of curious if that number had made any kind of advance or decline.

Chris, just quickly, the problem on those issues, talking about the large loads is so many of them are confidential, we just can't -- we can't come out with them until they go public. And so a lot of times, we're in a holding pattern for them. .

Next question comes from the line of Michael Lonegan from Barclays.

Just wondering if there's any update you can provide on Micron Fab 2, when you expect an ESA to be signed and when we today expected to be implemented into your capital plan?

This is Adam. So the ESA has been signed, still being reviewed by the commission. We expect to hear from the commission.

This is Fab 2 .

This is on Fab 2. Yes, we're still negotiating tab to ESA. What I can say about Micron is there is an absolute ton of work that's going on, on site. It's really amazing to see what a $50 billion project looks like as you walk around. Brian, Lisa and I were able to do that long ago. But in terms of their -- in service, they anticipate initial waiver output for their first fab around mid-2027. And on the second fab, they are already moving forward with the ground preparation for Fab 2. And of course, we have revenues potentially coming in the door mid this year related to Fab 1. So on the ESA side, we're still working with Micron on that. Hard to say exactly the timing of that, but we'll let you know when it becomes more public.

And then you highlighted the capital plan is conservative. You touched upon the 2032 RFP as being incremental. Just anything you could say about your targeted ownership on the investment opportunity set there?

I mean we always want to go in with some company-owned assets or projects and we do. And historically, we've won about 50% of those and so we have -- certainly, we have a desire to own as many of the resources as we can, and we do so in a competitive way.

And maybe I'll just add, we are -- this is Adam. We do have several projects that we'll put into the 2032 bids. So we'll compete like we do each year.

Yes, Michael, if I can add to that, I think you referenced the CapEx impacts as well. And so the CapEx forecast that we have in the slides that we're showing right now doesn't have any resources for the 2032 RFP. We don't assume any sort of win rate for purposes of our CapEx. We put it in there when we know it's going to happen. There is some amount of CapEx in the graph that will help serve a portion of Micron's second fab, but only what we expect would be in the very earliest year or years of operation. That's our large transmission projects will help with that. Some of our generation. We need more resources for Fab 2 and like Adam said, the amount of CapEx actually depends on the ESAs we signed and how we serve our load growth rate, which we're working on right now.

Again, the IRP gets filed in June '27, but we'll lock down some form of growth rate, low growth rate more fourth quarter this year so that we can do our modeling off of that. If you want to serve the load several years from now, you have to start the process now, which means spending some amount in the near term for things like Truven reservations and early payments and a higher amount things get fabricated and delivered and the project gets constructed. So you could start to see some of those payments show up in the current 5-year window, maybe weighted more towards 2029 and 2030. -- in the very near term. But that's how we look at the CapEx upside on that graph.

Great. And then lastly for me, you executed on the ATM program this year. You talked about a new ATM program, you have some forward settling later this year. For the balance of your equity financing plan, I just wondering if you could talk about the profile of issuances, broadly speaking, should we expect it to profile with CapEx and also incremental capital, should we still anticipate that to be financed with your 50-50 structure?

So the answer to the second question is yes. For any incremental amounts that are in the plan, you should plan on 50-50 right? For the stuff that's already in the plan, I think we've quoted more like a 30-70 split, but anything incremental above that to maintain our balance sheet structure, assume 50-50. The nature of the issuances -- I mean, one of the things we've talked about in the past is it's probably not linear. And part of that is because you've got large customer revenues coming in more operating cash flow in the latter years of the window.

So maybe a little bit more front-end loaded. I think the best way we've been able to tell people is to model it somewhat like the CapEx profile is right now and then if there's incremental upside to the CapEx in the plan, build a little more in, in that window. But definitely not linear, and we can look at it from the perspective of if we were to have ATM issuances with forward on it. the financing plan for equity based on the amount you saw on the slide is something that's within a reasonable ATM issuance on balance. I think I mentioned in my more prepared remarks earlier. And with those forwards, we have the ability to shape the equity a little easier to match the timing of payment.

Your next question comes from the line of Julian Dumoulin-Smith from Jefferies.

It's Brian Russo on for Julian.

We never know which really going to answer. So nice for Brian. .

Likewise. And just -- it's nice to see ground prep beginning at the micron at to. I'm just wondering what are the next milestones that could trigger an ESA -- or is it just the parameters of the contract that you're negotiating? And then secondly, what load is upside that would be incremental to the prior IRPs, 8.3% that would be reflected in this updated IRP. And will Micron fab to also be included in that load forecast.

Brian, this is Adam. So Fab 2 is not in the 8.3%. We do anticipate that it will be an upcoming Q4 load forecast. In terms of timing, I shared kind of where they're at. Anything beyond that is not public. I think they publicly said that, again, they anticipate initial waiver output for the first fab in mid-2027. Beyond that, we just -- we can't get into the details of they'll hit different targets or not. So to do that, we can attract what they've said publicly and that's what they've said publicly.

Okay. And then I apologize if I missed this earlier, but could you remind us of what has changed in the RFP bidding process that might give you guys a slight advantage possibly on the win rate?

This is Adam again. I don't know that I would say to advantage as much as it's faster than it was under the Oregon rules. One of the things we're running into, and I think you know this, Brian, is that turbine procurement, you have to do well in advance of what we used to do because of supply chain constraints and the time line related to the regulatory process, the review was just a lot longer than what we needed to get these projects in place. The other thing that's out there is we don't submit a benchmark bid anymore. We just compete equally with all other independent power producers out there. So that would set up the advantage as much as it's just putting us in an equal playing field and that the playing field we were not in several years ago.

Lisa mentioned we've been kind of at a 50% hit rate -- so we're continuing to try to do that. And hopefully, this new process will make it go faster. And then, of course, not having a benchmark data allows us to compete line with everyone else.

Your next question comes from the line of Anthony Crowdell from Mizuho.

I appreciate the update on the beet crop. Just I have 1 quick follow-up. Slide 12, you talk about the 2032 RFP update. The 200 megawatts of capacity you're talking there, is that associated with any particular committed customer or committed load?

This is Adam. So 1 thing we mentioned there, you'll note it has at least 200 megawatts. We view that as a little bit of a minimum. This 200 megawatts is perfect capacity and it's tied to the 8.3% IRP growth rate that we've been talking about. Again, we're going to update that figure in the future. The way it works in the RFP side is we'll get a variety of different projects. We'll be able to review those projects that are on the short list. And then depending on our need at that time, we'll be able to pull the trigger on as many projects as we to meet the load forecast at that time.

Again, Idaho Power will bid several projects in the 2032 IRP. And then on the CapEx side, Brian, maybe worth mentioning, I guess, what's included in the CapEx in the 2032 resource play.

Yes, thank .I'll just reiterate. We don't actually have anything in there at all from the 2032 RFP. It's a common question. that we don't actually have any assumed win rate. [indiscernible] will compete on equal footing in the RFP and what shows up from that the company-owned would be additive to the CapEx. .

[Operator Instructions] There are no further questions. That concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

All right. Thank you. Thanks, everyone, for joining us today and for your continued interest in IDACORP, and I hope you all have a great evening. Thanks. .

That concludes today's meeting. You may now disconnect.

Welcome to IDACORP's Fourth Quarter and Year-End 2025 Earnings Call. Today's call is being recorded, and our website is live. A replay will be available later today and for the next 12 months on the IDACORP website. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance and Compliance and Risk.

Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we'll reference during today's call are available on IDACORP's website. As noted on Slide 2, our discussion today includes forward-looking statements, including earnings guidance, spending forecast, financing plans, regulatory plans and actions and estimates and assumptions that reflect our current views on what the future holds, all of which are subject to risks and uncertainties.

These risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements. We've included our cautionary note on forward-looking statements and various risk factors in more detail for your review in our filings with the Securities and Exchange Commission.

As shown on Slide 3, also presenting today, we have Lisa Grow, President and CEO; Brian Buckham, EVP, CFO and Treasurer; and John Wunderlich, Investor Relations Manager.

Slide 4 shows a summary of our full year financial results. IDACORP's diluted earnings per share were $5.90 compared with $5.50 last year. This made 2025 our 18th consecutive year of EPS growth, as noted on Slide 5. We ended up $0.15 per share above the midpoint of our original EPS guidance for 2025. These results include additional tax credit amortization of about $40 million for 2025 compared to almost $30 million of additional tax credit amortization in 2024.

Today, we initiated our full year 2026 IDACORP earnings guidance estimate in the range of $6.25 to $6.45 diluted earnings per share which includes our expectation that Idaho Power will use less than $30 million of additional tax credit amortization to the core earnings. These estimates assume historically normal weather conditions throughout the year and normal power supply expenses.

Now I'll turn the call over to Lisa.

Thank you, Amy, and thanks to everyone for joining us today. As we look back on 2025, it was a particularly busy and exciting year for IDACORP. Our employees continue to shine achieving strong results for our customers and owners. Our company produced its 18th year of consecutive earnings per share growth, as Amy mentioned. We sold a record amount of energy to our retail customers, broke ground on the B2H transmission project and recorded among the best reliability scores in company history.

And we did it all while staying true to our core value to Safety first, integrity always and respect for all. We also settled our general rate case proceeding in Idaho with a constructive outcome for our company and our customers. I want to again thank -- extend my thanks to our outstanding employees for their hard work and commitment to helping us build a secure energy future that powers our customers' lives and businesses.

As you can see on Slide 6, growth remains robust across Idaho Power service area, outperforming national trends and highlighting our region's economic vitality. In 2025, our customer base grew 2.3%, including 2.5% for residential customers, bringing the number of metered customers we serve to more than 660,000. This growth is happening across most customer classes with extensive residential, commercial and industrial construction continuing throughout our service area.

In 2025, Micron's new semiconductor facility continued to advance towards completion. The size is impressive, as you can see on Slide 7. Meta also made significant progress on construction of its data center, which you can see on Slide 8, and that project began taking power last year.

Additionally, Idaho Power helped bring several other major industrial projects online, including a tractor supply distribution warehouse and a major expansion of Chobani yogurt production factory or facility. Along with steady interest from our core industries of food processing, manufacturing, distribution and warehousing, we're also seeing increased inquiries from other energy-intensive customers looking to operate within our service area. We work closely with prospective large customers to set realistic and thoughtful time lines to meet their energy needs while ensuring they are not imposing costs on our other customers.

The solution to serving load growth from new large customers in our mind has several important elements. We first have to comply with the [ laws of physics ] in delivering power. It has to be at a price the customer will pay. We need to procure reliable resources and have them available on the time line we agree to with the customer. It has to be appropriately derisked operationally and on the credit side through special contracts with the customer and it cannot be subsidized by other customers.

As far as we've been able to find, we're serving the fastest load growth rate in the nation, and we're doing it with a thoughtful and measured approach to ensure there are benefits to our company and its owner at the same time, mitigate what might otherwise be a risk of cost shifting to our other customers were it not for our growth pace for growth regulatory model in Idaho.

Notably, last year, Micron announced it would build a second semiconductor facility in Boise. The load and CapEx projections we're providing today don't yet include this expansion, but we're working through the details with Micron. As we've noted previously and continues to be our practice, Idaho Power's public growth projections only include projects that have signed contracts or large financial commitments for customer-funded infrastructure.

With this approach, our growth forecast for large load customers is based only on committed projects. We also have a significant pipeline that includes a diverse mix of prospective large load customers and that pipeline exceeds our current 4,000 megawatt peak load. But we don't have -- if we don't include any of them in our load projections as speculation and hope are not how we like to forecast.

Turning to Slides 9 and 10. Affordability continues to be one of Idaho Power's key focus areas. We work hard to keep our costs down and provide exceptional value for our customers, and our rates have increased at a much slower pace than national averages. We believe that even after implementing our 2025 Idaho General Rate base outcome, our prices remain well below the national average. We're proud of our low rates and despite considerable infrastructure investment and expansion of our customer base, we expect rates to remain in check with our regulatory methodology in Idaho.

Case in point for affordability based on current projections, we're not planning to buy general rate case in Idaho on June 1 of this year. While we anticipate higher depreciation and interest expense associated with growth and infrastructure build-out as well as wildfire mitigation costs, we expect revenues from new large load contracts will help offset those additional costs. And we continue to benefit from our culture of careful and thoughtful spending. We'll watch revenues and cash flow during the year as part of our continuing assessment of the need and timing of a rate case.

As seen on Slide 7 -- or Slide 11, we continue to be full speed ahead on our major infrastructure projects. Work is progressing quickly on our B2H project with 80 towers already completed and many more under construction. We expect B2H to be in service by late 2027. Permitting is nearly complete on the SWIP-North transmission project, and we expect construction to begin this year as well.

We anticipate the project will be completed as early as 2028. We also continue to work with PacifiCorp on the Gateway West transmission project. We anticipate a critical section of the line between our Hemingway and Midpoint substations will come online as early as 2028. With those expectations, we have several new large transmission projects added to our system in '27 and '28. Transmission takes a great deal of time to permit, so we're glad we got started early.

Moving to resource planning. We recently received acknowledgment of our 2025 IRP from our Idaho and Oregon Commission.

Turning to Slide 12. Idaho Power is adding generation and storage resources that will help us maintain excellent reliability as demand growth. In 2025, the 200-megawatt Pleasant Valley Solar project came online as part of our Clean Energy Your Way program, and we added 230 megawatts of battery storage to the resource portfolio. Additional projects are underway to help us continue meeting growing customer demand, including 250 megawatts of batteries and 125 megawatts of solar, which are both set to be in service later this spring.

Idaho Power has announced plans to construct 167 megawatts of natural gas fuel generating capacity next to the existing Bennett Mountain power plant in 2028. We're proud that this company-owned project was the most cost-effective resource in the RFP. As we've mentioned on prior calls, we're working hard to solve the generation needs in '29 and '30, which is a deficit of around 200 megawatts of incremental firm capacity needed each year. We expect to procure additional resources to solve for those deficits.

The additional gas plant near Bennett Mountain as well as other resources we expect to construct are included in our CapEx forecast that Brian will discuss. We filed a request for a CPCN for the capacity addition next to the Bennett Mountain plant, and we plan to file a request for CPCNs for other new resources in the relative near term. You'll see those requests on the Idaho Commission website when we file those.

In other news on generation resources, in 2025, Unit one of the Valmy coal-fired power plant was converted to natural gas. And we also burned the last of our coal at our other Valmy unit, which is currently being converted to natural gas. We expect that conversion to be completed this summer. I'll end by discussing this morning's announcement regarding our Oregon service area. We've entered into a definitive asset purchase agreement with the Organ Trail Electric Cooperative for the sale of our distribution system and some transmission assets in Oregon.

After the transaction, we have no regulated retail operations in Oregon, so we provide power to OTECH for some period of time under a power purchase agreement. The base purchase price for the transaction is $154 million, which is subject to various adjustments. Completion of the transaction is subject to a number of conditions, including approval by the Idaho and Oregon Public Utility Commission and from FERC. Oregon represents a small portion of our overall service area, projected to be less than 3% of our total sales by 2030.

We're confident [ OTECH ] will provide a strong local focus and dedicated service for Eastern Oregon, while Idaho Power concentrates on supporting rapidly growing Idaho communities. If the sale is approved, Idaho Power's 20,000 customers in Oregon will transfer to [ OTECH ] service. While Idaho Power would no longer directly serve Oregon electric customers, it would retain ownership of its Oregon generation facilities and a large majority of its Oregon transmission assets, including B2H, which will help serve Oregon residents and businesses. We're working closely with [indiscernible] to prepare for a smooth transition and make the appropriate regulatory filings to support the sale. It's too early to determine, but we expect regulatory approval could take 10 months or longer.

And with that, we'll turn the time over to Brian.

Thanks, Lisa. I'm going to start on Slide 13, which has our usual reconciliation of year-end results. just running through the table, IDACORP's net income increased over $34 million compared to 2024 and higher operating income at Idaho Power from the January rate increase and from customer growth combined for a roughly $75 million benefit. Usage on a per customer base has decreased operating income by $6.5 million and that was because temperatures were milder in 2025 versus the prior year, though both years did have above average cooling 3 days.

O&M was another offset, albeit smaller than we originally anticipated. Total other O&M expenses increased less than $10 million, mostly from increased labor-related costs. We ended up at the low end of our O&M guidance range for the year. So good outcome there. Depreciation and amortization expense increased nearly $28 million for the year, which was expected with the increase in system investments we've made and the assets have gone into service. In the second quarter last year, a new leased battery storage facility began operations and that modestly increased expense due to amortization of our [ related right to use ] assets. So something new on our financial statements for last year.

Other changes in operating revenues and expenses decreased operating income by a net $3.8 million, and this was because of the year-over-year impact of the conclusion of property tax litigation in 2024, that resulted in refunds that year. Also the timing of recording and adjusting regulatory accruals and deferrals positively impacted 2024 results. But those items didn't recur at that level last year. Those items were partially offset by a recovery of costs of the new battery finance lease through the power cost adjustment mechanism.

The expense for the new battery financing lease had interest expense and amortization, but they're offset in the power cost adjustment mechanism, so ultimately, it's a near 0 impact to operating income. The decrease in power supply expenses that weren't deferred also provided a benefit when compared to 2024. Nonoperating expense increased by about $23 million. That was mainly driven by an increase in interest expense because our long-term debt balance has increased. Interest on the new finance lease also contributed to the increase.

So as I noted before, this is offset in the power cost adjustment mechanism. Partially offsetting those items was increased [indiscernible] from higher construction work in progress balance, which we predict will be sustained for the next several years. Idaho Power amortized $40.3 million of additional tax credits under the Idaho mechanism to reach the 9.12% floor level of Idaho return on year-end equity. That was only an increase of $10.5 million compared to the prior year.

And also related to taxes, the $20.4 million relative decrease in income tax expense, excluding the additional ADITC amortization was primarily driven by income tax return adjustments for state taxes and then standard plant-related flow-through items. That's it for the recon table.

And moving to Slide 14, we've updated our 5-year CapEx forecast as promised. You can see that it increased considerably. We're currently forecasting spending $1.4 billion per year on average over the 2026 to 2030 forecast period. With a total 5-year CapEx amount of around $7 billion, that's a doubling of our average annual actual spend of around $700 million for the past 5 years and near our current market cap. And to give you some perspective on our update, our 2026 to 2030 forecast is a 26% increase in CapEx compared to the 2025 to 2029 forecasted CapEx that we shared at this time last year.

If you look at the CapEx graph, the bars are shaped a lot like they were at this time last year, but the difference is in the scale on the left side of the chart, it's much different in terms of magnitude. And as usual, the last 2 years and the chart probably have some upside that might materialize as we refine our plans and projects for that later time span.

Some of that upside to our forecast results from the fact it doesn't yet include the resources that are needed to serve Micron's second fab or some of the other expected load growth. Amidst all of this investment, I think, it's important that we reiterate the importance of affordability for all of our customers. We're fortunate that our regulatory processes and rules ensure that the new large load customers [indiscernible] they have fair share of system costs and aren't subsidized by existing customers.

As we look at the possibility of not filing rate cases this year and also the estimated potential magnitude of cases in the future, with the future where affordability remains achievable, notwithstanding the significant magnitude of our investments. We also need to keep the utility financially healthy, meaning we need to convert our capital investments into rate base and provide returns to our debt and equity holders funding our growth.

On Slide 15, we rolled forward our rate base forecast for the 2026 to 2030 period. Our total system rate base coming out of our 2025 Idaho General Rate Case was $5.3 billion, it was $4.6 billion coming out of the 2024 Idaho Limited scope rate case, so a big upward reset for our base year. We forecast that by 2030 rate base could reach over $11 billion, which is more than double our 2025 rate base. That's an incredible amount of growth in rate base.

Case in point, we project it to be a 16.7% rate base growth CAGR for the 5-year period from 2026 to 2030. Last time this year, our forecasted rate base CAGR was 16.1% for 2025 to 2029. And today's higher CAGR even after rolling forward to the considerably higher base year that I mentioned. If you look at the cash flow statement, you'll see additions to PP&E in 2025 were nearly $1.2 billion and on the balance sheet is over $1.7 billion. And I think that illustrates how busy we've been over the past few years as a company.

And amidst this increasingly long growth cycle, it's obviously important that IDACORP and Idaho Power keep their balance sheet strong. As part of that, we continue to target an average [ 50 ] debt equity capital ratio and a simple balance sheet. We don't have any holding company debt or any particularly sizable maturities coming up and our capital structure has just medium-term notes and common stock in it right now. And I'd say there is great elegance in that simplicity.

Moving to Slide 16. You can see the net cash flow from operations is funding over half of our CapEx needs in the 2026 to 2030 window. We still need [ growth ] capital, which we estimated at $2 billion in equity and $2.9 billion in debt as they add our target 50-50 capital ratio. But we need to dig a little deeper on that. We've already executed on over $600 million of equity through forward sales agreements that will settle in 2026, which leaves a lesser net amount of $1.4 billion of net equity sales to occur through 2030. That equates to our future capital markets transactions being comprised of about 2/3 debt, 1/3 equity, and it's an average less than $300 million of equity per year for the full 5-year forecast period if you exclude equity already sold on forward, which is within a reasonable ATM issuance range for us, and that gives us a lot of optionality on how we raise our equity growth capital.

Cash flows from operations are expected to increase as we move through the forecast window, particularly with large load revenues coming in with greater volumes over time. And it's important to note that any additional CapEx needed to serve additional load would require additional financing. If that were the case, additional funding would likely be more heavily weighted to the back end of our forecast.

Lisa already mentioned the execution of a definitive agreement to sell Idaho Power's Oregon distribution assets. I'll just add that from a financing perspective, we'd look to offset some of the equity -- I talked about with the net after-tax proceeds of the transaction. That transaction would give us business simplification as Lisa noted, but also another source of capital to fund our rapid growth related investment in Idaho. In the financing table, we haven't applied any proceeds from the prospective sale.

We estimate the onetime gain from the asset sale would be immaterial, and that's not the thesis for it. We expect the asset sales to be only slightly accretive earnings accretive in the year it closes, but also provide an ongoing benefit to EPS from lower dilution.

On Slide 17. Cash flows from operations eclipsed $600 million for the first time in company history. Customer growth, the benefits of the general rate case outcomes and moderate power supply costs, all helped to achieve that milestone. The strong cash flows also help moderate our financing needs and leaves IDACORP with strong cash position as of today.

What I'll end with today is to reiterate something I noted at this time last year because it still rings true. Over the forecast window we talked about today, we expect to see what we believe to be among the leading actual earnings growth and earnings quality profiles in the industry. I think it's important to note that when you do your analysis, our expectations are on a GAAP basis and basing off a long stream of 18 years of consecutive GAAP earnings growth. So we based on our growth expectations off of a very strong year with no non-GAAP exclusions or exceptions, again, elegance in simplicity.

We're mindful of those providing the debt and equity capital for our growth and recognize the importance of generating returns for them. We're focused on the things that matter to them. Strong risk mitigated execution and already in process infrastructure build-out, sustained affordability for customers, actual rate base growth from permitted and in-flight projects, real near-term earnings accretion, customer revenue diversity and long-term durability of our earnings growth and returns.

That's the paradigm we've been working under and what I know you've all come to expect from us. And with that, I'll turn it over to John.

Thanks, Brian. This marks my 1-year anniversary of conference calls in my IR role. So Brian asked me to give a new fun fact about myself. Last year, I noted that I was an assistant coach for a third-grade basketball team, and I'm happy to let you know that I was promoted from the role of assistant to the head coach to a full assistant coach this year. And I moved up the ladder to fourth grade basketball.

Turning to Slide 18. You can see our 2026 full year earnings guidance and key operating metrics. This guidance assumes normal weather throughout 2026 and normal power supply expenses. We expect IDACORP's diluted earnings per share this year to be in the range of $6.25 to $6.45. The midpoint of this range reflects an [ 8% ] EPS growth rate over 2025 actual results, premised on what we would consider a conservative set of assumptions.

We expect that Idaho Power will use less than $30 million of additional investment tax credit amortization in 2026, so less than the amount in 2025. We expect full year O&M expense to be in the range of $525 million to $535 million. And I'd like to provide some context on that range. The largest driver of the increase over the prior year is wildfire mitigation costs, which are offset by revenues from the general rate case.

So it's not apples-to-apples comparison between 2025 actuals and the 2026 estimate. As we continue to expand our system to accommodate growth, we do expect to also see higher O&M expense. We also continue to experience inflationary pressure on labor and professional services, but our culture of spending wisely to help ensure affordability for our customers is very much intact. We continue to focus on keeping costs as low as possible while keeping the system safe and reliable.

We anticipate spending between $1.3 billion and $1.5 billion on CapEx in 2026. As the 5-year forecast showed, we continue to expect higher CapEx numbers as we respond to strong growth in our service area. Finally, given our current forecast of hydropower operating conditions, we expect hydropower generation to be within the range of 5.5 million to 7.5 million megawatt hours for the year.

With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question comes from the line of David Arcaro of Morgan Stanley.

I was wondering if you could give an update on maybe your customer load pipeline. What are the latest discussions you're having in terms of either expansions of current large load customers and how is the pipeline shaping up for new companies coming into your service territory?

Well, I'll get it started. We certainly -- it just continues to -- we get a lot of inquiries, a lot of folks that are very interested some big than others and really from across many industries. So it isn't focused on on just one. I'll let Adam give a little more color. And it's true, too, that we have NDAs. So there's some things that we can't talk about.

Yes, I feel like a little bit about broken record. This is Adam, saying the same thing, the inquiries continue to be strong. It's kind of [indiscernible] amount of inquiries, everything from data centers to manufacturing. For example, we have a data center that's looking at a service territory that the conditional use permit called Diodes, it's the gemstone Technology Park. We have Idaho National Lab that's growing. [indiscernible] that is a mine up north that's looking at starting operations there, too. So it's pretty robust. Again, a lot of them are under confidentiality. So I can't get into the details but feel like the growth is strong.

And David, just one thing I'll add is the last time you've seen a formal load growth update from us was associated with the 2025 IRP. So that was from quite some time ago. We do plan to update that. The load growth at some point during the year, usually towards the end. But there's a lot of customers that we've talked about that just aren't in that 8.3% load growth update or load growth number that we have out there as of right now. You should [indiscernible] later this year.

And maybe I'll add that, of those customers, a lot of them aren't just inquiries. They're actually doing construction study, generation studies. We have energy service agreements that we're looking at for a fair amount of megawatts. So when we talk about inquiries, goes beyond just people kind of touching and feeling and actually going to the next stage of looking at what it looks like to come to our service territory.

Got it. I appreciate that color. That's helpful. I wanted to also just ask about on the equity needs side of things with the refresh here. Maybe there are a couple of moving pieces, but I was wondering if you could just give a sense for what the rule of thumb would be, Brian, maybe just on -- for incremental CapEx, how do you think about the funding split in terms of external equity from where we stand now, given your latest operating cash flow kind of outlook here? And maybe in the context there, I was curious, any repairs tax impact from the guidance there.

Yes, David, sure. On the repair stack side, the assumptions that we use in our forecast tend to stay relatively stable. It does adjust from time to time each year, but not a major update in our repair tax deduction. On the equity needs side, any incremental CapEx that we add to the forecast is probably financed 50-50 debt equity, at least beyond what we have now and the update that we provided this morning.

What I will say, though, is in a lot of instances, these large load customers come with large load cash flows, and that can certainly impact ultimately what our need is. And if you look at the equity number that we put in our estimate right now, it does have some conservative assumptions about what cash flow will look like. If you look at the incremental increase in cash flow in the bar chart for our financing waterfall February of last year versus February of this year, you can really see -- you can see some movement there.

And that's to fund the significant incremental amount of CapEx that we have in the forecast. So some of the adjustments that you see in that waterfall is a result of what cash is on the balance sheet and where forward drawdowns were on our equity programs at any given time. So that gives you a little bit of a skewed view of not apples-to-apples comparison year-over-year on equity needs. So the number does move around, certainly with cash flows.

It could be impacted like I noted by the sale of the Oregon service territory. So there's a lot that can move the equity number. I'd say it's pretty conservative at this point. And so even the 50-50 debt equity split could be somewhat of a conservative approach on how we would look at our equity needs over time.

Your next question comes from the line of Michael Lanigan of Barclays.

So obviously, you mentioned your current capital plan does not include Micron Fab 2. Would you be able to help us understand the size of that investment opportunity in the latter part of your plan?

We're just working with Micron to determine that. So we don't have anything to share in terms of size today. So more to come as we work our way through that.

Yes, Michael, this is Adam. They haven't given publicly a load ramp. The size of their first fab is public, but they haven't come out with the second fab yet. So when we are able to share that, we will.

Okay. Great. And then secondly for me, obviously, a sizable CapEx increase with today's update, modest increase in equity content needs. You're on track for significant cash flow generation increases, like you said, with the large customer ramp-up. Just wondering where did you end 2025 on FFO to debt? And where do you anticipate being over the course of your plan? And do you think there's an opportunity for Moody's to take your rating off negative watch?

Yes, Michael, thank you for the question. I think the answer to that is yes. I think there is an opportunity for that. So we do have a pretty substantial capital investment. And so we are maintaining a very strong simple balance sheet, as I mentioned, of 50-50. And I think that's been a good factor from a rating agency perspective. .

We have, at the end of 2025, I'd say on Moody's, I think we were at about 14.3% at Idaho Power. And on S&P, we were just barely sub-14%, if I remember correctly, on FFO to debt. Our threshold at Moody's is 13% and at S&P at 14%. So as of right now, we're somewhat navigating that floor level. We expect to come out of that with large load revenues, as you mentioned, in the cash flow to support it. But again, we're maintaining a really strong balance sheet. The outcomes of our rate cases helped the rate case that we did in 2025 had a result that will help credit metrics in 2026.

So I could see us being at or near those levels again in 2026 before we make a gradual move up off of those numbers. But again, we usually do better than what our internal forecast suggests. And so I think Moody's and S&P both understand that. And we'll be meeting with them in March actually to have a conversation about where things are headed.

So we don't have, as I mentioned, holding company debt. That helps. We don't have anything on our balance sheet that all fall in exotic for lack of a better term. And we don't have any upcoming maturities through 2030 other than $116 million [indiscernible] control revenue bond this year to refinance. So from a balance sheet perspective, we're sitting very strong. I think the rating agencies will recognize that.

Your next question comes from the line of Shar Purreza of Wells Fargo.

This is Whitney Makalima on for Shar. And any congratulations to John on the promo to...

So you probably have precedent for large load arrangements, including a certain tariff that's tied to, I think, it's tariff schedule 33 tied to a special contract. Do you expect to move towards a standardized large load tariff rather than negotiating special contracts case by case? And if so, what would drive that decision?

At this point, we don't have plans for that. Each customer really comes with their own unique needs. And so we really try to make sure that we understand them and meet them -- so they really are tariffs at one, if you will, that are very catered to the customer.

Okay. So nothing in the near term.

That's correct. Yes, nothing in the near term from our perspective.

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

You mentioned the downward sloping CapEx in the outer years, and you take a conservative approach to what you include, what could be upside there? Is there anything left on the '28 and '29 RFPs that would be additive? Or is this another RFP that would be needed for the post 2030 time frame?

Yes, Brian, this is Adam. Yes, we are looking at an RFP in the post 2031, '32 time frame. As you know, we had 1 for 2028. We had one for 2029. The 2029 and later RFP really only provided on natural gas project. That was the project that [indiscernible] you've heard us speak about that's getting built right now. We're actually moving that project into 2028. And so as we look at 2029 and 2030, we're going to have to evaluate some options to increase power production there. And we hope to give you an update on that here relatively soon. And I think Lisa mentioned it [indiscernible] in her opening comments that we do have some options there, and they will go public here in the near future. .

Right. Is one of those options brownfield development, I think it's a [indiscernible].

Yes, absolutely. We have an energy site there. And just as a quick reminder, too, we don't have any generation resources for Micron Fab 2, Fab 2, is not in the load resource balance, nor is diode, so you would see additional CapEx there as long as well as additional generation resources to meet that growth. .

Okay. Great. And then the less than 30 million ADITC usage in '20 notable, as you mentioned earlier, would that be like the inflection or with the likely stay out this year of filing a rate case, how should we look at post 2026 support for earnings?

Well, certainly, as the large loads start to come online, we start to see those revenues help push out the need for rate cases and hopefully lower the need for the use of ADITCs. And so, so far, we're keeping on schedule, and we're optimistic. And so we -- I don't know that I would call it an inflection point necessarily, but certainly, we are starting to see some of that revenue come in.

It's Brian. What I would add is I think one way to look at this is -- let's take a look at the rate base growth slide that we talked about today on the call. And you can see that '26 and '27 has significant rate base growth. But when you look to '28, there's a very large amount of growth. So there's still the company still will earn based on rate base over time, in addition to large load customers.

We are at a point though where we have to look more globally every year as to which one is the better outcome.

Okay. And then just lastly, obviously, not surprising the assumption on the hydropower forecast. But could you just talk more or just share some thoughts on what the current hydro conditions are and drought conditions, understanding that you've got very strong mechanisms. But I'm just curious with the dynamic with irrigation sales as we move into the spring, I mean, is there a high probability of a dry and hot irrigation season?

Yes. It's really interesting. If you're a skier out west, it's been kind of a bummer of a winter, but what our hydrologists are telling us is that we actually in the -- on the east side of our system, we're actually, it's really at normal levels, and that's where we get the most generation from because it flows through all of our hydro resources. And then certainly, at lower levels, there is less no than we historically see.

But it's been actually quite wet this winter, so it didn't necessarily become snow at the lower levels, but that also helps keep those soils wet, so the runoff from the higher elevations make it to the river. So overall, we're actually pretty optimistic. I will also tell you that yesterday, it looks like Christmas here. So we're starting to see some storms. So it ain't over till it's over, again so we aren't necessarily done with the snow pack accumulation.

But of course, we live out west, so we're pretty used to having fluctuations. There are drought cycles that happen. And yes, we have mechanisms. And then we also work very carefully as we prepare for summer operations, knowing what we're -- with the conditions as we go into those operating season. Adam, I don't know what you would add.

No, I agree you covered it. I think the range reflects that. We've been much lower than that 5.5 last 5 years, I think, in 2021 and 2022, we are below that 5.5 number. So we're actually feeling somewhat optimistic that it's higher than what you would think, and that's why the range is what it is. .

Your next question comes from the line of Chris Ellinghaus of Siebert Williams Shank.

So if you're going to forgo the middle year rate case for this year, would you expect to stay on a similar midyear cadence going forward?

Well, that's sort of been our cadence historically, but we are constantly looking at our financial situation and make a determination then. So if something changed and we needed to do it sooner or later, we would do it at that time. We do have a requirement that we have to give notice when we're going to file. So you can we tell people before we do it [indiscernible]

Anything you would add, Tim?

Chris, this is Tim Tatum. The only thing I'd add is, in the past, we have filed general rate cases in the fall, targeting at June 1 effective date. So we would have the opportunity there. We look at June 1 because that coincides with our annual power cost adjustment updates and our fixed cost adjustment update. So that's another time that we could look at to file. We'll be monitoring and certainly only file if we absolutely have to, but that's a potential option as well.

Okay. The customer growth continued sort of a little more moderate in the back half of the year. Do you have any better sense today what's affecting residential growth that is it the interest rate environment or whatever you might know about?

I mean those are always the key drivers. It does seem like there's been a little bit more activity, if you will, of buying and selling. It kind of was frozen up as people were kind of stuck in their homes and interest rates, and that seems to have been relieved a little bit. I don't know if people just got used to it or needed to do something for other reasons, but I don't think it is necessarily -- I mean, we still have good growth.

And so whether it's it sort of ebbs and flows with the seasons or what drives it. We don't necessarily know. But overall, we still think it's pretty strong, and there's lots of subdivisions that are getting flatted and getting ready to be built, if not already under construction. So some really massive subdivisions sort of to the east and to the west. So we're excited about that. And certainly, with some of these big employers like Micron, they're going to need places for their employees to live. So that's really driving a lot of this growth as well.

Yes. I wanted to say, given the large new employers, is there going to be some lumpiness to what the residential customer growth looks like for the next 5 years?

It very well could. You know it's never perfectly matched. So it looks like people are gearing up to provide housing for sure.

Okay. Brian, do you have an estimate for what the weather impact was for the year?

I don't have a specific number. I can show you the way I would look at it is from a sales volume perspective, if you look at a 1.5% year-over-year sales growth on a weather-adjusted basis, it's 2.3%. So weather did certainly have its impact on the year. We had a great third quarter as a result of some of the, say, drier conditions and very hot conditions. But again, cooling degree days in both of the last 2 years were high and that impacted our sales.

If you look at, say, November, December, they were very warm months. What I would note, though, is the FTA does have some impact on the outcome of that or the impact of weather on our results. But again, no, I would say there are parts of the year that were more moderate conditions that had an impact on those sales numbers. .

Okay. Do you have an estimate for your large load growth for 2027 that mitigates the large CapEx and equity dilution and whatnot. Have you got an estimate for what 2027 looks like?

In terms of financing?

No, in terms of large load growth.

But we can tell you, Chris, that that's when a lot of that growth is going to start to ramp up when you're going to see a lot of these in-service dates for Micron and others. But I don't think we have an exact number unless you guys do.

No, we just have the 5-year CAGR out there as of now. And I think as we've mentioned, that number has been there for a while, somewhat more back-end loaded, but I would include 2027 as one of those larger ramp years

'25 or '26, '28, '29 and that is out into the 2030s actually being a pretty significant ramp years for us.

Okay. I was just checking because 2027 looks like a big year by my calculation. What -- so with acceleration in the CapEx and AFUDC and the rate case does that lead -- should that lead us to believe that 2025 was peak ADITC usage?

Not necessarily. I wouldn't assume that. There's a few different factors that influence ADITC usage. One of them is just book equity number at the end of the year as well as the calculations based on. So that's impactful. Other things can be, what's the amount of depreciation and interest expense that's unrecovered that's not offset fully by AFUDC and whether or not we file rates is another aspect of that.

So it's not linear in any given sense that ADITC usage would go down. What we're doing this year though, if you think about even into 2027, you could see something similar. It's a little too far out to know for now. But in the further out years, when you look at some of that rate base growth, we've talked about that does have to be financed with our hybrid test year, our historic test year, how you want to look at it, there is lag that sometimes has to be covered by ADITCs. And that's really why in the rate case that was important to us to have that as an element of the settlement is to smooth out some of those years where ADITC is may be a little higher.

Sure. I just don't see the big sag in the ROE that would require it to be much bigger than last year thus far. So also, you sort of reduced the dividend payout target with the dividend increase in September. Can you give us any thoughts about what do you see as a minimum that's -- can you -- do you feel like you can dip below 50%? Is there really a range that you're wanting to maintain at a minimum or a minimum growth rate have you got any insights there?

We're always looking at that, certainly, we're just trying to make sure that we're not issuing equity to pay dividends and whether it's been sort of the consensus that it's better to invest in the company and get the returns there. But I don't really know that we have -- we do have that stated range, but we sort of take it as we go through this time period and try to make recommendations to our Board that makes sense.

Your next question comes from the line of David Arcaro of Morgan Stanley.

Just 1 more that I wanted to check in with you. I was wondering just any thoughts on the prospect here for depreciation and interest expense tracker just going forward from a regulatory standpoint, whether that's something you might seek again in the future?

Well, certainly, something that we have looked at and talked about. And when we looked at our forecast for this year and sort of determine that we don't need to go in for a rate case immediately, we didn't see that we -- there was a need this year, but it's definitely something that we will keep a close eye on because as you know, with this big capital program, that those are significant impact to our financials. So we are interested in that. We'll continue the dialogue on that. It's just not something that we're working on right this minute. .

[Operator Instructions] With no further questions, that concludes the question-and-answer session for today. Ms. Grow, I will turn the conference back to you.

Thank you again to all of you for joining us today and your continued interest in IDACORP and John's basketball career. coaching career, and we hope you all have a great evening. Thank you.

This concludes today's conference call. You may now disconnect.

Welcome to IDACORP's Third Quarter 2025 Earnings Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP's website. [Operator Instructions].

I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we'll reference during today's call are available on IDACORP's website.

As noted on Slide 2, our discussion today includes forward-looking statements, including earnings guidance, spending forecast, financing plans, regulatory plans and actions and estimates and assumptions that reflect our current views on what the future holds, all of which are subject to risks and uncertainties. These risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements. We've included our cautionary note on forward-looking statements and various risk factors in more detail for your review in our filings with the Securities and Exchange Commission.

As shown on Slide 3, also presenting today, we have Lisa Grow, President and CEO; Brian Buckham, SVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager.

Slide 4 has a summary of our third quarter results. IDACORP's diluted earnings per share were $2.26 compared with $2.12 for last year's third quarter. In the third quarter of this year, Idaho Power recorded $2.5 million of additional tax credit amortization under the Idaho Regulatory Mechanism, which is the same amount Idaho Power recorded in the third quarter of last year. For the first 3 quarters of 2025, diluted earnings per share were $5.13 versus $4.82 for the first 3 quarters of 2024. Those results include additional tax credit amortization of $39 million in the first 3 quarters of 2025, compared to $22.5 million in the first 3 quarters of last year.

For our guidance, we're raising our full year IDACORP's diluted earnings per share guidance range for the second time this year. Our new expected range is $5.80 to $5.90 per diluted share. Our current expectation is that Idaho Power will use between $50 million and $60 million of additional tax credit amortization for the full year, a reduction from our estimate last quarter. So we were able to increase our earnings per share estimate for the year while decreasing our estimate of additional ADITC amortization, which is reflective of our strong operational performance this year. These estimates assume historically normal weather conditions and normal power supply expenses for the fourth quarter.

Now I'll turn the call over to Lisa.

Thanks, Amy, and thanks to everyone for joining us on the call. Let's start with a look at customer growth and economic expansion. As you can see on Slide 5, our customer base has grown 2.3% since last year's third quarter, including 2.5% for residential customers. We continue to see robust activity across several sectors, including manufacturing, food processing, distribution, warehousing and technology. Micron's 2 fab projects remain a cornerstone of our industrial engagement. The 2 fab expansion represents the largest private capital investment in Idaho's history and underscores our region's growing prominence in advanced manufacturing and technology.

In parallel, we're actively engaging with several Micron suppliers planning to establish operations in the Treasure Valley. Perpetual Resources, another new large customer recently achieved a significant milestone in its mining project by transitioning from permitting to development. The project broke ground earlier this month, marking a new phase in Idaho's mining sector.

We're also seeing increased momentum in agricultural-related projects in the southern part of our service area. These include cross-vent barnes, rotary milking parlors and biodigesters that will contribute to load growth while supporting energy production through renewable natural gas.

Our new large load pipeline remains very robust. As we've previously communicated, our load forecasting methodology remains conservative and disciplined. We don't include new large projects in our forecast until contracts for the procurement and construction are executed, which occurs after we've identified how to serve the customer. This approach ensures that only viable projects are reflected in our projections. Now the laws of physics are unyielding. So we are working hard on creative options to serve these new large loads while ensuring the system remains reliable and affordable.

As we work with these new loads, I want to emphasize Idaho Power's continued commitment to customer affordability. We work hard to keep our prices among the most affordable in the country. And according to national data compiled by the Edison Electric Institute, Idaho Power's customers' bills remain 20% to 30% lower than the national average. We strive to achieve a thoughtful balance between growth and affordability in part through the design of pricing and contractual provisions for new large load customers guided by a long-standing growth pace for growth philosophy.

As shown on Slide 6, our residential customer rates -- our residential customers' rate increases since 2014 are much lower than the national average and the steep increase in consumer price index in recent years.

Shifting gears and turning to Slide 7. We remain full speed ahead as we execute on key projects. Most notably, work is progressing quickly on the Boardman-to-Hemingway transmission line project. Several towers for that project are now complete. We're thrilled to have steel on the ground on this key resource for helping us access reliable, affordable energy in the Northwest. We continue working through the regulatory and permitting processes on the Gateway West and Swift North transmission lines, and we look forward to moving both of those projects into the construction phase, hopefully soon as they are necessary resources.

As I touched on during the last call, recent policy changes impacted the permitting of the 600-megawatt Jackalope Wind project that we plan to have in service by 2027. As a result, we terminated the agreements we had for that project, both the ownership and the power purchase components. With the wind project's agreements terminated, we're busy identifying power supply solutions to meet future load growth. These solutions could include short-term market purchases, natural gas projects and potentially additional solar and battery storage resources.

We're in a continuous state of planning and execution to affordably serve the growing demand with a reliable mix of generation resources. As described in our IRP, natural gas resources are a good operational fit for our system as well as a lease cost, lease risk resource. Idaho Power is planning a 167-megawatt expansion of the Bennett Mountain gas-fired power plant, which will help serve load during peak times. In September, we received a pre-permit to construct from the Idaho Department of Environmental Quality, which allows construction to begin. We've also submitted a certificate of public convenience and necessity for the project to the Idaho Commission. If approved, we expect to begin construction in the spring of 2026 and bring the project online in 2028.

As you can see on Slide 8, there's lots of work going on in the RFP space and lots more to come. The Bennett project is an important step in helping to solve our future power supply needs. We're continuing to work through the resource selection process, and we anticipate being able to provide some updates on additional selected generation projects on our year-end call, if not sooner.

The next 2 slides highlight the news in our pending Idaho General Rate Case. We recently reached a settlement with new rates designed to increase annual revenues by $110 million or 7.48% effective January 1. Additional details of the rate case settlement include a 9.6% ROE, a 7.41% overall rate of return and a $4.9 billion Idaho jurisdictional rate base, excluding coal plants that are under separate mechanisms. There were no capital disallowances in the settlement. Our ADITC mechanism remains in place with a $55 million annual cap for 2026 and thereafter. Also, all existing ADITCs not currently included in the mechanism and all investment tax credits generated through 2028 will be added to the mechanism.

We view the settlement as a constructive outcome that helps us continue to safely, reliably and affordably provide electric service to our growing service area. The settlement requires approval by the Idaho Public Utilities Commission. And based on prior cases, we expect the commission will issue an order on the settlement sometime in December.

Turning to Slide 11. We filed our 2026 Idaho Wildfire Mitigation plan with the Idaho Commission earlier this month. It's the first wildfire mitigation plan being filed pursuant to Idaho's new Wildfire Standard of Care Act and it outlines our proposed methods of mitigating wildfire risk and hardening our system. As a reminder, the Wildfire Standard of Care Act was signed into law earlier this year. The law empowers the Idaho Commission to set clear and consistent expectations for utilities wildfire mitigation efforts. Under the law, stated generally, utilities are assumed to be acting without negligence if they follow a commission-approved wildfire mitigation plan and provides up to 6 months for the Idaho Commission to review and approve the plan after it is filed.

So with that, I will turn the presentation over to Brian for a financial update.

Thanks, Lisa. Hi, everybody. I'm going to start today with the financial results on Slide 12. As you can see, IDACORP's net income increased $10.8 million for the third quarter of this year when compared with the third quarter last year. Just to summarize, that increase was mainly driven by higher retail revenues from the January rate change and from customer growth. On the other hand, we saw lower usage per customer, and that's because we're comparing to a very hot, very dry third quarter of last year. We also saw higher O&M expense and as expected, depreciation and interest expense increase from our continued build-out of the infrastructure to support the growth that Lisa talked about.

To add some detail on that, a net increase in retail revenues per megawatt hour increased operating income by $17.6 million on a relative basis, resulting mostly from the rate changes from the limited issue rate case Idaho Power filed last year. Our customer growth increased operating income by $7.8 million. That was the result of adding 15,000 customers over the last year. And although cooling degree days in Boise were 14% higher than normal, we saw an impact from a relative decrease in usage per customer of $5.7 million. That's not intuitive, when it was so warm this year, but it's because the third quarter last year was even more abnormally hot and dry, which affects the comparability.

Of the customer classes irrigation usage per customer decreased most significantly, with higher precipitation and lower temperatures during the quarter compared with the third quarter of last year.

Other O&M expenses were $4.2 million higher, that was driven by inflationary pressures on labor and professional services and some wildfire mitigation program and some related insurance expenses. As the system grows, we also expect to see higher O&M expenses to maintain an expanding system, the natural result of that growth. That said, we plan to keep our culture of measured and thoughtful spending fully intact as we go forward.

And depreciation expense increased $8.1 million quarter-over-quarter, again, as we expected from our infrastructure development and the placement of additional assets into service. Other net changes in operating revenues and expenses increased operating income by $4.3 million. This was due primarily to a decrease in net power supply expenses that weren't deferred through the power cost adjustment mechanisms. And then nonoperating expense increased $9.8 million from the third quarter on a net basis.

As we continue to grow, we continue to experience higher interest expense to finance it. Also, we had an increase in interest that Idaho Power is required to pay on transmission customer deposits. And as I noted on our Q2 call, a portion of our higher interest expense is driven by our new finance lease, related to a third-party energy storage agreement and that affects comparability as well. I think it's important to remember that the additional financing costs and the amortization related to that right-of-use lease asset is recovered as a pass-through cost and the power cost adjustment mechanism.

The increase in nonoperating expenses was partially offset by an increase in AFUDC, that's from higher average construction work in progress balances. Just as a barometer of how busy we've been as a company, our QIP balance was $1.6 billion at the end of the quarter. And at the same time, IDACORP's total assets went over $10 billion for the first time.

Income tax expense, in this case, excluding additional ADITC amortization under the mechanism decreased by $9.1 million. I'd attribute this mostly to annual income tax return adjustments and recurring regulatory flow-through tax items.

So to sum it up on financial results, it was a strong quarter, and it's been a strong year-to-date. And because of that, we've decreased our full year expectation of additional ADITC amortization, while at the same time raising our expectations on earnings for the year.

Now moving on to Slide 13, I'll talk about the cash side. Our operating cash flow through September were $464 million, which was $6 million higher than the comparative period last year. This continues the trend of steadily improving cash flows from our rate cases and operation of our mechanisms. At the end of September, the Idaho Commission approved our request for additional pre-collection of Hells Canyon AFUDC. On an annual basis, this will increase cash collection by about $30 million. Now there's no income statement impact from that, but it's positive on the cash side and it's beneficial for our credit metrics. We think the order demonstrates the Idaho Commission's intent to support the financial health of the company, and also a willingness to make decisions to help keep financing costs low for the benefit of our customers.

It was another busy quarter. The fourth quarter surely offers no reprieve. We're working through resource acquisitions, building infrastructure like the Bennett expansion and our major transmission projects, and undoubtedly other projects to meet load and reliability obligations and we're otherwise executing on our strategy. So we're hard at work. We're glad you're with us, and we're excited to share additional information on projects and the resulting in new CapEx expectations in the relative near term as soon as we have some.

I'd be remiss if I didn't mention that we're excited to see many of you at the EEI financial conference coming up in a little over a week. Lisa, Amy, John and I will all be there. And now over to John for an update on our 2025 guidance.

Thanks, Brian. Moving to Slide 14. You can see our updated 2025 full year earnings guidance and key operating metrics. This guidance assumes normal weather and normal power supply expenses for the rest of the year. Amy and Brian already mentioned this, but with continued positive operating results, we raised our guidance and now expect IDACORP's diluted earnings per share this year to be in the range of $5.80 to $5.90, with the assumption that Idaho Power will use $50 million to $60 million of additional investment tax credit amortization.

Our expectation for full year O&M expense increased to a range of $470 million to $480 million as we continue to experience inflationary pressures on labor and professional services, and added work on wildfire mitigation efforts. We still expect to spend between $1 billion and $1.1 billion on CapEx in 2025.

Finally, we still expect pretty good hydropower generation in 2025, though we've updated our range to 6.5 million to 7.0 million megawatt hours for the year.

With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question comes from the line of Bill Appicelli with UBS.

Just a question around the medium generation needs and some of the considerations you are making around the change with the wind farm. So can you just maybe remind us what was in the capital plan for Jackalope? And then what are the sort of potential solutions and the time line for that?

Well, I'll start. I'll have Brian go over the numbers. And certainly, as we shifted away from the wind project and we're reviewing what the opportunities are for replacement, we only have the really Bennett to talk about today, but it's worth noting that it was 600 megawatts of wind. So it won't be a megawatt per megawatt replacement. We do -- as I mentioned in my comments, gas is showing up in our IRP and we are certainly looking at those options as well as others as we work our way through the RFP process. So do you want to talk about what was in the budget, Brian?

Sure, Bill. So one thing I'll mention about the Jackalope Wind project is that the spend for that project was consolidated in the years 2026 and 2027. So when you look at our capital stack, that's where you'll see the generation resource for that. Now 300 megawatts of that was owned, 300 megawatts was PPA. We don't have the exact number to give you in terms of the cost because it's competitive information. But I will say that if you use typical wind pricing on a 300-megawatt project, there's also some interconnection costs associated with that, that given the location were relatively high.

Though it was a pretty significant piece of capital in our stack, but as we're looking to the future, I think there's some other pretty significant bias to the upside on capital from some of the other resources that might be coming out of the RFP process.

Just so I'm going to have Adam just give a little highlight on the RFP process.

Yes. So we're still working through the 2028 and 2029 RFP processes. Just as a reminder, the 2028 process, Idaho Power has 3 projects on that final shortlist. On the 2029 shortlist, we have 4 projects, Lisa mentioned the Bennett Project. So we're going to continue to work through those to see how to replace that capacity in 600 megawatts, but Jackalope was mainly an energy resource for us. The effective load carrying capability was about 90 megawatts. So that's what you'll see us try to replace from a capacity perspective. Lisa also mentioned the IRP shows gas in the future in 2029 and 2030. There was only 1 gas bid that made the 2029 RFP. So we'll have to consider other options there as well as we evaluate our future in the gas space.

Okay. And then was the Bennett project in the capital stack, Brian, in February or now?

We had a resource that was in there somewhat as a proxy in the most recent capital update that we gave, but it's not a full reflection of the '28, '29 RFPs.

Okay. And then just my only other question was just around customer growth trends. It seems like that's not an issue based on the amount of growth that you guys are talking about. But I just did note that the 12-month trailing did tick down a little bit. Any color there or just thoughts on those trends moving forward?

Are you talking about the load growth or the actual?

Sorry, the customer growth, yes, the actual that you cite there, I think it was 2.3% year-over-year on a trailing 12-month basis. I think that had been a little bit less, and that was 2.5%, so?

Yes. I think those have been pretty much...

We've been consistent kind of in the -- this is Adam, the 2.3%, 2.4%. That's meter growth. That's per customer or customer meters, really where we're going to see and continue to see more substantial growth is in the manufacturing area, and we expect that to happen here and ramp up over the next couple of years.

Right. And just to sort of put a finer point on it, too, that prospectively, we're looking at around 8.3% growth overall.

Right, in terms of total load growth, right?

Yes. And that's each year over the next 5.

Bill, I want to go back to your question on the -- on whether or not the gas plant was included in the capital stack. So if you go back to February, we didn't have a CPCN on that and the RFP wasn't known. So that project is actually -- is an incremental add since then. So you take the wind out and the 167 megawatts Bennett project is actually an incremental add.

And then we'll expect additional adds beyond that in the future.

Your next question comes from the line of Chris Ellinghaus with Siebert Williams Shank.

So residential customer growth slowed sequentially from the last few quarters. Is that telling us anything about sort of how the ramping of staffing of the new customer loads is going? Or is that telling us anything about some slower economy overall? Is that like the labor market has slowed a little bit. What can you say about that?

Well, certainly, on the large loads, I mean, right now, it's mostly construction personnel that are there. So I can't really say too much about what their final load growth will be. But I think the interest rates have impact. I think where you are in the year has impact in terms of people's ability and willingness to move. And I do think there probably is a little bit of softening in the economy, just given so much of the uncertainty out there. But there's not really any big trend that we're seeing that we're concerned about.

Okay. The sales growth for the quarter was actually, I thought, a little surprisingly good despite the usage impact. Is that just sort of the year-over-year progression of customer growth? Or are there other factors there, given cooling degree days were down double digits. So to have your sales level be up as much as it was on the residential and commercial side may be a little surprising. Have you got any thoughts there?

Yes. I mean I think it does speak to growth. Weather was a little wonky this year. So I think that kind of had us kind of dampened some of it, but yes, I think I would point to growth mostly.

Yes. Chris, this is Adam. It's been interesting looking at the operational side. Every single day, we look at the load and where it's going versus the temperatures and I think if you ask our operators, they would say they definitely noticed kind of an uptick even when the weather maybe wasn't as strong this year. So when I see that every single day, I view it is we're starting to see the manufacturing load increase. A lot of the projects -- there are large projects are starting to get construction power. We're starting to see that come through our loads. So I thought it was a pretty positive year when you consider the weather that we had. I agree with you.

Can you say the same about irrigation? I really kind of thought it might be even lower given what the weather was, particularly sort of the way that precipitation fell during the quarter. So was there something going on with ag where it was particularly strong to keep irrigation as high as it was?

Well, I think that the way that the spring and summer started, it was quite warm and dry. So I think we've got a good bump there. And then of course, it rained on the 4th of July, we had rain in August. It was -- it never really got miserably hot for extended periods of time, which often is where you see some of those super peaks show up. But overall, what we're projecting for the year, it is slightly up over last year, even though it sort of not -- doesn't have the historic shape as you go through the year. Anything you would add, Adam?

Maybe I'll just hit the kind of boots on ground perspective. And then, Brian, I know you have some numbers on it. Talking to our ag reps, they kind of have said that the demand has been pretty strong. It's been pretty steady. So that -- I think that's what we expected going into the year based on our conversations with farmers, and I think that's what we ended up seeing as a pretty steady amount of energy used throughout the year. Ebbs and flows, Brian, I know you have the numbers, but it was -- the demand was strong.

Yes. And this is Brian. If you look at just the third quarter, a modest downtick in irrigation loads. But if you look at the 9 months -- the first 9 months of the year, kind of a modest increase, right, that you see overall. So June usage was high both years. June 2025 didn't have precept, right? And that's a big driver. It turns out the amount of precipitation not just the temperature. We saw an uptick in precipitation actually, in the third quarter, but nonetheless, still has a pretty strong quarter for irrigation.

Okay. Lastly, if I recall correctly in the IRP with the preferred portfolio, I think you had a scenario in there with reduced renewables, probably in anticipation of the Jackalope issue. And if I recall correctly, sort of gas was next up in the queue there. Is that kind of what you're thinking? And given the sort of RFP results, do you anticipate sort of opening that up at all to see if there's additional interest, given the sort of gas environment that we see ourselves in today?

Well, certainly, with a lot of the policy changes, that has changed the economics of renewables for sure. So that has an impact in how those inputs go into the model. And we'll see sort of what -- on the short-listed projects, their ability to meet the terms that they were selected on given those changes in policy. Anything you would add...

Chris, maybe I'll just add, you're right. 2029 had a gas plant, 2030 had a gas plant. If you look at our 2029 RFP, and it was actually 2029 and later, there was only 1 gas plant that was part of that RFP. So just by virtue of seeing what's lease costs, lease risk in our resource portfolios, we're going to have to start looking to see what might exist beyond the RFPs in that 2030 range.

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

It's Brian Russo on for Julien. I think you may have just answered my question, but I'll just ask it again anyway. Given that you're really the only bidder of gas generation in the RFPs, is there an alternative to the RFPs to expedite the process, considering the long lead time to secure turbines, et cetera, and given the profile of your customer and the demand that you need to meet as we move towards the end of the decade. I was just curious if that was even considered?

Well, we're certainly considering all options, and there's -- it's just an incredibly dynamic environment from which to try to plan and execute quickly. So we will report back to everyone next quarter when we have a little more insight as to what those alternatives will be.

Okay. Great. And then I think given that you can only get Bennett in service by 2028, right, that's a year after, you were hoping to have the Jackalope capacity. And you mentioned 3 alternative short-term purchases, I think the second one was gas and the third was solar and battery storage. I suppose that your preferred choice is to own something, but it doesn't seem realistic to own any gas generation that soon. So with solar or battery storage, be kind of the next preferred scenario to replace Jackalope?

Well, I mean, we're -- again, we're looking at all options to see what can we actually get as quickly as we need. So I don't know that we have more than that to really say about it today. Is there anything that you'd add?

Brian, this is Adam. I mean, I think you're right. You're seeing a gap there. And certainly, we have a couple of PPA projects that were going to help fill that gap. But to your point, we've got to start considering what other options exist because what the IRP is showing is it's most cost effective right now to go forward with a gas facility. So we are taking a look at that, and hopefully, we'll be able to update you next quarter.

Yes. And to just add too, our transmission projects also help get us to market to bring resources in. So those are also important.

And on those, just quickly as a reminder, 2027 is the in-service date for B2H. So that's pretty significant. We will bring resources in using that resource. And then 2028, we have both the Southwest Intertie project down south and a portion of Gateway West. So when you look at '27 and '28 from a CapEx perspective, they're going to be pretty busy setting aside the generation side of things.

And I guess I'd just tie it up and just remind you that certainly, we have our obligation to serve, and we do also procure those resources competitively. So that doesn't change.

Your next question comes from the line of David Arcaro with Morgan Stanley.

This is [ Alex Herman ] on for Dave. Could you talk about the priorities for your next rate case and especially related to potential tracking mechanisms. How important is that to your plan? And how do you see the regulatory support for that in Idaho?

I just want to make sure that I heard the whole question. So we are very sensitive about rate cases. We want to make sure that we're being careful about meeting our obligation to serve, but also keeping rates as affordable as possible. And so with -- as we go through time, we evaluate each subsequent rate case and based on the need for what we're spending and if we can cover that with revenues that kind of growth. So it really is a very dynamic calculation as we go through time. We want to make sure that we maintain our financial health as we go through this extraordinary period of growth. But certainly, rates are -- rate cases are part of that calculation as we go through time. Is there anything, Tim, that you would add?

Yes. Thanks for the question, Alex. It's a great one. We just filed our 2025 general rate case settlement stipulation last week. Timely question. I've met with a few folks this morning to start talking about it. And we are working on trying to assess the timing and need of our next case and what elements might be included, whether it's a traditional case, whether it's a case that has a tracker, all of that's on the table at this point. But the plan is in development and in early stages. So we'll have to report back more later.

Got it. No, very clear. And then shifting to the earnings outflow going forward. As our new large load customers start to come online, do you think you could earn an ROE above the minimum level of 9.12%?

Yes, Alex, this is Brian. So at some point along the way, yes, there's a convergence of just revenues coming in from customers that caused our earned ROE to increase above the 9.12% level. In fact, that's what we've been looking to do is increase the ROE every year. We've done that with cases over the last few years. We have removed some element of regulatory lag by doing that and eventually hope that the magnitude of frequency of cases would decline and the revenues from large load customers would, in fact, come in and cover the infrastructure that -- that's being developed for them.

So those large load, large volume customers pay for their share and that, therefore, would reduce the need for rate cases, and still allow earning at or above that 9.12% floor and then not needing ADITC support.

Your next question comes from the line of Anthony Crowdell with Mizuho.

I just want to follow up on one of the Bill Appicelli's question on the Jackalope project, the loss of 300 megawatts, I guess, in your capital plan, I know you talked about the transmission and maybe you'll meet the generation need. But is there offsetting CapEx that goes into your forecast? Or should we expect a dip from what you previously thought 2027 was going to be now that Jackalope is being canceled?

Yes, great question, Anthony. So we typically update our capital forecast every February on the Q4 call. The last couple of years, we've done an interim update just based on the outcome of RFPs and resource procurement. I think you should expect us to do that potentially this time as well. I mean we've talked about the Bennett plant, but that is an inadequate resource to cover the load growth that we have going forward, even for just the customers we've announced so far, the ones that are in the construction phase or that have executed agreements with us. There are incremental generation requirements in there, and they are not reflected yet in the capital stack. But as we solidify those, we will add those to the capital stack.

You'll see Jackalope come out, you'll see Bennett go in. And then by the time we get to that update, I would expect to see incremental resources in there as well as project costs and timing adjustments that we typically include in our annual update. So that may be in the Q4 call, it may actually be sooner that you see some of that coming to fruition possibly as early as this year, starting to see some incremental generation resources being added depending on the outcome of our processes.

The driver that we would see in the update in 2025, is it approval of the settlement? Or is it something else that would cause us to see in '25?

No. It's just getting through the procurement process. Sometimes that can be a relatively lengthy process and it is a competitive process. So identifying whether or not we've been the successful bidder, negotiating with the actual suppliers and vendors and ensuring we can meet time lines are all factors that go into whether or not that will be a 2025 announcement or not. And it's also a confidential process that we have as we negotiate with those vendors.

So there's not much we can release until we've gotten to a point where we're very comfortable in the fact that is a winning project. And then we'll announce what it is and magnitude and add it to the capital stack.

Great. And when do you expect approval of the settlement, I apologize if you've already put it in the 8-K on when the commission would vote on it?

Yes, we're expecting that sometime in December as they have done historically, so probably late December.

Great. And then lastly, Brian, you talked about, I guess, you're carrying a QIP balance of $1 billion. I believe Moody's has you on a negative outlook for your rating. Do you plan on working down that QIP balance in '26 or it stays at that level? And with the negative outlook and that large QIP balance that maybe accelerates equity needs?

Actually, I would think the equity need would go the other direction in the near term, Anthony. And the reason for that was I mentioned the Jackalope Wind project had 2 large payment obligations in 2026 and 2027. As we look at removing that and replacing it with potentially more traditional timing of payment like for a gas plant, for example, those tend to be spread out longer and that can actually reduce our near-term equity need by pushing out the capital requirements until further in our 5-year window. So we can see a reduction in near-term equity and overall equity just as a result of the payment timing for CapEx.

On the credit metrics side, we did have this rate case outcome. We do believe it to be -- the settlement is a balanced settlement certainly and constructive, but it does help on the credit rating side as does the outcome of the Hells Canyon AFUDC case. So we see ourselves naturally progressing out of being near the threshold for both Moody's and S&P without having to issue incremental equity in the near term.

[Operator Instructions] That concludes the question-and-answer session for today. Lisa, I will turn the conference back to you.

All right. Well, thank you very much for everyone for joining us today, and I hope you all have your Halloween costumes picked out and that you have a very safe and happy Halloween. So thank you.

That concludes our conference for today. You may now disconnect. Thank you, and have a great day.

Welcome to IDACORP's Second Quarter 2025 Earnings Conference Call. Today's call is being recorded, and our webcast is live. A replay will be available later today and for the next 12 months on the IDACORP website. [Operator Instructions] I will now turn the call over to Amy Shaw, Vice President of Finance, Compliance and Risk.

Thank you. Good afternoon, everyone. We appreciate you joining our call. The slides we'll reference during today's call are available on IDACORP's website. As noted on Slide 2, our discussion today includes forward-looking statements, including earnings guidance, spending forecast, financing plans, regulatory plans and actions and estimates and assumptions that reflect our current views on what the future holds, all of which are subject to risks and uncertainties. These risks and uncertainties may cause actual results to differ materially from statements made today, and we caution against placing undue reliance on any forward-looking statements.

We've included our cautionary note on forward-looking statements and various risk factors in more detail for your review in our filings with the Securities and Exchange Commission. As shown on Slide 3, we also have Lisa Grow, President and CEO; Brian Buckham, SVP, CFO and Treasurer; and John Wonderlich, Investor Relations Manager, presenting today. Slide 4 has a summary of our second quarter results. IDACORP's diluted earnings per share were $1.76 compared with $1.71 for last year's second quarter. In the second quarter of this year, we recorded $17.2 million of additional tax credit amortization under the Idaho regulatory mechanism compared with $7.5 million in the second quarter of last year.

For the first half of 2025, diluted earnings per share were $2.87 versus $2.67 in 2024. Those results include additional tax credit amortization of $36.5 million in the first half of 2025 versus $20 million in the first half of last year. For our key operating metrics, we're raising the lower end of our full year IDACORP diluted earnings per share guidance by $0.05 to the new range of $5.70 to $5.85. This increase was driven by strong operational results in the second quarter, and it includes our expectation that Idaho Power will use between $60 million and $77 million of additional tax credit amortization for the full year. These estimates also assume historically normal weather conditions and normal power supply expenses for the rest of the year.

Now I'll turn the call over to Lisa.

Thank you, Amy, and thanks to all of you for joining us today. I'll start with a look at the continued customer growth across our service area, which we've summarized on Slide 5. Idaho Power's customer base has grown 2.5% since last year's second quarter, including 2.7% for residential customers. We saw several significant new customer investments in the technology, food processing, mining and distribution warehousing sectors during the first half of the year. I talked about some of those on our first quarter call. The most notable new one I'll highlight is Micron's June announcement of a second high-volume fabrication plant in Boise, adding to the first fab already under construction.

We expect that second fab facility will be about the same size as the first fab. We've included a recent photo of the construction progress of the first fab on Slide 6, so you can see the scale of that project. We have served Micron since its inception, and we're excited for them and the opportunities that this expansion creates for our region. We're already working with the Micron team to determine how we'll serve the expanded project. Valor C3 data centers also announced an expansion at a second location in Boise, and Tesla has energized 6 new large electric vehicle fast charging stations throughout Idaho Power service area. While growth is already robust, we continue to field and thoughtfully process requests from businesses looking to locate and expand within our service area.

The pipeline of prospective customers on our list exceeds our all-time peak load of around 3,800 megawatts. While we don't expect all of those customers to materialize in the near term, those prospective customers would be incremental to the load growth rate that we included in our recently filed IRP. And they give us visibility on incremental load growth well into the 2030s. Also, the infrastructure and resources needed to serve those prospective customers is not yet in our CapEx plans. We're strong advocates that growth has to be sustainable and responsible and that service to our existing customers must remain reliable and affordable.

So any new agreements with large load customers will include the appropriate time frames needed for build-out and ramp-up as well as appropriate cost allocation just as we've done in recent large load special contracts. Turning to Slide 7. I'll provide some updates on what we're building to meet this historic demand. In June, we broke ground on the Boardman to Hemingway transmission line, a key resource we've been working hard for nearly 19 years to make a reality. We also recently brought a company-owned 80-megawatt battery project online, along with the batteries for a 150-megawatt energy storage agreement.

For the Gateway West and Swift North transmission lines, which will join Boardman to Hemingway as major energy highways across the Western U.S., we're working through the remaining regulatory and permitting processes to get to construction. Recent legislation and executive orders have introduced new hurdles and some uncertainty around the constructability of renewable projects. So we've been working with our counterparty on the Jackalope Wind project in Wyoming to assess the impact of these federal actions. In addition to permitting, there are other conditions that still need to be satisfied to move forward with the project. This project would provide both energy and capacity that we need to serve load growth.

So if ultimately, the project doesn't move ahead, we are identifying alternative capacity and energy resources. With a dynamic environment, remaining flexible and planning ahead is key. In other developments related to resources, we recently filed our 2025 IRP. On Slide 8, you can see a key takeaway from this 20-year plan is that our IRP recommends more gas-fired resources, which are needed to provide additional system flexibility and dispatchable capacity. These gas assets would complement our existing diverse resource portfolio.

Remember that the IRP is a fixed point in time, and it assumes that current laws like the Clean Air Act Section 111D continue into the future. If those rules change, the portfolio could also change. Like I said, things are very dynamic. Also, it's important to remember that we issue RFPs for resources. And what we're looking for as we plan for the future is the least cost, least risk resources that are viable and meet the capacity and energy deficits we see in our future. Often through that RFP process, those resources are ultimately different than what our IRP shows.

On Slide 9, you can see the significant load growth the 2025 IRP forecasted between 2025 and the early 2030s. As I mentioned, our 5-year growth rate has increased notably in each of the last 3 IRPs, and Micron second fab wasn't included in this one. So we're quite possibly underestimating load growth in our 2025 IRP. On a related note, turning to Slide 10, we filed our 2029 RFP final shortlist in July for Oregon PUC acknowledgment. As a reminder, the Oregon PUC acknowledged the 2028 RFP final shortlist last quarter, and it has a mix of renewable projects. For resources in both RFPs, some of the listed projects would be owned by Idaho Power and some would have third-party ownership.

We continue to make progress on contract negotiations. We'll be working with the bidders to help understand the impact of recent federal legislation, tariffs and executive orders on their projects as we focus on identifying the least cost, least risk resources from those RFPs. I think the most notable is the 167-megawatt Idaho Power-owned gas plant shown as the top project on the short list for the 2029 RFP, which would provide us with greater certainty on a high capacity factor relative to the other listed projects.

Turning to regulatory matters on Slide 11. Idaho Power filed a general rate case in Idaho at the end of May. The regulatory process for that case is underway, and we expect new rates to go into effect at the beginning of next year. This request is a full general rate case filing similar to our 2023 Idaho rate case, and it requests an overall rate increase of about $199 million for Idaho customers. We're requesting a 51% equity ratio, a 10.4% ROE and additional ADITCs to be added to our regulatory mechanism, along with a depreciation and interest expense tracker.

Brian will talk more about the case in his comments, and I will hand it over to him now.

Thanks, Lisa. Hi, everybody. I'm going to start on Slide 12 today. And as the table shows, IDACORP's net income increased $6.3 million for the second quarter this year compared with the second quarter last year. The major drivers for the quarter were higher retail revenues from the January 1 rate change, customer growth, higher customer usage due to warm and dry weather and then recording incremental tax credits this year under the Idaho regulatory mechanism. No surprise, those benefits were partially offset by higher depreciation and interest expense from our infrastructure projects.

We also had higher O&M expense in large part from labor cost increases, but I'd say we're still on track with our O&M guidance for the year. A little more detail on the drivers. Net increase in retail revenues per megawatt hour increased operating income by $8.8 million on a relative basis. That benefit was mostly from the increase in Idaho base rates from the limited issue rate case that Idaho Power filed last year. Customer growth increased operating income by $6 million quarter-over-quarter. Usage per retail customer was a benefit of $5.5 million.

Cooling degree days were 49% higher than normal, which was only slightly higher than the warmer-than-normal second quarter last year. But precipitation was particularly low in the second quarter this year. So our irrigation customers use more energy to operate irrigation pumps despite the comparable temperatures year-over-year. Other O&M expenses were $11.1 million higher. I already mentioned the higher labor costs, but there were some wildfire mitigation program and some related insurance expenses included in the mix of higher costs as well.

And consistent with the trend we've seen over the past several quarters from continued and accelerated capital investment, depreciation expense increased $6.4 million quarter-over-quarter. The other net changes in operating revenues and expenses decreased operating income by $5.6 million. We expected this. It was mostly due to the timing of recording and adjusting regulatory accruals and deferrals in the second quarter last year that didn't recur in this year's second quarter.

Net nonoperating expense increased $7 million in the second quarter. Interest on higher long-term debt balances needed to finance our growth and also an increase in interest that Idaho Power is required to pay on transmission customer deposits, both contributed to the increase. There's one new factor this year on the nonoperating expense side that you might have noticed in the 10-Q, if you've gotten to it yet. In May, our first battery project subject to a third-party energy storage agreement started operations. That triggered the beginning of our finance lease accounting for the project, and this resulted in higher interest expense and amortization of the right-of-use asset.

From a financial results perspective, this item is a pass-through in our power cost adjustment mechanism in Idaho, but I wanted to call it out because you'll see the various lease accounting entries in the financial statements for the first time. It's not bad. It's just different. The increases in nonoperating expenses were partially offset by an increase in AFUDC because the average construction work in progress balance was higher. QIP was a fairly staggering $1.4 billion at quarter end. Also, we saw higher interest income due to higher cash balances in the second quarter this year.

The decrease in income tax expense was mostly the result of an increase in additional ADITC amortization and some variances in flow-through tax adjustments. Based on our current expectations of full year financial results, Idaho Power reported $17.2 million of additional ADITC amortization like Amy noted earlier, compared with $7.5 million in the second quarter last year. Remember, we record the ADITCs ratably each quarter based on our full year expectation of financial results. Moving on to Slide 13. I want to touch on our recent equity transaction. In early May, we entered into forward sale agreements to sell $575 million in gross amount of IDACORP stock through a discrete follow-on offering.

Combining the future net proceeds from that offering with $145 million of forward sale agreements we executed through our ATM program in the fourth quarter last year and in the first quarter of this year, we expect to be able to fund our equity needs into 2027 based on our current CapEx plan and the anticipated timing of our spend. Lisa mentioned new customers, and she mentioned the pending RFPs. So there's certainly pressure to the upside on incremental CapEx, and that can impact our plans. But in any event, we haven't taken down any of the ATM shares or any of the shares from the follow-on offering to date. So those are all available and they aren't shown as equity in our capital ratio right now.

We're committed to maintaining a 50-50 debt-to-equity ratio at Idaho Power, and our equity forward transactions help make that achievable over the longer term. We're excited to have the follow-on transaction completed with a solid outcome, and it had very high receptivity. So I'd just say that we appreciate our owners' continued support and confidence, and we are, of course, committed to the thoughtful drawdown and the investment of the capital as we execute on our infrastructure work. Also related to liquidity, our operating cash flows for the first half of 2025 were $301 million, which was $45 million higher than the first half of last year.

So more good news on that front. Lastly for me, Lisa gave the highlights on our general rate case. We're looking to add nearly $1 billion of rate base through the case, which is reflecting the investments we've made in our system for reliability and to address economic growth. And that's a notable amount, but it's otherwise a relatively standard general rate case for us in most respects. We're asking for our typical historic test year treatment, but with known and measurable adjustments and annualizing adjustments on larger capital projects for period-end rate base treatment like we received in our 2023 general rate case.

But because of the notable regulatory lag that inevitably results from that historic test year approach, we also requested in our case, a new to us depreciation and interest expense tracking mechanism. That mechanism would help to reduce the substantial amount of regulatory lag we're experiencing as we move through this period of heightened capital investment. Just stated generally, the mechanism would measure the difference between actual depreciation and interest expense and a sales adjusted baseline level of depreciation and interest expense on a calendar year basis starting in 2026. It would have both a forecast and true-up component like our PCA and rates would adjust at the same time as the PCA rates.

So if it's approved, we expect the mechanism would help address regulatory lag and benefit both our earnings and our credit metrics and help keep financing costs at an acceptable level, ultimately benefiting our customers as well. We also asked in our filing for authority to incorporate additional ADITCs in the tax credit regulatory mechanism. We ask that all existing ADITCs on the books that are not already authorized for inclusion in the tax credit mechanism plus all the ITCs we earn through 2028 be included. We, as of now, estimate the amount of those credits is around $200 million.

That's incremental to the $77 million already included in the mechanism. And we also asked for a usage cap of $75 million of ADITCs in any single year. So it was a busy quarter. We're growing, and we're executing on our financing, regulatory and capital investment plans to support our growth. We're glad you're with us while we move ahead.

And with that, I'll turn it over to John for an update on our 2025 guidance and some metrics.

Thanks, Brian. Moving to Slide 14, you can see our updated 2025 full year earnings guidance and key operating metrics. This guidance assumes normal weather and normal power supply expenses for the rest of the year. We raised our lower end of our guidance and now expect IDACORP's diluted earnings per share this year to be in the range of $5.70 to $5.85. With the assumption that Idaho Power will use $60 million to $77 million of additional investment tax credit amortization. Our expectation for full year O&M expense continues to be in the range of $465 million to $475 million. We still anticipate spending between $1 billion and $1.1 billion on CapEx in 2025.

Although it is important to note that we have not adjusted our forecast for tariffs, given the volatility in amounts, and we continue to evaluate and monitor that situation. Finally, we still expect good hydropower generation in 2025, though we have updated our range to 7 million to 8 million-megawatt hours for the year, the dry June weather was the largest driver of the reduction to the high end. With that, we're happy to address any questions you might have.

[Operator Instructions] Your first question is from the line of Chris Ellinghaus with Siebert Williams Shank.

I think the number you quoted is 3,800 megawatts in the pipeline. A, can you talk about how many potential connections that is? And secondly, I'm not sure if you mentioned this, but was any of that in the IRP numbers?

So I don't have the number of exact projects that, that amounts to and it's actually more than our peak load, but kind of around that number. So it's mostly data centers that are in that pipeline, although there are smaller projects in there as well. So the DAC number I don't have on the top of some of the head.

Don't have the exact number, Chris, this is I think 1 of the data centers is included, but it's beyond the 5-year window mostly. And so you won't see that loan included in the IRP forecast of the 8.3% that you guys have.

And Chris, this is Brian. I'll say when we do our load forecasting for the IRP, we always assume some amount of commercial and industrial growth -- some of those customers are the ones that are on the pipeline list, but I would say it's a relatively small growth rate compared to what it would look like when you add some of the larger customers from that pipeline going forward.

Okay. Lisa, you also sort of addressed this where you might be conservative in the IRP. Are you kind of thinking at this point, looking at Slide 5, which shows sort of the progression of your retail sales forecast growth? Are you thinking that it's conceivable that you could have another step-up in the 2027 IRP that's kind of comparable to what we've been seeing in the progression?

Yes, I think that's a fair assumption, Chris. And I'll say, I've said on several of these calls, the IRP process, we sort of published a study every 2 years, but these are studies we essentially do with every large log customer that comes in, which is quite frequent. So just given that when you do the IRP process, you have to sort of lock down the number you're going to use in the study. And meanwhile, the economic activity continues. So a long-winded way of saying that, yes, it could very well be higher in a similar amount.

And Chris, maybe I'll add to that. This is Adam. Just to give you 1 stat line on that front. Our large load requests this year inquiries increased right around 30% compared to the year before, the year before was a relatively strong year in terms of inquiries and interest. So we're seeing continued interest in our service territory moving forward.

Okay. That's great. So looking at Slide 8, I looked at this preferred portfolio for a long time when it came out. And you mentioned the tax bill and how that may complicate things. It certainly looks today like you've got an awful lot that's affected in solar wins maybe not the best column, but are you currently thinking today that you're going to need to upsize and pull forward more of the gas expectation given what the tax bill looks like?

That's certainly some of the scenarios that we're analyzing.

And lastly, I guess, I haven't seen it yet, but do you have any idea when you'll get a procedural schedule on the rate case?

Tim, do you want to take that one?

Sure. Chris, this is Tim Tatum.Yes, we've been working on the procedural schedule with the parties and staff. I would expect it in the coming weeks, maybe even as early as next week. We're close. We're not all the way there yet.

Okay. One maybe 1 more thing, Brian. Can you give us any kind of color on what the irrigation impact look like in the second quarter?

I can give you a little bit on that, Chris. It was pretty significant. Last year, we had a really strong irrigation season in the second quarter. That was fueled by high temperatures. This quarter, we have continued high temperatures relative to normal. What we saw this quarter, though, was very low precipitation across our service territory.

And it turns out irrigation load is sensitive to heat, certainly, but it's also very sensitive to precipitation levels. And we saw that this year. If you look at actual sales year-over-year, year-to-date, it's been about a 15% increase in irrigation. If you look at on a weather-adjusted basis, it's relatively flat. It's a slight increase over last year. So very, very weather-sensitive. And remember, on irrigation, we don't have mechanisms like an FCA that adjust for that. Those types of sales.

[Operator Instructions] Your next question is from the line of Julien Dumoulin-Smith for Jefferies.

It's Brian Russo on for Julien. Just on you mentioned the Micron Phase 2. It's great to hear. It could be the same size as the first phase still under construction. And I think according to the tariffs, ultimately, the first phase is 500 megawatts. What kind of time line do you see unfolding here?

I suppose you're just going to want to start construction of Phase II, maybe even before Phase I ends, right, to keep the continuity of the EPCs, et cetera. Just any thoughts there? And I would imagine that would correlate to 1 of the upside scenarios in the 2025 IRP.

Yes. On the second part of your question, it would be upside. And so the first part, we're just working through those details with Micron. So we're not really able to speak to the amount of timing but it is underway. And as soon as we have information we can share, we will. .

Okay. Great. And just to clarify, the '28 and '29 RFPs that you show in the slide, in theory, that's based off of your '23 IRP, right? So the way to look at it is whatever is in the 2025 IRP just subtract what we see here on Slide 10, and that's what will be incremental in any sort of follow-up RFP.

I'm not sure if the math is that simple, just given how many moving parts are, but what would you say, Adam?

Yes. Typically, the way it goes is we set out we get the projects that come in as we're evaluating those projects, we're also evaluating the load in the knee. And so that can ebb and flow given what we need at the exact time that the RFP is out. So this is just the list of the projects that were shortlisted that responded to our RFP request, and we would have to decide how many of those projects we actually pick that meet the current needs that exist at that time. Does that make sense, Brian? .

Yes, it does. So for example, 160 megawatts self-build gas plant that you referenced in the '29 RFP shortlist that kind of correlates to what you have on Slide 8, 2029, 150 megawatts at new gas but I suppose you'll need an RFP for 2030 for 300 megawatts of new gas. Is that the simplistic way of looking at it.

Yes. I think that's 1 way to look at it. Maybe another way, Brian, is just in terms of the next 5 years, our need in megawatts of perfect capacity. So that's the resources maybe now renewable that can give you everything you need at that moment is about a little over 200 megawatts a year, every single year. based on the 2025 IRP. Now when we decide which projects we're going to pick related to the 2028, 2029 RFP, we will continue to look at that load forecast see if it's changed. But in terms of the 2025 IRP, it's a little over 200 megawatts of perfect capacity every year, which could be hundreds of megawatts in renewables or even a little bit less in natural gas, but that's kind of how it works as we move forward and work on these different projects. .

Okay. Great. And then just lastly, you mentioned some issues with the Jakait wind farm, it's a pull-on transfer, right? And I think it's for 2027 needs conceptually if that's facing economic issues with the tax bill, et cetera, could you just shift to gas?

This is Adam. That is absolutely 1 option. I think on [indiscernible] really looking at the permitting potential permitting issues related to the executive orders that are out there. If we did not build Jackalope, Certainly, 1 of the things we have and we'll continue to look at is gas bills in that time line. .

That concludes the question-and-answer session for today. Ms. Grow, you will turn the call back to you.

Well, thanks again to everyone for joining us today, and we thank you for your continued interest in IDACORP, and I wish you all a good evening. Thank you.

This concludes today's call. Thank you for joining. You may now disconnect your lines.